KINDER MORGAN, INC. - Quarter Report: 2017 June (Form 10-Q)

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 June 30, 2017

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 Web site, 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, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one): Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company o Emerging Growth Company o

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. 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 July 20, 2017, the registrant had 2,233,227,311 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS



		Page Number
	Glossary	2
	Information Regarding Forward-Looking Statements	3

	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2017 and 2016	4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2017 and 2016	5
	Consolidated Balance Sheets - June 30, 2017 and December 31, 2016	6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2017 and 2016	7
	Consolidated Statements of Stockholders’ Equity - Six Months Ended June 30, 2017 and 2016	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	42
	Results of Operations	42
	Liquidity and Capital Resources	55

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	59

Item 4.	Controls and Procedures	59

	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	60

Item 1A.	Risk Factors	60

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	60

Item 3.	Defaults Upon Senior Securities	60

Item 4.	Mine Safety Disclosures	60

Item 5.	Other Information	60

Item 6.	Exhibits	61

	Signature	62

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.	KML	=	Kinder Morgan Canada Limited and its majority-
Elba Express	=	Elba Express Company, L.L.C.			owned and/or controlled subsidiaries
EPB	=	El Paso Pipeline Partners, L.P. and its majority-	KMLT	=	Kinder Morgan Liquid Terminals, LLC
		owned and controlled subsidiaries	KMP	=	Kinder Morgan Energy Partners, L.P. and its
EPNG	=	El Paso Natural Gas Company, L.L.C.			majority-owned and controlled subsidiaries
Hiland	=	Hiland Partners, LP	KMR	=	Kinder Morgan Management, LLC
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	SFPP	=	SFPP, L.P.
KMEP	=	Kinder Morgan Energy Partners, L.P.	SLNG	=	Southern LNG Company, L.L.C.
KMGP	=	Kinder Morgan G.P., Inc.	SNG	=	Southern Natural Gas Company, L.L.C.
			TGP	=	Tennessee Gas Pipeline Company, L.L.C.

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

Common Industry and Other Terms
/d	=	per day	EPA	=	United States Environmental Protection Agency
BBtu	=	billion British Thermal Units	FASB	=	Financial Accounting Standards Board
Bcf	=	billion cubic feet	FERC	=	Federal Energy Regulatory Commission
CERCLA	=	Comprehensive Environmental Response,	GAAP	=	United States Generally Accepted Accounting
		Compensation and Liability Act			Principles
C$	=	Canadian dollars	IPO	=	Initial Public Offering
CO₂	=	carbon dioxide or our CO₂ business segment	LLC	=	limited liability company
DCF	=	distributable cash flow	MBbl	=	thousand barrels
DD&A	=	depreciation, depletion and amortization	MMBbl	=	million barrels
EBDA	=	earnings before depreciation, depletion and	NGL	=	natural gas liquids
		amortization expenses, including amortization of	OTC	=	over-the-counter
		excess cost of equity investments



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

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, 2016 (2016 Form 10-K) 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.

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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Revenues
Natural gas sales	$	758		$	478		$	1,567		$	1,021
Services	1,940			2,034			3,917			4,148
Product sales and other	670			632			1,308			1,170
Total Revenues	3,368			3,144			6,792			6,339

Operating Costs, Expenses and Other
Costs of sales	1,090			752			2,171			1,483
Operations and maintenance	536			603			1,049			1,168
Depreciation, depletion and amortization	577			552			1,135			1,103
General and administrative	153			189			334			379
Taxes, other than income taxes	91			110			195			218
(Gain) loss on impairments and divestitures, net	—			(4		)	6			231
Other (income) expense, net	(1		)	2			—			1
Total Operating Costs, Expenses and Other	2,446			2,204			4,890			4,583

Operating Income	922			940			1,902			1,756

Other Income (Expense)
Earnings from equity investments	135			106			310			206
Gain on impairments and divestitures of equity investments, net	—			12			—			6
Amortization of excess cost of equity investments	(15		)	(16		)	(30		)	(30		)
Interest, net	(463		)	(471		)	(928		)	(912		)
Other, net	20			17			36			30
Total Other Expense	(323		)	(352		)	(612		)	(700		)

Income Before Income Taxes	599			588			1,290			1,056

Income Tax Expense	(216		)	(213		)	(462		)	(367		)

Net Income	383			375			828			689

Net Income Attributable to Noncontrolling Interests	(7		)	(3		)	(12		)	(2		)

Net Income Attributable to Kinder Morgan, Inc.	376			372			816			687

Preferred Stock Dividends	(39		)	(39		)	(78		)	(78		)

Net Income Available to Common Stockholders	$	337		$	333		$	738		$	609

Class P Shares
Basic Earnings Per Common Share	$	0.15		$	0.15		$	0.33		$	0.27

Basic Weighted Average Common Shares Outstanding	2,230			2,229			2,230			2,229

Diluted Earnings Per Common Share	$	0.15		$	0.15		$	0.33		$	0.27

Diluted Weighted Average Common Shares Outstanding	2,230			2,229			2,230			2,229

Dividends Per Common Share Declared for the Period	$	0.125		$	0.125		$	0.250		$	0.250

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016

Net income	$	383		$	375		$	828		$	689
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(63), $82, $(102) and $40, respectively)	108			(142		)	178			(69		)
Reclassification of change in fair value of derivatives to net income (net of tax benefit of $43, $6, $55 and $69, respectively)	(75		)	(11		)	(96		)	(119		)
Foreign currency translation adjustments (net of tax expense of $(10), $(4), $(17) and $(49), respectively)	38			7			51			85
Benefit plan adjustments (net of tax expense of $(4), $(3), $(9) and $(6), respectively)	7			6			13			10
Total other comprehensive income (loss)	78			(140		)	146			(93		)

Comprehensive income	461			235			974			596
Comprehensive income attributable to noncontrolling interests	(26		)	(3		)	(31		)	(2		)
Comprehensive income attributable to Kinder Morgan, Inc.	$	435		$	232		$	943		$	594

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

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

	June 30, 2017			December 31, 2016
	(Unaudited)
ASSETS
Current Assets
Cash and cash equivalents	$	452		$	684
Restricted deposits	66			103
Accounts receivable, net	1,184			1,370
Fair value of derivative contracts	230			198
Inventories	438			357
Income tax receivable	169			180
Other current assets	187			337
Total current assets	2,726			3,229

Property, plant and equipment, net	39,423			38,705
Investments	7,442			7,027
Goodwill	22,159			22,152
Other intangibles, net	3,208			3,318
Deferred income taxes	3,619			4,352
Deferred charges and other assets	1,626			1,522
Total Assets	$	80,203		$	80,305

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	3,224		$	2,696
Accounts payable	1,353			1,257
Accrued interest	573			625
Accrued contingencies	335			261
Other current liabilities	878			1,085
Total current liabilities	6,363			5,924
Long-term liabilities and deferred credits
Long-term debt
Outstanding	33,900			36,105
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	1,100			1,149
Total long-term debt	35,100			37,354
Other long-term liabilities and deferred credits	2,526			2,225
Total long-term liabilities and deferred credits	37,626			39,579
Total Liabilities	43,989			45,503
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,230,166,353 and 2,231,117,801 shares, respectively, issued and outstanding	22			22
Preferred stock, $0.01 par value, 10,000,000 shares authorized, 9.75% Series A Mandatory Convertible, $1,000 per share liquidation preference, 1,600,000 shares issued and outstanding	—			—
Additional paid-in capital	42,092			41,739
Retained deficit	(6,482		)	(6,669		)
Accumulated other comprehensive loss	(483		)	(661		)
Total Kinder Morgan, Inc.’s stockholders’ equity	35,149			34,431
Noncontrolling interests	1,065			371
Total Stockholders’ Equity	36,214			34,802
Total Liabilities and Stockholders’ Equity	$	80,203		$	80,305

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

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

	Six Months Ended June 30,
	2017			2016
Cash Flows From Operating Activities
Net income	$	828		$	689
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,135			1,103
Deferred income taxes	454			388
Amortization of excess cost of equity investments	30			30
Change in fair market value of derivative contracts	(5		)	(14		)
Loss on impairments and divestitures, net	6			231
Gain on impairments and divestitures of equity investments, net	—			(6		)
Earnings from equity investments	(310		)	(206		)
Distributions from equity investment earnings	208			203
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable, net	185			81
Inventories	(93		)	49
Other current assets	—			7
Accounts payable	(59		)	(144		)
Accrued interest, net of interest rate swaps	(44		)	(49		)
Accrued contingencies and other current liabilities	(96		)	73
Rate reparations, refunds and other litigation reserve adjustments	(35		)	31
Other, net	(38		)	(121		)
Net Cash Provided by Operating Activities	2,166			2,345

Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired	(4		)	(333		)
Capital expenditures	(1,336		)	(1,470		)
Sales of property, plant and equipment, and other net assets, net of removal costs	71			220
Contributions to investments	(548		)	(363		)
Distributions from equity investments in excess of cumulative earnings	214			81
Other, net	30			(15		)
Net Cash Used in Investing Activities	(1,573		)	(1,880		)

Cash Flows From Financing Activities
Issuances of debt	4,330			6,847
Payments of debt	(6,124		)	(6,800		)
Debt issue costs	(60		)	(6		)
Cash dividends - common shares	(560		)	(559		)
Cash dividends - preferred shares	(78		)	(76		)
Contributions from investment partner	415			—
Contributions from noncontrolling interests - net proceeds from KML IPO	1,247			—
Contributions from noncontrolling interests - other	11			87
Distributions to noncontrolling interests	(15		)	(11		)
Other, net	(1		)	(1		)
Net Cash Used in Financing Activities	(835		)	(519		)

Effect of Exchange Rate Changes on Cash and Cash Equivalents	10			5

Net decrease in Cash and Cash Equivalents	(232		)	(49		)
Cash and Cash Equivalents, beginning of period	684			229
Cash and Cash Equivalents, end of period	$	452		$	180

Non-cash Investing and Financing Activities
Increase in property, plant and equipment from both accruals and contractor retainage	$	159
Assets acquired by the assumption or incurrence of liabilities	$	—		$	43
Net assets contributed to equity investments	$	—		$	37
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	995		$	1,047
Cash paid during the period for income taxes, net	1			5

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)



	Common stock			Preferred stock
	Issued shares	Par value		Issued shares	Par value		Additional paid-in capital		Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Balance at December 31, 2016	2,230	$	22	2	$	—	$	41,739	$	(6,669	)	$	(661	)	$	34,431		$	371		$	34,802
Restricted shares							37								37						37
Net income									816						816			12			828
KML IPO							316					51			367			683			1,050
Distributions															—			(15		)	(15		)
Contributions															—			11			11
Preferred stock dividends									(78		)				(78		)				(78		)
Common stock dividends									(560		)				(560		)				(560		)
Impact of adoption of ASU 2016-09 (See Note 8)									9						9						9
Other															—			(16		)	(16		)
Other comprehensive income												127			127			19			146
Balance at June 30, 2017	2,230	$	22	2	$	—	$	42,092	$	(6,482	)	$	(483	)	$	35,149		$	1,065		$	36,214



	Common stock			Preferred stock
	Issued shares	Par value		Issued shares	Par value		Additional paid-in capital		Retained deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Balance at December 31, 2015	2,229	$	22	2	$	—	$	41,661	$	(6,103	)	$	(461	)	$	35,119		$	284		$	35,403
Restricted shares							35								35						35
Net income									687						687			2			689
Distributions															—			(11		)	(11		)
Contributions															—			87			87
Preferred stock dividends									(78		)				(78		)				(78		)
Common stock dividends									(559		)				(559		)				(559		)
Other comprehensive loss												(93		)	(93		)				(93		)
Balance at June 30, 2016	2,229	$	22	2	$	—	$	41,696	$	(6,053	)	$	(554	)	$	35,111		$	362		$	35,473

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 84,000 miles of pipelines and 155 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 steel, coal and petroleum coke. We are also a leading producer of CO₂, which we and others utilize for enhanced oil recovery projects primarily in the Permian basin.

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.

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2016 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

Impairments and Losses on Divestitures, net

During the six months ended June 30, 2017, we recorded non-cash pre-tax losses on impairments and divestitures netting to $6 million related to miscellaneous asset disposals. During the three and six months ended June 30, 2016, we recorded non-cash pre-tax losses on impairments and divestitures netting to $2 million and $257 million, respectively. The six months ended June 30, 2016 included (i) $216 million of project write-offs across our Natural Gas Pipelines, CO₂,and Products Pipelines business segments, of which $20 million was related to our share of impairments recorded by our equity investees; (ii) $20 million of impairments related to certain coal facilities in our Terminals business segment; (iii) $8 million of loss related to the sale of a Transmix facility in our Products Pipelines business segment; and (iv) $13 million of net losses on miscellaneous asset disposals.

In addition, during the three and six months ended June 30, 2016 we recognized a $12 million gain on the sale of an equity investment, which is included in “Gain on impairments and divestitures of equity investments, net” on the accompanying consolidated statements of income.

These impairments were driven by market conditions that existed at the time and require management to estimate fair value of these assets. The impairments resulting from decisions to classify assets as held-for-sale are based on the value expected to be realized in the transaction which is generally known at the time. The estimates of fair value are based on Level 3 valuation estimates using industry standard income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. In certain cases, management’s decisions to dispose of certain assets may trigger impairments. We typically use discounted cash flow analyses to determine the fair value of our assets. We may probability weight various forecasted cash flow scenarios utilized in the analysis as we consider the possible

outcomes. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.

We may identify additional triggering events requiring future evaluations of the recoverability of the carrying value of our long-lived assets, investments and goodwill. Because certain assets, including some equity investments and oil and gas producing properties, have been recently written down to fair value, any deterioration in fair value relative to our carrying value increases the likelihood of further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to be not fully recoverable.

Goodwill

We evaluate goodwill for impairment on May 31 of each year. For this purpose, we have seven reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals; and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test.

Step 1 involves comparing the estimated fair value of each respective reporting unit to its carrying value, including goodwill. If the estimated fair value exceeds the carrying value, the reporting unit’s goodwill is not considered impaired. If the carrying value exceeds the estimated fair value, step 2 must be performed to determine whether goodwill is impaired and, if so, the amount of the impairment.

The results of our May 31, 2017 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value and step 2 was not required. For our Natural Gas Pipelines - Non-Regulated, the fair value of the reporting unit exceeded the carrying value (including approximately $4 billion of allocated goodwill) by 4%.

The fair value estimates used in the step 1 goodwill test are based on Level 3 inputs of the fair value hierarchy. The level 3 inputs include valuation estimates using industry standard market and income approach valuation methodologies which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions prices, weighted average costs of capital, general economic conditions and the related demand for products handled or transported by our assets as well as assumptions regarding commodity prices, future cash flows based on rate and volume assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimate of the risk-adjusted discount rates that would be used by market participants specific to the particular asset.

We expect that the fair value of our Natural Gas Pipelines - Non-Regulated reporting unit will continue to exceed carrying value so long as our estimate of future cash flows and the market valuation remain consistent with current levels. A continued period of volatile commodity prices could result in further deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital, and our cash flow estimates. Changes to any one or combination of these factors, would result in a change to the reporting unit fair values discussed above which could lead to future impairment charges. Such potential impairment could have a material 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, which may be stock or stock units issued to management employees and include dividend equivalent payments, do not participate in excess distributions over earnings.

The following table sets forth the allocation of net income available to shareholders of Class P shares and participating securities (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Class P shares	$	336	$	332	$	735	$	607
Participating securities:
Restricted stock awards(a)	1		1		3		2
Net Income Available to Common Stockholders	$	337	$	333	$	738	$	609

________


(a)	As of June 30, 2017, there were approximately 9 million restricted stock awards.

On May 25, 2017, approximately 293 million of warrants expired. In addition, the following maximum number of 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 June 30,		Six Months Ended June 30,
	2017	2016	2017	2016
Unvested restricted stock awards	9	8	9	8
Convertible trust preferred securities	3	8	3	8
Mandatory convertible preferred stock(a)	58	58	58	58

_______

(a) Until our mandatory convertible preferred shares are converted to common shares, on or before the expected mandatory conversion date of October 26, 2018, the holder of each preferred share participates in our earnings by receiving preferred dividends.

2. Divestitures

Sale of Approximate 30% Interest in Canadian Business

On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares on the Toronto Stock Exchange at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million (USD $1,299 million). The net proceeds from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business with KMI retaining the remaining 70% interest. We used the proceeds from KML to pay down debt.

Subsequent to the IPO, we retained control of KML and the limited partnership, and as a result, they remain consolidated in our consolidated financial statements. The public ownership of the KML restricted voting shares is reflected within “Noncontrolling interests” in our consolidated statements of stockholders’ equity and consolidated balance sheets. Earnings attributable to the public ownership of KML are presented in “Net income attributable to noncontrolling interests” in our consolidated statements of income for the periods presented after May 30, 2017.

The net proceeds received of $1,247 million are presented as “Contributions from noncontrolling interests - KML IPO” on our consolidated statement of cash flows for the six months ended June 30, 2017. Because we retained control of KML subsequent to the IPO, the $316 million adjustment made to “Additional paid-in capital” on our consolidated statement of stockholders equity for the six months ended June 30, 2017 represents the difference between our book value prior to the sale and our share of book value in KML’s net assets after the sale. The impact of the IPO resulted in a $165 million deferred income tax adjustment. $764 million is attributed to the KML public shareholders to reflect their proportionate ownership percentage in the net assets of KML acquired from us and is presented in “Noncontrolling interests” on our consolidated statement of stockholders equity for the six months ended June 30, 2017. The above amounts recorded to “Additional paid-in capital” and “Noncontrolling interests” are net of IPO fees, which includes $2 million accrued at June 30, 2017.

The above amount recorded to “Noncontrolling interests” has been reduced by $81 million primarily associated with the allocation of currency translation adjustments recorded in “Accumulated other comprehensive loss” to “Noncontrolling interests.”

Mountain pipeline system; (ii) the Canadian Cochin pipeline system; (iii) the Puget Sound pipeline system; (iv) the Jet Fuel pipeline system; and (v) terminal facilities located in Western Canada.

Kinder Morgan Canada Limited Partnership

In conjunction with the IPO, Kinder Morgan Canada Limited Partnership (KMC LP) and Kinder Morgan Canada GP Inc. (KMC GP) were formed to hold our Canadian business. We have determined that KMC LP is a variable interest entity because a simple majority or lower threshold of the limited partnership interests do not possess substantive “kick-out rights” (i.e., the right to remove the general partner or to dissolve (liquidate) the entity without cause) or substantive participation rights. We have also determined KMC GP is the primary beneficiary because it has the power to direct the activities that most significantly impact KMC LP’s performance, the right to receive benefits and the obligation to absorb losses, that could be significant to KMC LP. As a result, KMC GP consolidates KMC LP. KMC GP is a wholly-owned subsidiary of KML, which is indirectly controlled by us through our 100% interest in KML’s special voting shares that represent approximately 70% of KML’s total voting shares (comprised of restricted voting shares and special voting shares). Consequently, we consolidate KML and the variable interest entity, KMC LP, in our consolidated financial statements.

The following table shows the carrying amount and classification of KMC LP’s assets and liabilities in our consolidated balance sheets (in millions):



	June 30, 2017
Assets
Total current assets	$	235
Property, plant and equipment, net	2,580
Total goodwill, deferred charges and other assets	298
Total assets	$	3,113
Liabilities
Total current liabilities	$	366
Long-term debt, excluding current maturities	—
Total other long-term liabilities and deferred credits	371
Total liabilities	$	737

We receive distributions from KMC LP through our indirectly owned limited partnership interests in KMC LP, but otherwise the assets of KMC LP cannot be used to settle our obligations. Our subsidiaries that are the direct owners of our limited partnership interests in KMC LP have guaranteed the obligations of KMC LP’s wholly owned subsidiaries, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, under the Credit Facility (see Note 3), but recourse in respect of such guarantee is limited solely to the limited partnership interests of KMC LP held by such subsidiaries and any proceeds thereof. Additionally, in connection with the Credit Facility, we entered into an Equity Nomination and Support Agreement whereby, among other things, we commit to contribute or cause to be contributed at the time of each drawdown on the construction credit facility or the contingent credit facility either equity or subordinated debt to Kinder Morgan Cochin ULC in an amount sufficient to cause the outstanding indebtedness under the credit facilities and any other funded debt for the Trans Mountain expansion project not to exceed 60% of the total project costs for the project as projected over the six month period following the date of such drawdown. Other than such guarantees and the Equity Nomination and Support Agreement, we do not guarantee the debt, commercial paper or other similar commitments of KMC LP or any of its subsidiaries, and the obligations of KMC LP may only be settled using the assets of KMC LP. KMC LP does not guarantee the debt or other similar commitments of KMI.

Sale of Interest in Elba Liquefaction Company L.L.C. (ELC)

Effective February 28, 2017, we sold a 49% partnership interest in ELC to investment funds managed by EIG Global Energy Partners (EIG). We continue to own a 51% controlling interest in and operate ELC. Under the terms of ELC’s limited liability company agreement, we are responsible for placing in service and operating certain supply pipelines and terminal facilities that support the operations of ELC and which are wholly owned by us. In certain limited circumstances which are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account.

As a result of these contingencies, the sale proceeds of $386 million, and subsequent EIG contributions, have been recorded as a deferred credit within “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of June 30, 2017. EIG is not entitled to any specified return on its capital. Once these contingencies expire, EIG’s capital account will be reflected as noncontrolling interest on our consolidated balance sheet.

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, premiums and issuance costs (in millions):



	June 30, 2017		December 31, 2016
Unsecured term loan facility, variable rate, due January 26, 2019	$	1,000	$	1,000
Senior notes, 1.50% through 8.05%, due 2017 through 2098(a)	12,563		13,236
Credit facility due November 26, 2019	—		—
Commercial paper borrowings	115		—
KML Credit Facility(b)	146		—
KMP senior notes, 2.65% through 9.00%, due 2017 through 2044(c)	18,885		19,485
TGP senior notes, 7.00% through 8.375%, due 2017 through 2037(d)	1,240		1,540
EPNG senior notes, 5.95% through 8.625%, due 2017 through 2032(e)	760		1,115
CIG senior notes, 4.15% and 6.85%, due 2026 and 2037	475		475
Kinder Morgan Finance Company, LLC, senior notes, 6.00% and 6.40%, due 2018 and 2036	786		786
Hiland Partners Holdings LLC, senior note, 5.50%, due 2022	225		225
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035	427		433
Trust I preferred securities, 4.75%, due March 31, 2028(f)	221		221
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock	100		100
Other miscellaneous debt	281		285
Total debt – KMI and Subsidiaries	37,224		38,901
Less: Current portion of debt(g)	3,224		2,696
Total long-term debt – KMI and Subsidiaries(h)	$	34,000	$	36,205

_______

(a)

Amount includes senior notes that are denominated in Euros and have been converted to U.S. dollars and are respectively reported above at the June 30, 2017 exchange rate of 1.1426 U.S. dollars per Euro and the December 31, 2016 exchange rate of 1.0517 U.S. dollars per Euro. For the six months ended June 30, 2017, our debt balance increased by $114 million as a result of the change in the exchange rate of U.S. dollars per Euro. The increase in debt due to the changes in exchange rates is offset by a corresponding change in the value of cross-currency swaps reflected in “Deferred charges and other assets” and “ Other long-term liabilities and deferred credits” on our consolidated balance sheets. At the time of issuance, we entered into cross-currency swap agreements associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management”). In June, 2017, we repaid $786 million of maturing 7.00% senior notes.


(b)	The credit facility is denominated in C$ and has been converted to U.S. dollars and reported above at the June 30, 2017 exchange rate of 0.7706 U.S. dollars per C$. See “—Credit Facilities” below.


(c)	In February 2017, we repaid $600 million of maturing 6.00% senior notes.


(d)	In April 2017, we repaid $300 million of maturing 7.50% senior notes.


(e)	In April 2017, we repaid $355 million of maturing 5.95% senior notes.

(f)

The Trust I Preferred Securities are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder. Prior to May 25, 2017, conversions of these securities were converted into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; (ii) $25.18 in cash without interest; and (iii) 1.100 warrants to purchase a share of our Class P common stock. Our warrants expired on May 25, 2017, along with conversion of 1.100 warrants to purchase a share of our Class P common mixed consideration.


(g)	Amounts include outstanding credit facility borrowings, commercial paper borrowings and other debt maturing within 12 months (see “—Current Portion of Debt” below).


(h)	Excludes our “Debt fair value adjustments” which, as of June 30, 2017 and December 31, 2016, increased our combined debt balances by $1,100 million and $1,149 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs

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.

We and substantially all of our wholly owned domestic subsidiaries are a party to 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. Also, see Note 11.

Credit Facilities

As of June 30, 2017, we had $4,774 million available under our $5.0 billion revolving credit agreement, which is net of $111 million in letters of credit. 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 June 16, 2017, Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC, our indirect subsidiaries of KML, entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the Trans Mountain expansion project, (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain expansion project costs (and, subject to the need to fund such additional costs, meeting the Canadian National Energy Board-mandated liquidity requirements) and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. Any undrawn commitments under the Credit Facility will incur a standby fee of 0.30% to 0.625%, with the range dependent on the credit ratings of Kinder Morgan Cochin ULC or KML. The Credit Facility is guaranteed by KML and all of the non-borrower subsidiaries of KML and are secured by a first lien security interest on all of the assets of KML and the equity and assets of the other guarantors.

Draw down of funds on the Credit Facility bear interest dependent on the type of loans requested and are as follows:


•	bankers’ acceptances or London Interbank Offered Rate loans are at an annual rate of approximately CDOR or the London Interbank Offered Rate, as the case may be, plus a fixed spread ranging from 1.50% to 2.50%;


•	loans in Canadian dollars or U.S. dollars are at an annual rate of approximately the Canadian prime rate or the U.S. dollar base rate, as the case may be, plus a fixed spread ranging from 0.50% to 1.50%, in each case, with the range dependent on the credit ratings of the Company;


•	letters of credit (under working capital facility only) will have issuance fees based on an annual rate of approximately CDOR plus a fixed spread ranging from 1.50% to 2.50%, with the range dependent on the credit ratings of the Company.

The foregoing rates and fees will increase by 0.25% upon the fourth anniversary of the Credit Facility.

Our Credit Facility includes various financial and other covenants including:


•	a maximum ratio of consolidated total funded debt to consolidated capitalization of 70%;


•	restrictions on ability to incur debt;


•	restrictions on ability to make dispositions, restricted payments and investments;


•	restrictions on granting liens and on sale-leaseback transactions;


•	restrictions on ability to engage in transactions with affiliates; and


•	restrictions on ability to amend organizational documents and engage in corporate reorganization transactions.

As of June 30, 2017, we were in compliance with all required covenants. As of June 30, 2017, we had $126.9 million (C$164.7 million) outstanding on our construction facility and $18.9 million (C$24.5 million) outstanding on our working capital facility, both included in “Current portion of debt” on our consolidated balance sheet. For the six months ended June 30, 2017, we incurred $0.5 million in standby fees.

Current Portion of Debt

Our current portion of debt as of June 30, 2017, primarily includes the following significant series of long-term notes maturing within the next 12 months:

Senior notes - $500 million 2.00% notes due December 2017

Kinder Morgan Finance Company, LLC, senior notes - $750 million 6.00% notes due January 2018

Senior notes - $82 million 7.00% notes due February 2018

KMP senior notes - $975 million 5.95% notes due February 2018

Senior notes - $477 million 7.25% notes due June 2018

4. Stockholders’ Equity

Common Equity

As of June 30, 2017, our common equity consisted of our Class P common stock. For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2016 Form 10-K.

KMI Common Dividends

Holders of our common stock participate in any dividend declared by our board of directors, subject to the rights of the holders of any outstanding preferred stock. Our per share dividends declared for and paid in the six months periods ended June 30, 2017 and 2016 were $0.250 per share. On July 19, 2017, our board of directors declared a cash dividend of $0.125 per common share for the quarterly period ended June 30, 2017, which is payable on August 15, 2017 to common shareholders of record as of July 31, 2017.

Warrants

On May 25, 2017, 293 million of unexercised warrants to buy KMI common stock expired. Prior to expiration, each of the warrants entitled 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.

Mandatory Convertible Preferred Stock

We have issued and outstanding 1,600,000 shares of 9.750% Series A mandatory convertible preferred stock, with a liquidating preference of $1,000 per share. For additional information regarding our mandatory convertible preferred stock, see Note 11 to our consolidated financial statements included in our 2016 Form 10-K.

Preferred Dividends

On April 19, 2017, our board of directors declared a cash dividend of $24.375 per share of our mandatory convertible preferred stock (equivalent of $1.21875 per depositary share) for the period from and including April 26, 2017 through and including July 25, 2017, which is payable on July 26, 2017 to mandatory convertible preferred shareholders of record as of July 11, 2017.

Noncontrolling Interests

KML Restricted Voting Shares

As discussed in Note 2, on May 30, 2017 our indirect subsidiary, KML, issued 102,942,000 restricted voting shares in a public offering. The public ownership of the KML restricted voting shares represents an approximate 30% interest in our Canadian operations and is reflected within “Noncontrolling interests” in our consolidated financial statements as of and for the periods presented after May 30, 2017.

On July 19, 2017, KML’s board of directors declared a prorated dividend for the first quarter of C$0.0571 per restricted voting share, payable on August 15, 2017, to restricted voting shareholders of record as of July 31, 2017. The initial dividend is prorated from May 30, 2017, the day that KML closed its offering, to June 30, 2017. Based on a full quarter, the dividend amounts to C$0.1625 per restricted voting share (C$0.65 annualized). The total KML dividend declared for the three months ended June 30, 2017 amounted to approximately C$5.9 million.

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 some of these risks. In addition, prior to May 2016, we had legacy power forward and swap contracts related to operations of acquired businesses.

Energy Commodity Price Risk Management

As of June 30, 2017, 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	(20.1	)	MMBbl
Crude oil basis	(2.7	)	MMBbl
Natural gas fixed price	(54.9	)	Bcf
Natural gas basis	(27.0	)	Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price	(0.9	)	MMBbl
Crude oil basis	(0.5	)	MMBbl
Natural gas fixed price	4.6		Bcf
Natural gas basis	(39.0	)	Bcf
NGL and other fixed price	(6.1	)	MMBbl

As of June 30, 2017, 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 2021.

Interest Rate Risk Management

As of June 30, 2017 and December 31, 2016, we had a combined notional principal amount of $9,575 million and $9,775 million, respectively, of fixed-to-variable interest rate swap agreements, all of which were designated as fair value hedges. All of our swap agreements effectively convert the interest expense associated with certain series of senior notes from fixed rates to variable rates based on an interest rate of London Interbank Offered Rate plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of June 30, 2017, 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

As of June 30, 2017, we had a notional principal amount of $1,358 million of cross-currency swap agreements to manage the foreign currency risk related to our Euro denominated senior notes 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
		June 30, 2017		December 31, 2016		June 30, 2017			December 31, 2016
	Location	Fair value				Fair value
Derivatives designated as hedging contracts
Natural gas and crude derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	149	$	101	$	(6	)	$	(57	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	82		70		(2		)	(24		)
Subtotal		231		171		(8		)	(81		)
Interest rate swap agreements	Fair value of derivative contracts/(Other current liabilities)	69		94		—			—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	211		206		(30		)	(57		)
Subtotal		280		300		(30		)	(57		)
Cross-currency swap agreements	Fair value of derivative contracts/(Other current liabilities)	—		—		(21		)	(7		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	82		—		—			(24		)
Subtotal		82		—		(21		)	(31		)
Total		593		471		(59		)	(169		)

Derivatives not designated as hedging contracts
Natural gas, crude, NGL and other derivative contracts	Fair value of derivative contracts/(Other current liabilities)	12		3		(6		)	(29		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(1		)	(1		)
Subtotal		12		3		(7		)	(30		)
Total		12		3		(7		)	(30		)
Total derivatives		$	605	$	474	$	(66	)	$	(199	)

Effect of Derivative Contracts on the Income Statement

The following tables summarize the impact of our derivative contracts in 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 June 30,						Six Months Ended June 30,
		2017			2016			2017			2016

Interest rate swap agreements	Interest, net	$	46		$	119		$	7		$	399

Hedged fixed rate debt	Interest, net	$	(47	)	$	(120	)	$	(11	)	$	(404	)



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 June 30,							Three Months Ended June 30,							Three Months Ended June 30,
	2017			2016				2017			2016				2017		2016
Energy commodity derivative contracts	$	52		$	(111	)	Revenues—Natural gas sales	$	(1	)	$	2		Revenues—Natural gas sales	$	—	$	—
							Revenues—Product sales and other	14			33			Revenues—Product sales and other	5		(6		)
							Costs of sales	1			(2		)	Costs of sales	—		—
Interest rate swap agreements(c)	(1		)	(1		)	Interest, net	(1		)	—			Interest, net	—		—
Cross-currency swap	57			(30		)	Other, net	62			(22		)	Other, net	—		—
Total	$	108		$	(142	)	Total	$	75		$	11		Total	$	5	$	(6	)



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)
	Six Months Ended June 30,							Six Months Ended June 30,							Six Months Ended June 30,
	2017			2016				2017			2016				2017		2016
Energy commodity derivative contracts	$	120		$	(84	)	Revenues—Natural gas sales	$	1		$	23		Revenues—Natural gas sales	$	—	$	—
							Revenues—Product sales and other	20			90			Revenues—Product sales and other	8		(5		)
							Costs of sales	4			(12		)	Costs of sales	—		—
Interest rate swap agreements(c)	(1		)	(5		)	Interest, net	(1		)	(1		)	Interest, net	—		—
Cross-currency swap	59			20			Other, net	72			19			Other, net	—		—
Total	$	178		$	(69	)	Total	$	96		$	119		Total	$	8	$	(5	)

_____

(a)

We expect to reclassify an approximate $60 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of June 30, 2017 into earnings during the next twelve months (when the associated forecasted transactions 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).


(c)	Amounts represent our share of an equity investee’s accumulated other comprehensive loss.



Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended June 30,					Six Months Ended June 30,
		2017		2016			2017		2016
Energy commodity derivative contracts	Revenues—Natural gas sales	$	5	$	(11	)	$	11	$	(5	)
	Revenues—Product sales and other	7		(12		)	19		(14		)
	Costs of sales	—		3			—		(2		)
Interest rate swap agreements	Interest, net	—		24			—		77
Total(a)		$	12	$	4		$	30	$	56

_______

(a) Three and six months ended June 30, 2017 includes approximate gains of $17 million and $29 million, respectively, associated with natural gas, crude and NGL derivative contract settlements. Three and six months ended June 30, 2016 includes approximate gains of $20 million and $39 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of June 30, 2017 and December 31, 2016, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2017 and December 31, 2016, we had cash margins of $7 million and $37 million, respectively, posted by us with our counterparties as collateral and no amounts posted by our counterparties as collateral. The balance at June 30, 2017, consisted of initial margin requirements of $14 million, offset by variation margin requirements of $7 million. We also use industry standard commercial agreements which allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

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 June 30, 2017, 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, 2016	$	(1	)	$	(288	)	$	(372	)	$	(661	)
Other comprehensive gain before reclassifications	178			32			13			223
Gains reclassified from accumulated other comprehensive loss	(96		)	—			—			(96		)
KML IPO	—			44			7			51
Net current-period other comprehensive income	82			76			20			178
Balance as of June 30, 2017	$	81		$	(212	)	$	(352	)	$	(483	)



	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, 2015	$	219		$	(322	)	$	(358	)	$	(461	)
Other comprehensive (loss) gain before reclassifications	(69		)	85			10			26
Gains reclassified from accumulated other comprehensive loss	(119		)	—			—			(119		)
Net current-period other comprehensive (loss) income	(188		)	85			10			(93		)
Balance as of June 30, 2016	$	31		$	(237	)	$	(348	)	$	(554	)

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 June 30, 2017
Energy commodity derivative contracts(a)	$	10	$	233	$	—	$	243	$	(12	)	$	(7	)	$	224
Interest rate swap agreements	—		280		—		280		(13		)	—			267
Cross-currency swap agreements	—		82		—		82		(20		)	—			62
As of December 31, 2016
Energy commodity derivative contracts(a)	$	6	$	168	$	—	$	174	$	(43	)	$	—		$	131
Interest rate swap agreements	—		300		—		300		(18		)	—			282



	Balance sheet liability fair value measurements by level															Net amount
	Level 1			Level 2			Level 3		Gross amount			Contracts available for netting		Collateral posted(b)		Net amount
As of June 30, 2017
Energy commodity derivative contracts(a)	$	(4	)	$	(11	)	$	—	$	(15	)	$	12	$	—	$	(3	)
Interest rate swap agreements	—			(30		)	—		(30		)	13		—		(17		)
Cross-currency swap agreements	—			(21		)	—		(21		)	20		—		(1		)
As of December 31, 2016
Energy commodity derivative contracts(a)	$	(29	)	$	(82	)	$	—	$	(111	)	$	43	$	37	$	(31	)
Interest rate swap agreements	—			(57		)	—		(57		)	18		—		(39		)
Cross-currency swap agreements	—			(31		)	—		(31		)	—		—		(31		)

_______


(a)	Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of OTC West Texas Intermediate swaps and options.

(b)

Cash margin deposits held and posted by us associated with our energy commodity contract positions and OTC swap agreements and reported within “Other current liabilities” and “Restricted deposits,” respectively, on our accompanying consolidated balance sheets. Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

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 June 30,					Six Months Ended June 30,
	2017		2016			2017		2016
Derivatives-net asset (liability)
Beginning of Period	$	—	$	(2	)	$	—	$	(15	)
Total gains or (losses) included in earnings	—		(3		)	—		(9		)
Settlements	—		5			—		24
End of Period	$	—	$	—		$	—	$	—
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	$	—	$	—		$	—	$	—

As of June 30, 2016, our Level 3 derivative asset and liability activity consisted primarily of power derivative contracts (which expired in April 2016), 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, and management would not expect materially different valuation results were we to use different input amounts within reasonable ranges.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below (in millions):



	June 30, 2017				December 31, 2016
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	38,324	$	39,915	$	40,050	$	41,015

We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both June 30, 2017 and December 31, 2016.

7. Reportable Segments

Segment results for the three and six months ended June 30, 2016 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within the Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.

Financial information by segment follows (in millions):



	Three Months Ended June 30,				Six Months Ended June 30,
	2017		2016		2017		2016
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,093	$	1,882	$	4,261	$	3,852
Intersegment revenues	2		1		5		2
CO₂	307		304		610		606
Terminals
Revenues from external customers	486		487		973		952
Intersegment revenues	1		1		1		1
Products Pipelines
Revenues from external customers	413		398		811		789
Intersegment revenues	5		3		9		8
Kinder Morgan Canada	60		63		119		122
Corporate and intersegment eliminations(a)	1		5		3		7
Total consolidated revenues	$	3,368	$	3,144	$	6,792	$	6,339



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Segment EBDA(b)
Natural Gas Pipelines	$	907		$	967		$	1,962		$	1,961
CO₂	221			204			439			391
Terminals	304			302			611			562
Products Pipelines	324			292			611			469
Kinder Morgan Canada	43			46			86			92
Total Segment EBDA	1,799			1,811			3,709			3,475
DD&A	(577		)	(552		)	(1,135		)	(1,103		)
Amortization of excess cost of equity investments	(15		)	(16		)	(30		)	(30		)
General and administrative and corporate charges	(145		)	(184		)	(326		)	(374		)
Interest expense, net	(463		)	(471		)	(928		)	(912		)
Income tax expense	(216		)	(213		)	(462		)	(367		)
Total consolidated net income	$	383		$	375		$	828		$	689



	June 30, 2017		December 31, 2016
Assets
Natural Gas Pipelines	$	50,858	$	50,428
CO₂	4,106		4,065
Terminals	9,898		9,725
Products Pipelines	8,421		8,329
Kinder Morgan Canada	1,762		1,572
Corporate assets(c)	5,158		6,108
Assets held for sale	—		78
Total consolidated assets	$	80,203	$	80,305

_______


(a)	Includes a management fee for services we perform as operator of an equity investee.


(b)	Includes revenues, earnings from equity investments, other, net, less operating expenses, and other (income) expense, net, loss on impairments and divestitures, net and loss on impairments and divestitures of equity investments, net.

(c)

Includes cash and cash equivalents, margin and restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to debt fair value adjustments, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy operations) not allocated to the reportable 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 June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
Income tax expense	$	216		$	213		$	462		$	367
Effective tax rate	36.1		%	36.2		%	35.8		%	34.8		%

The effective tax rate for the three and six months ended June 30, 2017 is slightly 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 Transmission Company (Citrus) and Plantation Pipe Line.

The effective tax rate for the three months ended June 30, 2016 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 Citrus and an increase in our deferred state income tax rate.

The effective tax rate for the six months ended June 30, 2016 is lower than the statutory federal rate of 35% primarily due to dividend-received deductions from our investment in Citrus and adjustments to our income tax reserve for uncertain tax positions, partially offset by state and foreign income taxes.

Adoption of ASU 2016-09 “Compensation - Stock Compensation (Topic 718)”

The tax impact of ASU 2016-09, which was adopted and effective January 1, 2017, resulted in $9 million of deferred tax assets being recorded through a cumulative-effect adjustment to our retained deficit. The previously unrecorded deferred tax asset is related to net operating loss carryovers as a result of the delayed recognition of a windfall tax benefit related to share-based compensation. Post-adoption the excess tax benefits or deficiencies are recognized for income tax purposes in the period in which they occur through the income statement.

9. Litigation, Environmental and Other Contingencies

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations 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 and insurance, 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.

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 the most recent of which was filed in late 2015 with the FERC (docketed at OR16-6) challenging SFPP’s filed East Line rates. 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 some of these proceedings shippers have challenged the overall rate being charged by SFPP, and in others the shippers have challenged SFPP’s index-based rate increases. If the shippers prevail on their arguments or claims, they are entitled to seek reparations (which may reach back up to two years prior to the filing date 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 SFPP may include in its rates. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to FERC for further consideration of two issues: (1) the appropriate data to be used to determine the return on equity for SFPP in the underlying docket, and (2) the just and reasonable return to be provided to a tax pass-through entity that includes an income tax allowance in its underlying cost of service. On July 21, 2017, an initial decision by the Administrative Law Judge (ALJ) in OR16-6 concluded that the Complainants are due reparations, with appropriate interest, equal to the difference between what SFPP collected from the Complainants for service on the East Line and the amounts SFPP would have collected had it charged just and reasonable rates for that line. The ALJ ruled that an income tax allowance should be included in the cost of service both to determine reparations and to set going forward rates, and found that the new just and reasonable rates are not knowable until the FERC reviews the initial decision and orders a compliance filing. The FERC will determine which portions of the initial decision to affirm, reject or amend. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $40 million in annual rate reductions and approximately $210 million in refunds. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests. However, to the extent the shippers are successful in one or more of the complaints or protest proceedings, SFPP estimates that applying the principles of FERC precedent, as applicable, to pending SFPP cases would result in rate reductions and refunds substantially lower than those sought by the shippers.

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. The 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 sought federal appellate review of Opinion 517-A and oral arguments were held on February 15, 2017. On February 21, 2017, the reviewing court delayed the case until the FERC rules on the rehearing requests pending in the 2010 Rate Case. With respect to the 2010 rate case, the FERC issued its decision (Opinion 528-A) on February 18, 2016. The FERC generally upheld its prior determinations, affirmed prior findings of an Administrative Law Judge that certain shippers qualify for lower rates, and required EPNG to file revised pro forma recalculated rates consistent with the terms of Opinions 517-A and 528-A. EPNG and two intervenors sought rehearing of certain aspects of the decision, and the judicial review sought by certain intervenors has been delayed until the FERC issues an order on rehearing. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. With respect to the 2010 rate case, EPNG believes it has an appropriate reserve related to the findings in Opinions 517-A and 528-A.

NGPL and WIC

On January 19, 2017, NGPL and WIC were separately notified by the FERC of rate proceedings against them pursuant to section 5 of the Natural Gas Act (the “Orders”). The matters were set for hearings to determine whether NGPL’s and WIC’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Both WIC and NGPL have reached settlements in principle with their respective customer groups that would resolve all matters set for hearing subject to completion of definitive documents and additional FERC approval. If such definitive documents or approvals are not obtained, an initial Administrative Law Judge decision for each proceeding would be anticipated by late February 2018, with final FERC decisions anticipated by the third quarter of 2018. We do not believe that the ultimate resolution of these proceedings will have a material adverse impact on our results of operations or cash flows from operations.

Trans Mountain Expansion Project Litigation

There are numerous legal challenges pending before the Federal Court of Appeal which have been filed by various governmental and non-governmental organizations, Aboriginal groups or other parties that seek judicial review of the recommendation of the National Energy Board (NEB) and subsequent decision by the Federal Governor in Council to conditionally approve the Trans Mountain Pipeline Expansion Project (the ‘‘Project’’). The petitions allege, among other things, that additional consultation, engagement or accommodation is required and that various non-economic impacts of the Project were not adequately considered. The remedies sought include requests that the NEB recommendation be quashed, that additional consultations be undertaken, and that the order of the Governor in Council approving the Project be quashed. A decision by the Federal Court of Appeal is subject to potential further appeal to the Supreme Court of Canada. Although we believe that each of the foregoing appeals lacks merit, in the event an applicant is successful at the Supreme Court of Canada, among other potential impacts, the NEB recommendation or Governor in Council’s approval may be quashed, permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be implemented, or the Project may be stopped altogether, which could materially impact the overall feasibility or economic benefits of the Project, which in turn would have a material adverse effect on the Project and, consequently, our investment in KML.

In addition to the judicial reviews of the NEB recommendation report and Governor in Council’s order, three judicial review proceedings have been commenced at the Supreme Court of British Columbia (Squamish Nation; the City of Vancouver; and Democracy Watch et al.). The petitions allege a duty and failure to consult or accommodate First Nations, apprehension of bias of decision makers, and generally, among other claims, that the Province ought not to have approved the Project. Each Applicant seeks to quash the Environmental Assessment Certificate that was issued by the BC Environmental Assessment Office. In the event that an applicant for judicial review is successful, among other potential impacts, the Environmental Assessment Certificate may be quashed, provincial permits may be revoked, the Project may be subject to additional significant regulatory reviews, there may be significant changes to the Project plans, further obligations or restrictions may be imposed or the Project may be stopped altogether. In the event that an applicant is unsuccessful at the Supreme Court of British Columbia, they may further seek to appeal the decision to the British Columbia Court of Appeal. Any decision of the British Columbia Court of Appeal may be appealed to the Supreme Court of Canada. A successful appeal at either of these levels could result in the same types of consequences described above.

Other Commercial Matters

Union Pacific Railroad Company Easements & Related Litigation

SFPP and Union Pacific Railroad Company (UPRR) have been engaged in a proceeding to determine the extent, if any, to which 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., et al, , Superior Court of the State of California, County of Los Angeles, Case No. BC319170). 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. SFPP appealed the judgment.

In addition, as part of the second ten-year rent setting period, in 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 review to the California Supreme Court which was denied. In July 2017, UPRR and SFPP reached a settlement of the rental disputes on terms that are confidential and within the right-of-way liability previously recorded for back rent.

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 2015 in California federal court 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 were filed and are pending in federal courts by landowners in Nevada, Arizona and New Mexico. 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, inverse condemnation and accounting arising from defendants’ alleged improper use or occupation of subsurface real property. Plaintiffs’ motions for class certification were denied by the federal district courts in Arizona and California, and plaintiffs are pursuing an appeal to the 9th Circuit Court of Appeals. The New Mexico and Nevada lawsuits have been stayed. 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.

SFPP and UPRR have also engaged in multiple disputes since 2000 over the circumstances and conditions under which SFPP must pay to relocate its pipeline within the UPRR right-of-way. In July 2017, UPRR and SFPP reached a settlement of the relocation disputes on terms that are confidential but which generally require the parties to share and allocate the cost of future relocations. Although the cost sharing mechanism in the settlement is expected to reduce the cost of future relocations, SFPP does not know UPRR’s plans for projects or other activities that would cause pipeline relocations such that it is difficult to quantify the cost of future potential relocations. Such costs could have an adverse effect on our financial position, results of operations, cash flows, and dividends to our shareholders.

Gulf LNG Facility Arbitration

On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received a Notice of Disagreement and Disputed Statements and a Notice of Arbitration from Eni USA Gas Marketing LLC (Eni USA), one of two companies that entered into a terminal use agreement for capacity of the Gulf LNG Facility in Mississippi for an initial term that is not scheduled to expire until the year 2031. Eni USA is an indirect subsidiary of Eni S.p.A., a multi-national integrated energy company headquartered in Milan, Italy. Pursuant to its Notice of Arbitration, Eni USA seeks declaratory and monetary relief based upon its assertion that (i) the terminal use agreement should be terminated because changes in the U.S. natural gas market since the execution of the agreement in December 2007 have “frustrated the essential purpose” of the agreement and (ii) activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC “in connection with a plan to convert the LNG Facility into a liquefaction/export facility have given rise to a contractual right on the part of Eni USA to terminate” the agreement. As set forth in the terminal use agreement, disputes are meant to be resolved by final and binding arbitration. A three-member arbitration panel conducted an arbitration hearing in January 2017. We expect the arbitration panel will issue its decision before the end of the third quarter 2017. Eni USA has indicated that it will continue to pay the amounts claimed to be due pending resolution of the dispute. The successful assertion by Eni USA of its claim to terminate or amend its payment obligations under the agreement prior to the expiration of its initial term could have an adverse effect on the business, financial

position, results of operations, or cash flows of GLNG and distributions to KMI, a 50% shareholder of GLNG. We view the demand for arbitration to be without merit, and we will continue to contest it vigorously.

Brinckerhoff Merger Litigation

In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by a former EPB unitholder on behalf of a class of former unaffiliated unitholders of EPB, seeking to challenge the $9.2 billion merger of EPB into a subsidiary of KMI as part of a series of transactions in November 2014 whereby KMI acquired all of the outstanding equity interests in KMP, KMR, and EPB that KMI and its subsidiaries did not already own. The suit alleges that the merger consideration did not sufficiently compensate EPB unitholders for the value of three derivative suits concerning drop down transactions which the derivative plaintiff lost standing to pursue after the merger and which the present suit now alleges were collectively worth as much as $700 million. The suit claims that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constitutes a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserts claims against KMI and certain individual defendants for allegedly tortiously interfering with and/or aiding and abetting the alleged breach of the limited partnership agreement. Defendants have moved to dismiss the suit. We continue to believe that both the merger and the drop down transactions were appropriate and in the best interests of EPB, and we intend to defend this lawsuit 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 are pending in Nevada federal district 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 district court for further consideration and trial, if necessary, of numerous remaining issues. On May 24, 2016, the district court granted a motion for summary judgment dismissing a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages has been alleged. That ruling has been appealed to the 9^th Circuit Court of Appeals. Tentative settlements have been reached in class actions originally filed in Kansas and Missouri, which settlements are subject to final court approval. In the remaining case, a Wisconsin class action in which approximately $300 million in damages has been alleged against all defendants, the district court denied plaintiff’s motion for class certification. The 9^th Circuit Court of Appeals granted plaintiff’s request for an interlocutory appeal of this ruling. There remains significant uncertainty regarding the validity of the causes of action, the damages asserted and the level of damages, if any, which may be allocated to us in the remaining lawsuits and therefore, our legal exposure, if any, and costs are not currently determinable.

Pipeline Integrity and Releases

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

General

As of June 30, 2017 and December 31, 2016, our total reserve for legal matters was $389 million and $407 million, respectively. The reserve primarily relates to various claims from regulatory proceedings arising in our products and natural gas pipeline segments.

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 laws and regulations, risks of additional costs and liabilities are inherent in pipeline,

terminal and CO₂ field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations, could result in substantial costs and liabilities to us.

We are currently involved in several governmental proceedings involving alleged violations of environmental and safety regulations, including alleged violations of the Risk Management Program and leak detection and repair requirements of the Clean Air Act. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties, individually or in the aggregate, will be material. 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. The EPA issued the FS and the Proposed Plan on June 8, 2016 which included a proposed combination of dredging, capping, and enhanced natural recovery. On January 6, 2017, the EPA issued its Record of Decision (ROD) for the final cleanup plan. The final remedy is more stringent than the remedy proposed in the EPA’s Proposed Plan. The estimated cost increased from approximately $750 million to approximately $1.1 billion and active cleanup is now expected to take as long as 13 years to complete. 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. Our share of responsibility for Portland Harbor Superfund Site costs will not be determined until the ongoing non-judicial allocation process is concluded in several years or a lawsuit is filed that results in a judicial decision allocating responsibility. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the site. In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims asserted by state and federal trustees following their natural resource assessment of the site. At this time, we are unable to reasonably estimate the extent of our potential NRD liability.

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 from 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 and fact discovery is proceeding.

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 is conducting 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. The counterclaim of defendant EPA has been settled, and no viable claims for reimbursement by the other defendants are known to exist.

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 (PRPs) 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 of approximately 70 cooperating parties, referred to as the Cooperating Parties Group (CPG), which has entered into AOCs and is 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 remain pending. Under the second AOC, the CPG 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. On March 4, 2016, the EPA issued its ROD for the lower 8.3 miles of the Passaic River Study area. The final cleanup plan in the ROD is substantially similar to the EPA’s preferred alternative announced on April 11, 2014. On October 5, 2016, the EPA entered into an AOC with one member of the PRP group requiring such member to spend $165 million to perform engineering and design work necessary to begin the cleanup of the lower 8.3 miles of the Passaic River. The design work is expected to take four years to complete and the cleanup is expected to take six years to complete.

In addition, the EPA has notified over 80 other PRPs, including EPEC Polymers and EPEC Oil Trust (the Notice), that the EPA intends to pursue agreements with other “major PRPs” and initiate negotiations over cash buyouts with parties whom the EPA does not consider “major PRPs.” The Notice creates significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD, and provides no guidance as to the EPA’s definition of a “major PRP” or the potential amount or range of cash buyouts. 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.

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. On March 3, 2017, the U.S. Court of Appeals for the Fifth Circuit affirmed the U.S. District Court’s decision. On March 17, 2017, the SLFPA filed a petition seeking en banc review and reconsideration of the decision by the Fifth Circuit, and such petition was denied.

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. 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. On November 12, 2015, the Plaquemines Parish Council adopted a resolution directing its legal counsel in all its Coastal Zone cases to take all actions necessary to cause the dismissal of all such cases. On April 14, 2016, following interventions in the suit by the Louisiana Department of Natural Resources and Attorney General, the Parish Council passed a resolution rescinding its November 12, 2015 resolution that had directed its counsel to dismiss the suit. We intend to continue to vigorously defend the suit.

Vermilion Parish Louisiana Coastal Zone Litigation

On July 28, 2016, the District Attorney for the 15^th Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed suit in the state district court for Vermilion Parish, Louisiana against TGP and 52 other energy companies, alleging that the defendants’ oil and gas and transportation operations associated with the development of several fields in Vermilion Parish (Operational Areas) were conducted in violation of the Coastal Zone Management Act. The suit alleges such operations caused substantial damage to the coastal waters and nearby lands (Coastal Zone) of Vermilion Parish, resulting in the release of pollutants and contaminants into the environment, improper discharge of oil field wastes, the improper use of waste pits and failure to close such pits, and the dredging of canals, which resulted in degradation of the Operational Areas, including erosion of marshes and degradation of terrestrial and aquatic life therein. As a result of such alleged violations of the Coastal Zone Management Act, the suit seeks a judgment against the defendants awarding all appropriate damages, the payment of costs to clear, revegetate, detoxify and otherwise restore the Vermilion Parish Coastal Zone, actual restoration of the affected Coastal Zone to its original condition, and reasonable costs and attorney fees. On September 2, 2016, the case was removed to the United States District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court, and such motion remains pending.

Vintage Assets, Inc. Coastal Erosion Litigation

On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a petition in the 25th Judicial District Court for Plaquemines Parish, Louisiana alleging that its 5,000 acre property is composed of coastal wetlands, and that SNG and TGP failed to maintain pipeline canals and banks, causing widening of the canals, land loss, and damage to the ecology and hydrology of the marsh, in breach of right of way agreements, prudent operating practices, and Louisiana law. The suit also claims that defendants’ alleged failure to maintain pipeline canals and banks constitutes negligence and has resulted in encroachment of the canals, constituting trespass. The suit seeks in excess of $80 million in money damages, including recovery of litigation costs, damages for trespass, and money damages associated with an alleged loss of natural resources and projected reconstruction cost of replacing or restoring wetlands. The suit was removed to the U.S. District Court for the Eastern District of Louisiana. The SNG assets at issue were sold to Highpoint Gas Transmission, LLC in 2011, which was subsequently purchased by American Midstream Partners, LP. In response to SNG’s demand for defense and indemnity, American Midstream Partners agreed to pay 50% of joint defense costs and expenses, with a percentage of indemnity to be determined upon final resolution of the suit. On October 20, 2016, plaintiffs filed an amended complaint naming Highpoint Gas Transmission, LLC as an additional defendant. A non-jury trial is scheduled to begin on September 11, 2017 and we intend to vigorously defend the suit.

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 June 30, 2017 and December 31, 2016, we have accrued a total reserve for environmental liabilities in the amount of $294 million and $302 million, respectively. In addition, as of both June 30, 2017 and December 31, 2016, we have recorded a receivable of $13 million, for expected cost recoveries that have been deemed probable.

10. Recent Accounting Pronouncements

Topic 606

On May 28, 2014, the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers” followed by a series of related accounting standard updates (collectively referred to as “Topic 606”). Topic 606 is designed to create greater revenue recognition and disclosure comparability in financial statements. The provisions of Topic 606 include a five-step process by which an entity will determine revenue recognition, depicting the transfer of goods or services to customers in amounts reflecting the payment to which an entity expects to be entitled in exchange for those goods or services. Topic 606 requires certain disclosures about contracts with customers and provides more comprehensive guidance for transactions such as service revenue, contract modifications, and multiple-element arrangements.

We are in the process of comparing our current revenue recognition policies to the requirements of Topic 606 for each of our revenue categories. While we have not identified any material differences in the amount and timing of revenue recognition for the categories we have reviewed to date, our evaluation is not complete, and we have not concluded on the overall impacts of adopting Topic 606. Topic 606 will require that our revenue recognition policy disclosure include further detail regarding our performance obligations as to the nature, amount, timing, and estimates of revenue and cash flows generated from our contracts with customers. Topic 606 will also require disclosure of significant changes in contract asset and contract liability balances period to period and the amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) as of the end of the reporting period, as applicable. We anticipate utilizing the modified retrospective method to adopt the provisions of this standard effective January 1, 2018, which requires us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) all existing revenue contracts as of January 1, 2018 through a cumulative adjustment to equity. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 will not be revised.

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 was effective January 1, 2017. We adopted ASU No. 2015-11 with no material impact to our financial statements.

ASU No. 2016-02

On February 25, 2016, the FASB issued ASU No. 2016-02, “Leases (Topic 842).” This ASU requires that lessees will be required to recognize assets and liabilities on the balance sheet for the present value of the rights and obligations created by all leases with terms of more than 12 months. The ASU also will require disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases. ASU 2016-02 will be effective for us as of January 1, 2019. We are currently reviewing the effect of ASU No. 2016-02.

ASU No. 2016-09

On March 30, 2016, the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718).” This ASU was issued as part of the FASB’s simplification initiative and affects all entities that issue share-based payment awards to their employees. This ASU covers accounting for income taxes, forfeitures, and statutory tax withholding requirements, as well as classification in the statement of cash flows. ASU No. 2016-09 was effective January 1, 2017. We adopted ASU No. 2016-09 with no material impact to our financial statements. See Note 8.

ASU No. 2016-13

On June 16, 2016, the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” This ASU modifies the impairment model to utilize an expected loss methodology

in place of the currently used incurred loss methodology, which will result in the more timely recognition of losses. ASU No. 2016-13 will be effective for us as of January 1, 2020. We are currently reviewing the effect of ASU No. 2016-13.

ASU No. 2016-18

On November 17, 2016, the FASB issued ASU No. 2016-18, “Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force).” This ASU requires the statement of cash flows to explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents are to be included with cash and cash equivalents when reconciling the beginning of period and end of period amounts shown on the statement of cash flows. ASU No. 2016-18 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-04

On January 26, 2017, the FASB issued ASU No. 2017-04, “Simplifying the Test for Goodwill Impairment (Topic 350)” to simplify the accounting for goodwill impairment. The guidance removes Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. A goodwill impairment will now be the amount by which a reporting unit’s carrying value exceeds its fair value, not to exceed the carrying amount of goodwill. ASU No. 2017-04 will be effective for us as of January 1, 2020. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-05

On February 22, 2017, the FASB issued ASU No. 2017-05, “Other Income-Gains and Losses from the Derecognition of Nonfinancial Assets (Subtopic 610-20): Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets.” This ASU clarifies the scope and accounting of a financial asset that meets the definition of an “in-substance nonfinancial asset” and defines the term “in-substance nonfinancial asset.” This ASU also adds guidance for partial sales of nonfinancial assets. ASU 2017-05 will be effective at the same time Topic 606, Revenue from Contracts with Customers, is effective. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-07

On March 10, 2017, the FASB issued ASU No. 2017-07, “Compensation - Retirement Benefits (Topic 715).” This ASU requires an employer to disaggregate the service cost component from the other components of net benefit cost, allow only the service cost component of net benefit cost to be eligible for capitalization, and how to present the service cost component and the other components of net benefit cost in the income statement. ASU No. 2017-07 will be effective for us as of January 1, 2018. We are currently reviewing the effect of this ASU to our financial statements.

11. Guarantee of Securities of Subsidiaries

KMI, along with its direct subsidiary KMP, are issuers of certain public debt securities. KMI, KMP and substantially all of KMI’s wholly owned domestic subsidiaries are parties to 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 issuer 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 or KMP is in the same position with respect to the net assets, income and cash flows of KMI and the Subsidiary Issuer 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 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 issuer in separate columns in this single set of condensed consolidating financial statements.

On September 30, 2016, Copano (previously reflected as a Subsidiary Issuer and Guarantor) repaid the $332 million principal amount of its 7.125% senior notes due 2021. Copano continues to be a subsidiary guarantor under the cross guarantee agreement mentioned above. For all periods presented, financial statement balances and activities for Copano are now reflected within the Subsidiary Guarantor column, and the Subsidiary Issuer and Guarantor-Copano column has been eliminated.

On September 1, 2016, we sold a 50% equity interest in SNG. Subsequent to the transaction, we deconsolidated SNG and now account for our equity interest in SNG as an equity investment. Our wholly owned subsidiary which holds our interest in SNG is reflected within the Subsidiary Guarantors column of these condensed consolidating financial statements.

Excluding fair value adjustments, as of June 30, 2017, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $13,678 million, $18,885 million, and $3,535 million, respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying June 30, 2017 condensed consolidating balance sheet is approximately $165 million of capital lease obligations that are not subject to the cross guarantee agreement.

The accounts within the Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, 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 activities eliminate in consolidation and are presented separately in the accompanying condensed consolidating 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.

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended June 30, 2017 (In Millions) (Unaudited)

	Parent Issuer and Guarantor				Subsidiary Issuer and Guarantor - KMP				Subsidiary Guarantors					Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	9			$	—			$	3,002		$	—	$	402		$	(45	)	$	3,368

Operating Costs, Expenses and Other
Costs of sales	—				—				1,041			—		83			(34		)	1,090
Depreciation, depletion and amortization	4				—				488			—		85			—			577
Other operating expenses	10				—				686			—		94			(11		)	779
Total Operating Costs, Expenses and Other	14				—				2,215					262			(45		)	2,446

Operating (loss) income	(5		)		—				787					140			—			922

Other Income (Expense)
Earnings from consolidated subsidiaries	747			—	739				110			—		17			(1,613		)	—
Earnings from equity investments	—			—	—				135			—		—			—			135
Interest, net	(177		)	—	4				(273		)	—		(17		)	—			(463		)
Amortization of excess cost of equity investments and other, net	—			—	—				1			—		4			—			5

Income Before Income Taxes	565				743				760					144			(1,613		)	599

Income Tax Expense	(189		)	—	(1		)		(18		)	—		(8		)	—			(216		)

Net Income	376				742				742					136			(1,613		)	383
Net Income Attributable to Noncontrolling Interests	—			—	—				—			—		—			(7		)	(7		)

Net Income Attributable to Controlling Interests	376				742				742					136			(1,620		)	376

Preferred Stock Dividends	(39		)	—	—				—			—		—			—			(39		)
Net Income Available to Common Stockholders	$	337			$	742			$	742				$	136		$	(1,620	)	$	337

Net Income	$	376			$	742			$	742				$	136		$	(1,613	)	$	383
Total other comprehensive income	59			—	168				194			—		52			(395		)	78
Comprehensive income	435				910				936					188			(2,008		)	461
Comprehensive income attributable to noncontrolling interests	—			—	—				—			—		—			(26		)	(26		)
Comprehensive income attributable to controlling interests	$	435			$	910		—	$	936				$	188		$	(2,034	)	$	435

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended June 30, 2016 (In Millions) (Unaudited)

	Parent Issuer and Guarantor				Subsidiary Issuer and Guarantor - KMP				Subsidiary Guarantors					Subsidiary Non-Guarantors					Consolidating Adjustments			Consolidated KMI
Total Revenues	$	8			$	—			$	2,777		$	—	$	371		$	—	$	(12	)	$	3,144

Operating Costs, Expenses and Other
Costs of sales	—				—				693					60					(1		)	752
Depreciation, depletion and amortization	4				—				470			—		78			—		—			552
Other operating expenses	30				2				683			—		196			—		(11		)	900
Total Operating Costs, Expenses and Other	34				2				1,846					334					(12		)	2,204

Operating (loss) income	(26		)		(2		)		931					37					—			940

Other Income (Expense)
Earnings from consolidated subsidiaries	752			—	734			—	52			—		17			—		(1,555		)	—
Earnings from equity investments	—			—	—			—	118			—		—			—		—			118
Interest, net	(176		)	—	34			—	(316		)	—		(13		)	—		—			(471		)
Amortization of excess cost of equity investments and other, net	1			—	—			—	(6		)	—		6			—		—			1

Income Before Income Taxes	551				766				779					47					(1,555		)	588

Income Tax Expense	(179		)	—	(1		)	—	(16		)	—		(17		)	—		—			(213		)

Net Income	372				765				763					30					(1,555		)	375
Net Income Attributable to Noncontrolling Interests	—			—	—			—	—			—		—			—		(3		)	(3		)

Net Income Attributable to Controlling Interests	372				765				763					30					(1,558		)	372

Preferred Stock Dividends	(39		)	—	—			—	—			—		—			—		—			(39		)
Net Income Available to Common Stockholders	333				765				763					30					(1,558		)	333

Net Income	$	372			$	765			$	763				$	30				$	(1,555	)	$	375
Total other comprehensive (loss) income	(140		)	—	(213		)	—	(223		)	—		8			—		428			(140		)
Comprehensive income	232				552				540					38					(1,127		)	235
Comprehensive income attributable to noncontrolling interests	—			—	—			—	—			—		—			—		(3		)	(3		)
Comprehensive income attributable to controlling interests	$	232			$	552			$	540				$	38				$	(1,130	)	$	232

Condensed Consolidating Statements of Income and Comprehensive Income for the Six Months Ended June 30, 2017 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	18		$	—		$	6,060		$	777		$	(63	)	$	6,792

Operating Costs, Expenses and Other
Costs of sales	—			—			2,058			154			(41		)	2,171
Depreciation, depletion and amortization	8			—			964			163			—			1,135
Other operating expenses	25			—			1,354			227			(22		)	1,584
Total Operating Costs, Expenses and Other	33			—			4,376			544			(63		)	4,890

Operating (loss) income	(15		)	—			1,684			233			—			1,902

Other Income (Expense)
Earnings from consolidated subsidiaries	1,593			1,570			212			35			(3,410		)	—
Earnings from equity investments	—			—			310			—			—			310
Interest, net	(354		)	10			(555		)	(29		)	—			(928		)
Amortization of excess cost of equity investments and other, net	—			—			(2		)	8			—			6

Income Before Income Taxes	1,224			1,580			1,649			247			(3,410		)	1,290

Income Tax Expense	(408		)	(3		)	(35		)	(16		)	—			(462		)

Net Income	816			1,577			1,614			231			(3,410		)	828
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(12		)	(12		)

Net Income Attributable to Controlling Interests	816			1,577			1,614			231			(3,422		)	816

Preferred Stock Dividends	(78		)	—			—			—			—			(78		)
Net Income Available to Common Stockholders	$	738		$	1,577		$	1,614		$	231		$	(3,422	)	$	738

Net Income	$	816		$	1,577		$	1,614		$	231		$	(3,410	)	$	828
Total other comprehensive income	127			274			293			73			(621		)	146
Comprehensive income	943			1,851			1,907			304			(4,031		)	974
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(31		)	(31		)
Comprehensive income attributable to controlling interests	$	943		$	1,851		$	1,907		$	304		$	(4,062	)	$	943

Condensed Consolidating Statements of Income and Comprehensive Income for the Six Months Ended June 30, 2016 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	17		$	—		$	5,602		$	741		$	(21	)	$	6,339

Operating Costs, Expenses and Other
Costs of sales	—			—			1,345			136			2			1,483
Depreciation, depletion and amortization	9			—			934			160			—			1,103
Other operating expenses	49			4			1,499			468			(23		)	1,997
Total Operating Costs, Expenses and Other	58			4			3,778			764			(21		)	4,583

Operating (loss) income	(41		)	(4		)	1,824			(23		)	—			1,756

Other Income (Expense)
Earnings from consolidated subsidiaries	1,410			1,331			75			31			(2,847		)	—
Earnings from equity investments	—			—			212			—			—			212
Interest, net	(346		)	97			(637		)	(26		)	—			(912		)
Amortization of excess cost of equity investments and other, net	1			—			(11		)	10			—			—

Income (Loss) Before Income Taxes	1,024			1,424			1,463			(8		)	(2,847		)	1,056

Income Tax Expense	(337		)	(3		)	(10		)	(17		)	—			(367		)

Net Income (Loss)	687			1,421			1,453			(25		)	(2,847		)	689
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(2		)	(2		)

Net Income (Loss) Attributable to Controlling Interests	687			1,421			1,453			(25		)	(2,849		)	687

Preferred Stock Dividends	(78		)	—			—			—			—			(78		)
Net Income (Loss) Available to Common Stockholders	609			1,421			1,453			(25		)	(2,849		)	609

Net Income (Loss)	$	687		$	1,421		$	1,453		$	(25	)	$	(2,847	)	$	689
Total other comprehensive (loss) income	(93		)	(161		)	(229		)	132			258			(93		)
Comprehensive income	594			1,260			1,224			107			(2,589		)	596
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(2		)	(2		)
Comprehensive income attributable to controlling interests	$	594		$	1,260		$	1,224		$	107		$	(2,591	)	$	594

Condensed Consolidating Balance Sheets as of June 30, 2017 (In Millions) (Unaudited)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	36	$	—	$	—	$	422	$	(6	)	$	452
Other current assets - affiliates	9,432		4,949		15,990		766		(31,137		)	—
All other current assets	246		87		1,740		206		(5		)	2,274
Property, plant and equipment, net	253		—		30,770		8,400		—			39,423
Investments	665		—		6,648		129		—			7,442
Investments in subsidiaries	27,176		28,902		5,118		4,025		(65,221		)	—
Goodwill	13,789		22		5,168		3,180		—			22,159
Notes receivable from affiliates	1,228		20,794		1,195		514		(23,731		)	—
Deferred income taxes	5,963		—		—		—		(2,344		)	3,619
Other non-current assets	158		208		4,287		181		—			4,834
Total assets	$	58,946	$	54,962	$	70,916	$	17,823	$	(122,444	)	$	80,203

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,174	$	975	$	806	$	269	$	—		$	3,224
Other current liabilities - affiliates	6,784		15,362		8,317		674		(31,137		)	—
All other current liabilities	339		346		1,923		542		(11		)	3,139
Long-term debt	12,841		18,293		3,299		667		—			35,100
Notes payable to affiliates	1,937		448		20,983		363		(23,731		)	—
Deferred income taxes	—		—		712		1,632		(2,344		)	—
All other long-term liabilities and deferred credits	722		100		1,239		465		—			2,526
Total liabilities	23,797		35,524		37,279		4,612		(57,223		)	43,989

Stockholders’ equity
Total KMI equity	35,149		19,438		33,637		13,211		(66,286		)	35,149
Noncontrolling interests	—		—		—		—		1,065			1,065
Total stockholders’ Equity	35,149		19,438		33,637		13,211		(65,221		)	36,214
Total Liabilities and Stockholders’ Equity	$	58,946	$	54,962	$	70,916	$	17,823	$	(122,444	)	$	80,203

Condensed Consolidating Balance Sheets as of December 31, 2016 (In Millions)

	Parent Issuer and Guarantor		Subsidiary Issuer and Guarantor - KMP		Subsidiary Guarantors		Subsidiary Non-Guarantors		Consolidating Adjustments			Consolidated KMI
ASSETS
Cash and cash equivalents	$	471	$	—	$	9	$	205	$	(1	)	$	684
Other current assets - affiliates	5,739		1,999		13,207		655		(21,600		)	—
All other current assets	269		139		1,935		205		(3		)	2,545
Property, plant and equipment, net	242		—		30,795		7,668		—			38,705
Investments	665		2		6,236		124		—			7,027
Investments in subsidiaries	26,907		29,421		4,307		4,028		(64,663		)	—
Goodwill	13,789		22		5,167		3,174		—			22,152
Notes receivable from affiliates	516		21,608		1,132		412		(23,668		)	—
Deferred income taxes	6,647		—		—		—		(2,295		)	4,352
Other non-current assets	72		206		4,455		107		—			4,840
Total assets	$	55,317	$	53,397	$	67,243	$	16,578	$	(112,230	)	$	80,305

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,286	$	600	$	687	$	123	$	—		$	2,696
Other current liabilities - affiliates	3,551		13,299		4,197		553		(21,600		)	—
All other current liabilities	432		362		2,016		422		(4		)	3,228
Long-term debt	13,308		19,277		4,095		674		—			37,354
Notes payable to affiliates	1,533		448		20,520		1,167		(23,668		)	—
Deferred income taxes	—		—		681		1,614		(2,295		)	—
Other long-term liabilities and deferred credits	776		111		821		517		—			2,225
Total liabilities	20,886		34,097		33,017		5,070		(47,567		)	45,503

Stockholders’ equity
Total KMI equity	34,431		19,300		34,226		11,508		(65,034		)	34,431
Noncontrolling interests	—		—		—		—		371			371
Total stockholders’ Equity	34,431		19,300		34,226		11,508		(64,663		)	34,802
Total Liabilities and Stockholders’ Equity	$	55,317	$	53,397	$	67,243	$	16,578	$	(112,230	)	$	80,305

Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 2017 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP				Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(1,460	)	$	2,076			$	5,813		$	509		$	(4,772	)	$	2,166

Cash flows from investing activities
Acquisitions of assets and investments, net of cash acquired	—			—				(4		)	—			—			(4		)
Capital expenditures	(23		)	—				(1,062		)	(251		)	—			(1,336		)
Sales of property, plant and equipment, and other net assets, net of removal costs	5			—				45			21			—			71
Contributions to investments	(215		)	—				(327		)	(6		)	—			(548		)
Distributions from equity investments in excess of cumulative earnings	1,025			—				195			—			(1,006		)	214
Funding (to) from affiliates	(2,806		)	657				(4,013		)	(482		)	6,644			—
Other, net	(8		)	30				—			8			—			30
Net cash (used in) provided by investing activities	(2,022		)	687				(5,166		)	(710		)	5,638			(1,573		)

Cash flows from financing activities
Issuances of debt	4,187			—				—			143			—			4,330
Payments of debt	(4,858		)	(600		)		(659		)	(7		)	—			(6,124		)
Debt issue costs	(6		)	—				—			(54		)	—			(60		)
Cash dividends - common shares	(560		)	—				—			—			—			(560		)
Cash dividends - preferred shares	(78		)	—				—			—			—			(78		)
Funding from (to) affiliates	4,356			406				2,444			(562		)	(6,644		)	—
Contributions from investment partner	—			—				415			—			—			415
Contributions from parents/net proceeds from KML IPO	—			—				(2		)	1,253			(1,251		)	—
Contributions from noncontrolling interests - net proceeds from KML IPO	7			—			—	—			—			1,240			1,247
Contributions from noncontrolling interests - other	—			—				—			—			11			11
Distributions to parents	—			(2,569		)		(2,854		)	(365		)	5,788			—
Distributions to noncontrolling interests	—			—				—			—			(15		)	(15		)
Other, net	(1		)	—				—			—			—			(1		)
Net cash provided by (used in) financing activities	3,047			(2,763		)		(656		)	408			(871		)	(835		)

Effect of exchange rate changes on cash and cash equivalents	—			—				—			10			—			10

Net (decrease) increase in cash and cash equivalents	(435		)	—				(9		)	217			(5		)	(232		)
Cash and cash equivalents, beginning of period	471			—				9			205			(1		)	684
Cash and cash equivalents, end of period	$	36		$	—			$	—		$	422		$	(6	)	$	452

Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 2016 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(1,949	)	$	2,976		$	5,368		$	326		$	(4,376	)	$	2,345

Cash flows from investing activities
Acquisitions of assets and investments, net of cash acquired	(2		)	—			(331		)	—			—			(333		)
Capital expenditures	(37		)	—			(929		)	(504		)	—			(1,470		)
Sales of property, plant and equipment, and other net assets, net of removal costs	—			—			220			—			—			220
Contributions to investments	(343		)	—			(13		)	(7		)	—			(363		)
Distributions from equity investments in excess of cumulative earnings	1,443			298			68			—			(1,728		)	81
Funding to affiliates	(1,670		)	(770		)	(2,416		)	(228		)	5,084			—
Other, net	—			(54		)	37			2			—			(15		)
Net cash used in investing activities	(609		)	(526		)	(3,364		)	(737		)	3,356			(1,880		)

Cash flows from financing activities
Issuances of debt	6,847			—			—			—			—			6,847
Payments of debt	(5,191		)	(500		)	(1,104		)	(5		)	—			(6,800		)
Debt issue costs	(6		)	—			—			—			—			(6		)
Cash dividends - common shares	(559		)	—			—			—			—			(559		)
Cash dividends - preferred shares	(76		)	—			—			—			—			(76		)
Funding from affiliates	1,429			882			2,333			440			(5,084		)	—
Contributions from parents	—			—			—			87			(87		)	—
Contributions from noncontrolling interests	—			—			—			—			87			87
Distributions to parents	—			(2,832		)	(3,234		)	(90		)	6,156			—
Distributions to noncontrolling interests	—			—			—			—			(11		)	(11		)
Other, net	(1		)	—			—			—			—			(1		)
Net cash provided by (used in) financing activities	2,443			(2,450		)	(2,005		)	432			1,061			(519		)

Effect of exchange rate changes on cash and cash equivalents	—			—			—			5			—			5

Net (decrease) increase in cash and cash equivalents	(115		)	—			(1		)	26			41			(49		)
Cash and cash equivalents, beginning of period	123			—			12			142			(48		)	229
Cash and cash equivalents, end of period	$	8		$	—		$	11		$	168		$	(7	)	$	180

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 2016 Form 10-K.

Sale of Approximate 30% Interest in our Canadian Business

On May 30, 2017, our indirectly owned subsidiary, KML, completed an IPO of 102,942,000 restricted voting shares at a price to the public of C$17.00 per restricted voting share for total gross proceeds of approximately C$1,750 million. The net proceeds of C$1,676 million (USD $1,299 million) from the IPO were used by KML to indirectly acquire from us an approximate 30% interest in a limited partnership that holds our Canadian business with us retaining the remaining 70% interest. We used the proceeds from KML to pay down debt.

The portion of the Canadian business operations that we sold to the public on May 30, 2017 represented Canadian assets that are included in our Kinder Morgan Canada, Terminals and Products Pipelines business segments and included the Trans Mountain Pipeline system (including related terminals assets), Trans Mountain Expansion Project, the Puget Sound and Jet Fuel Pipeline systems, the Canadian portion of the Cochin Pipeline system, the Vancouver Wharves Terminal and the North 40 Terminal; as well as three jointly controlled investments: the Edmonton Rail Terminal, the Alberta Crude Terminal and the Base Line Terminal.

In addition, upon completion of the IPO, we announced our final investment decision for the Trans Mountain Expansion Project. Construction on the Trans Mountain Expansion Project, a C$7.4 billion project, is expected to begin in September 2017 with completion expected in December 2019.

Results of Operations

Overview

Our management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below under “—Non-GAAP Measures,” distributable cash flow, or DCF, and Segment EBDA before certain items. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses, interest expense, net, and income taxes. 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.

Segment results for the three and six months ended June 30, 2016 have been retrospectively adjusted to reflect the elimination of the Other segment as a reportable segment. The activities that previously comprised the Other segment are now presented within Corporate non-segment activities in reconciling to the consolidated totals in the respective segment reporting tables. The Other segment had historically been comprised primarily of legacy operations of acquired businesses not associated with our ongoing operations. These business activities have since been sold or have otherwise ceased. In addition, the Other segment included certain company owned real estate assets which are primarily leased to our operating subsidiaries as well as third party tenants. This activity is now reflected within Corporate activity. In addition, the portions of interest income and income tax expense previously allocated to our business segments are now included in “Interest expense, net” and “Income tax expense” for all periods presented in the following tables.

Consolidated Earnings Results



	Three Months Ended June 30,
	2017			2016			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	907		$	967		$	(60	)	(6	)%
CO₂	221			204			17			8	%
Terminals	304			302			2			1	%
Products Pipelines	324			292			32			11	%
Kinder Morgan Canada	43			46			(3		)	(7	)%
Total Segment EBDA(b)	1,799			1,811			(12		)	(1	)%
DD&A	(577		)	(552		)	(25		)	(5	)%
Amortization of excess cost of equity investments	(15		)	(16		)	1			6	%
General and administrative and corporate charges(c)	(145		)	(184		)	39			21	%
Interest, net(d)	(463		)	(471		)	8			2	%
Income before income taxes	599			588			11			2	%
Income tax expense	(216		)	(213		)	(3		)	(1	)%
Net income	383			375			8			2	%
Net income attributable to noncontrolling interests	(7		)	(3		)	(4		)	(133	)%
Net income attributable to Kinder Morgan, Inc.	376			372			4			1	%
Preferred Stock Dividends	(39		)	(39		)	—			—	%
Net income available to common stockholders	$	337		$	333		$	4		1	%



	Six Months Ended June 30,
	2017			2016			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,962		$	1,961		$	1		—	%
CO₂	439			391			48			12	%
Terminals	611			562			49			9	%
Products Pipelines	611			469			142			30	%
Kinder Morgan Canada	86			92			(6		)	(7	)%
Total Segment EBDA(b)	3,709			3,475			234			7	%
DD&A	(1,135		)	(1,103		)	(32		)	(3	)%
Amortization of excess cost of equity investments	(30		)	(30		)	—			—	%
General and administrative and corporate charges(c)	(326		)	(374		)	48			13	%
Interest, net(d)	(928		)	(912		)	(16		)	(2	)%
Income before income taxes	1,290			1,056			234			22	%
Income tax expense	(462		)	(367		)	(95		)	(26	)%
Net income	828			689			139			20	%
Net income attributable to noncontrolling interests	(12		)	(2		)	(10		)	(500	)%
Net income attributable to Kinder Morgan, Inc.	816			687			129			19	%
Preferred Stock Dividends	(78		)	(78		)	—			—	%
Net income available to common stockholders	$	738		$	609		$	129		21	%

_______


(a)	Includes revenues, earnings from equity investments, and other, net, less operating expenses, other expense (income), net, losses on impairments and divestitures, net and gain on impairments and divestitures of equity investments, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes.

Certain items affecting Total Segment EBDA (see “—Non-GAAP Measures” below)

(b)

Three and six month 2017 amounts include a net increase in earnings of $42 million and $79 million, respectively, and three and six month 2016 amounts include net decreases in earnings of $12 million and $311 million, respectively, related to the combined effect of the certain items impacting Total Segment EBDA. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”

(c)

Three and six month 2017 amounts include a decrease in expense of $4 million and an increase in expense of $3 million, respectively, and three and six month 2016 amounts include net increases in expense of $19 million and $24 million, respectively, related to the combined effect of the certain items related to general and administrative expense and corporate charges disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

(d)

Three and six month 2017 amounts include net decreases in expense of $5 million and $17 million, respectively, and three and six month 2016 amounts include net decreases in expense of $40 million and $109 million, respectively, related to the combined effect of the certain items related to interest expense, net of unallocable interest income disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

The certain item totals reflected in footnotes (b), (c), and (d) to the table above accounted for $42 million of the increase in income before income taxes for the second quarter of 2017, as compared to the same prior year period (representing the difference between the increases of $51 million and $9 million in income before income taxes for the second quarters of 2017 and 2016, respectively) and an increase of $319 million in income before income taxes for the six months ended June 30, 2017, when compared to the same prior year period (representing the difference between an increase of $93 million and a decrease of $226 million in income before income taxes for the six months ended June 30, 2017 and 2016, respectively). After giving effect to these certain items, the remaining decreases in income before income taxes from the prior year quarter and year-to-date were $31 million (5%) and $85 million (7%), respectively. The quarter-to-date and year-to-date decreases from 2016 are primarily attributable to decreased performance from our Natural Gas Pipelines business segment, largely associated with our sale of a 50% interest in SNG to The Southern Company on September 1, 2016, and increased DD&A expense partially offset by decreased general and administrative expense and by decreased interest expense.

Non-GAAP Financial Measures

Our non-GAAP performance measures are DCF, both in the aggregate and per share, and Segment EBDA before certain items. Certain items are items that are required by GAAP to be reflected in net income, but typically either (i) do not have a cash impact (for example, asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example certain legal settlements, hurricane impacts and casualty losses).

Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP performance 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 is a significant performance measure used by us and by external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate cash earnings after servicing our debt and preferred stock dividends, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as common stock dividends, stock repurchases, retirement of debt, or expansion capital expenditures. Management uses this performance measure and believes it provides users of our financial statements a useful performance measure reflective of our business’s ability to generate cash earnings to supplement the comparable GAAP measure. We believe the GAAP measure most directly comparable to DCF is net income available to common stockholders. A reconciliation of DCF to net income available to common stockholders is provided in the table below. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends.

Segment EBDA Before Certain Items

Segment EBDA before certain items is used by management in its analysis of segment performance and management of our business. General and administrative expenses are generally not under the control of our segment operating managers, and therefore, are not included when we measure business segment operating performance. We believe Segment EBDA before certain items is a significant performance metric because it provides us and external users of our financial statements additional insight into the ability of our segments to generate segment cash earnings on an ongoing basis. We believe it is useful to investors because it is a performance measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Segment EBDA before certain items is segment earnings before DD&A and amortization of excess cost of equity investments (Segment EBDA).

In the tables for each of our business segments under “— Segment Earnings Results” below, Segment EBDA before certain items is calculated by adjusting the Segment EBDA for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables.

Reconciliation of Net Income Available to Common Stockholders to DCF



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except per share amounts)
Net Income Available to Common Stockholders	$	337		$	333		$	738		$	609
Add/(Subtract):
Certain items before book tax(a)	(51		)	(9		)	(93		)	226
Book tax certain items(b)	17			1			29			(102		)
Certain items after book tax	(34		)	(8		)	(64		)	124

Noncontrolling interest certain items(c)	1			(3		)	1			(9		)
Net income available to common stockholders before certain items	304			322			675			724
Add/(Subtract):
DD&A expense(d)	686			656			1,357			1,308
Total book taxes(e)	225			236			486			515
Cash taxes(f)	(48		)	(37		)	(45		)	(39		)
Other items(g)	11			10			24			20
Sustaining capital expenditures(h)	(156		)	(137		)	(260		)	(245		)
DCF	$	1,022		$	1,050		$	2,237		$	2,283

Weighted average common shares outstanding for dividends(i)	2,239			2,237			2,239			2,237
DCF per common share	$	0.46		$	0.47		$	1.00		$	1.02
Declared dividend per common share	$	0.125		$	0.125		$	0.250		$	0.250

_______

(a)

Consists of certain items summarized in footnotes (b) through (d) to the “—Results of Operations—Consolidated Earnings Results” tables included above, 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 and Corporate Charges, Interest, net and Noncontrolling Interests.”


(b)	Represents income tax provision on certain items, plus discrete income tax certain items.


(c)	Represents noncontrolling interests share of certain items.

(d)

Includes DD&A and amortization of excess cost of equity investments. Three and six month 2017 amounts also include $94 million and $192 million, respectively, and three and six month 2016 amounts also include $88 million and $175 million, respectively, of our share of certain equity investees' DD&A, net of the DD&A associated with noncontrolling interests in KML and consolidating joint venture partners’ share of DD&A.


(e)	Excludes book tax certain items. Three and six month 2017 amounts also include $26 million and $53 million, respectively, and three and six month 2016 amounts also include $24 million and $46 million, respectively, of our share of taxable equity investees’ book tax expense.


(f)	Three and six month 2017 amounts also include $(45) million for both periods, and three and six month 2016 amounts include $(30) million and $(34) million, respectively, of our share of taxable equity investees’ cash taxes.


(g)	Consists primarily of non-cash compensation associated with our restricted stock program.


(h)	Three and six month 2017 amounts include $(27) million and $(45) million, respectively, and three and six month 2016 amounts include $(20) million and $(42) million, respectively, of our share of equity investees’ sustaining capital expenditures.


(i)	Includes restricted stock awards that participate in common share dividends.

Segment Earnings Results

Natural Gas Pipelines



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except operating statistics)
Revenues(a)	$	2,095		$	1,883		$	4,266		$	3,854
Operating expenses	(1,312		)	(1,004		)	(2,584		)	(1,943		)
Loss on impairments and divestitures, net(b)	—			(5		)	—			(121		)
Earnings from equity investments(b)	109			84			255			156
Other, net	15			9			25			15
Segment EBDA(b)	907			967			1,962			1,961
Certain items(b)	(2		)	(8		)	(38)			130
Segment EBDA before certain items	$	905		$	959		$	1,924		$	2,091

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	218		12		%	$	397		10		%
Segment EBDA before certain items	$	(54	)	(6		)%	$	(167	)	(8		)%

Natural gas transport volumes (BBtu/d)(c)	28,187			27,414			28,753			28,171
Natural gas sales volumes (BBtu/d)(c)	2,247			2,281			2,405			2,306
Natural gas gathering volumes (BBtu/d)(c)	2,673			2,993			2,693			2,993
Crude/condensate gathering volumes (MBbl/d)(c)	261			299			267			299

_______

Certain items affecting Segment EBDA

(a)

Three and six month 2017 amounts include increases in revenue of $7 million and $22 million, respectively, and three and six month 2016 amounts include decreases in revenue of $26 million and $32 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. Three and six month 2016 amounts also include increases in revenue of $39 million for both periods associated with revenue collected on a customer’s early buyout of a long-term natural gas storage contract.

(b)

In addition to the revenue certain items described in footnote (a) above: three and six month 2017 amounts also include decreases in earnings of $5 million and $6 million, respectively, from other certain items. Also, six month 2017 amount includes an increase in earnings from equity investments of $22 million on the sale of a claim related to the early termination of a long-term natural gas transportation contract of an equity investee as a result of a customer bankruptcy proceeding, and three and six month 2016 amounts also include decreases in earnings of $5 million and $16 million, respectively, related to losses on impairments and divestitures, and six month 2016 amount also includes decreases in earnings of (i) $106 million of project write-offs; (ii) $13 million related to an equity investment impairment; and (iii) $2 million from other certain items.

Other


(c)	Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included at our ownership share for the entire period, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2017 and 2016:

Three months ended June 30, 2017 versus Three months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
SNG	$	(74	)	(75	)%	$	(127	)	(95	)%
CIG	(14		)	(22	)%	(12		)	(14	)%
Hiland Midstream	(12		)	(23	)%	41			29	%
South Texas Midstream	(9		)	(13	)%	(5		)	(2	)%
TGP	40			16	%	38			11	%
Elba Express	10			43	%	12			55	%
Texas Intrastate Natural Gas Pipeline Operations	8			11	%	274			51	%
All others (including eliminations)	(3		)	(1	)%	(3		)	(1	)%
Total Natural Gas Pipelines	$	(54	)	(6	)%	$	218		12	%

Six months ended June 30, 2017 versus Six months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
SNG	$	(157	)	(73	)%	$	(265	)	(95	)%
CIG	(29		)	(20	)%	(27		)	(15	)%
Hiland Midstream	(12		)	(12	)%	90			36	%
South Texas Midstream	(24		)	(17	)%	(8		)	(2	)%
TGP	36			6	%	38			5	%
Elba Express	20			44	%	22			49	%
Texas Intrastate Natural Gas Pipeline Operations	9			5	%	542			48	%
All others (including eliminations)	(10		)	(1	)%	5			1	%
Total Natural Gas Pipelines	$	(167	)	(8	)%	$	397		10	%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2017 and 2016:


•	decreases of $74 million (75%) and $157 million (73%), respectively, from SNG due to our sale of a 50% interest in SNG to The Southern Company on September 1, 2016;


•	decreases of $14 million (22%) and $29 million (20%), respectively, from CIG primarily due to a decrease in tariff rates effective January 1, 2017 as a result of a rate case settlement entered into in 2016;

•

decreases of $12 million (23%) and $12 million (12%), respectively, from Hiland Midstream primarily due to lower crude oil margins driven by lower crude oil gathering and delivery volumes. The increase revenues of $41 million and $90 million, respectively, resulted primarily from an increase in natural gas revenue due to higher commodity prices which was largely offset by a corresponding increase in costs of sales;


•	decreases of $9 million (13%) and $24 million (17%), respectively, from South Texas Midstream primarily due to lower service revenues resulting primarily from lower volumes partially offset by higher natural gas and NGL prices;


•	increases of $40 million (16%) and $36 million (6%), respectively, from TGP primarily due to higher firm transportation revenues driven by incremental capacity sales and an expansion project placed in service fourth quarter 2016;


•	increases of $10 million (43%) and $20 million (44%), respectively, from Elba Express primarily due to an expansion project placed in service in December 2016; and

•

increases of $8 million (11%) and $9 million (5%), respectively, from our Texas intrastate natural gas pipeline operations (including the operations of its Kinder Morgan Tejas, Border, Kinder Morgan Texas, North Texas and Mier-Monterrey Mexico pipeline systems) primarily due to higher transportation margins as a result of higher volumes and higher park and loan revenues partially offset by lower storage margins. The increase in revenues of $274 million and $542 million, respectively, resulted primarily from an increase in sales revenue due to higher commodity prices which was largely offset by a corresponding increase in costs of sales.

CO2



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except operating statistics)
Revenues(a)	$	307		$	304		$	610		$	606
Operating expenses	(95		)	(102		)	(192		)	(200		)
Gain (loss) on impairments and divestitures, net(b)	—			1			1			(20		)
Other expense	—			(1		)	—			—
Earnings from equity investments(b)	9			2			20			5
Segment EBDA(b)	221			204			439			391
Certain items(b)	(1		)	24			3			61
Segment EBDA before certain items	$	220		$	228		$	442		$	452

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(16	)	(5		)%	$	(20	)	(3		)%
Segment EBDA before certain items	$	(8	)	(4		)%	$	(10	)	(2		)%

Southwest Colorado CO₂ production (gross)(Bcf/d)(c)	1.3			1.2			1.3			1.2
Southwest Colorado CO₂ production (net)(Bcf/d)(c)	0.6			0.6			0.7			0.6
SACROC oil production (gross)(MBbl/d)(d)	27.4			29.7			27.9			30.1
SACROC oil production (net)(MBbl/d)(e)	22.8			24.8			23.2			25.1
Yates oil production (gross)(MBbl/d)(d)	17.4			18.7			17.6			18.9
Yates oil production (net)(MBbl/d)(e)	7.7			8.3			7.8			8.4
Katz, Goldsmith and Tall Cotton oil production (gross)(MBbl/d)(d)	8.0			6.8			7.6			6.8
Katz, Goldsmith and Tall Cotton oil production (net)(MBbl/d)(e)	6.7			5.7			6.5			5.8
NGL sales volumes (net)(MBbl/d)(e)	9.9			10.3			10.0			10.1
Realized weighted-average oil price per Bbl(f)	$	57.80		$	62.17		$	57.97		$	60.85
Realized weighted-average NGL price per Bbl(g)	$	22.47		$	17.73		$	23.49		$	15.57

_______

Certain items affecting Segment EBDA

(a)

Three and six month 2017 amounts include unrealized losses of $8 million and $13 million, respectively, and three and six month 2016 amounts include unrealized losses of $18 million and $28 million, respectively, related to non-cash mark to market derivative contracts used to hedge forecasted commodity sales. Three and six months 2017 amounts also include an increase in revenues of $9 million related to the settlement of a CO2 customer sales contract.

(b)

In addition to the revenue certain items described in footnote (a) above: six month 2017 amount also includes a $1 million decrease in expense related to source and transportation project write-offs, and three and six month 2016 amounts also include decreases of $6 million and $12 million, respectively, in equity earnings for our share of a project write-off recorded by an equity investee, and six month 2016 amount also includes a $21 million increase in expense related to source and transportation project write-offs.

Other


(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 and a 100% working interest in the Tall Cotton field.


(e)	Net after royalties and outside working interests.


(f)	Includes all crude oil production properties.


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

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2017 and 2016.

Three months ended June 30, 2017 versus Three months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	8		11	%	$	6		7	%
Oil and Gas Producing Activities	(16		)	(10	)%	(19		)	(8	)%
Intrasegment eliminations	—			—	%	(3		)	(43	)%
Total CO2	$	(8	)	(4	)%	$	(16	)	(5	)%

Six months ended June 30, 2017 versus Six months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	11		7	%	$	8		5	%
Oil and Gas Producing Activities	(21		)	(7	)%	(24		)	(5	)%
Intrasegment eliminations	—			—	%	(4		)	(24	)%
Total CO2	$	(10	)	(2	)%	$	(20	)	(3	)%

The changes in Segment EBDA for our CO₂ business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2017 and 2016:

•

increases of $8 million (11%) and $11 million (7%), respectively, from our Source and Transportation activities primarily due to higher revenues of $6 million and $8 million, respectively, driven by increased volumes of $8 million and $15 million, respectively, partially offset by lower contract sales prices of $2 million and $7 million, respectively, and $2 million and $3 million, respectively, related to increased earnings from an equity investee; and

•

decreases of $16 million (10%) and $21 million (7%), respectively, from our Oil and Gas Producing activities primarily due to decreased revenues of $19 million and $24 million, respectively, driven by lower volumes of $9 million and $21 million, respectively, and lower commodity prices of $10 million and $3 million, respectively, partially offset $3 million for both periods in reduced operating expenses.

Terminals



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except operating statistics)
Revenues(a)	$	487		$	488		$	974		$	953
Operating expenses	(194		)	(195		)	(373		)	(386		)
Gain (loss) on impairments and divestitures, net(b)	—			3			(7		)	(17		)
Other income (expense)	1			—			1
Earnings from equity investments	7			5			12			11
Other, net	3			1			4			1
Segment EBDA(b)	304			302			611			562
Certain items(b)	(5		)	(7		)	(10		)	9
Segment EBDA before certain items	$	299		$	295		$	601		$	571

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	7		1		%	$	32		3		%
Segment EBDA before certain items	$	4		1		%	$	30		5		%

Bulk transload tonnage (MMtons)	14.6			14.0			29.0			26.1
Ethanol (MMBbl)	15.8			16.3			33.4			31.6
Liquids leasable capacity (MMBbl)	87.8			86.1			87.8			86.1
Liquids utilization %(c)	94.7		%	94.9		%	94.7		%	94.9		%

_______

Certain items affecting Segment EBDA


(a)	Three and six month 2017 amounts include increases in revenue of $3 million and $5 million, respectively, and three and six month 2016 amounts include increases in revenue of $11 million and $16 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)

In addition to the revenue certain items described in footnote (a) above: three and six month 2017 amounts also include (i) $1 million and $8 million, respectively, related to losses on impairments and divestitures, net: and (ii) decreases in expense of $3 million for both periods related to other certain items, and six months 2017 amounts also include $10 million decrease in expense related to a true-up of accrued dredging costs, and three and six month 2016 amounts also include increases in expense of $4 million and $5 million, respectively, related to other certain items, and six month 2016 amount also includes $20 million related to losses on impairments and divestitures, net.

Other


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

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2017 and 2016.

Three months ended June 30, 2017 versus Three months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Marine Operations	$	8		22	%	$	19		35	%
Gulf Liquids	4			6	%	9			10	%
Southeast	(4		)	(21	)%	(3		)	(7	)%
Held for sale operations	(3		)	(100	)%	(14		)	(93	)%
All others (including intrasegment eliminations)	(1		)	(1	)%	(4		)	(1	)%
Total Terminals	$	4		1	%	$	7		1	%

Six months ended June 30, 2017 versus Six months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Marine Operations	$	21		31	%	$	34		32	%
Gulf Liquids	13			10	%	21			12	%
Southeast	(5		)	(14	)%	(3		)	(4	)%
Held for sale operations	(8		)	(100	)%	(25		)	(81	)%
All others (including intrasegment eliminations)	9			3	%	5			1	%
Total Terminals	$	30		5	%	$	32		3	%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2017 and 2016:

•

increases of $8 million (22%) and $21 million (31%), respectively, from our Marine Operations related to the incremental earnings from the May 2016, July 2016, September 2016, December 2016 and March 2017 deliveries of the Jones Act tankers, the Magnolia State, Garden State, Bay State, American Endurance and American Freedom, respectively, partially offset by decreased charter rates on the Golden State, Pelican State, Sunshine State and Empire State Jones Act tankers;


•	increases of $4 million (6%) and $13 million (10%), respectively, from our Gulf Liquids terminals, primarily related to higher volumes as a result of various expansion projects, including the recently commissioned Kinder Morgan Export Terminal and North Docks terminal;


•	decreases of $4 million (21%) and $5 million (14%), respectively, from our Southeast terminals, primarily related to the expiration of a coal customer contract in September 2016; and


•	decreases of $3 million (100%) and $8 million (100%), respectively, from our sale of certain bulk terminal facilities to an affiliate of Watco Companies, LLC in December 2016 and early 2017.

Products Pipelines



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except operating statistics)
Revenues	$	418		$	401		$	820		$	797
Operating expenses(a)	(100		)	(141		)	(229		)	(294		)
Gain (loss) on impairments and divestitures, net(b)	—			5			—			(73		)
Other expense	(1		)	—			(1		)	—
Earnings from equity investments	10			15			23			28
Gain on divestiture of equity investment(c)	—			12			—			12
Other, net	(3		)	—			(2		)	(1		)
Segment EBDA(a)(b)(c)	324			292			611			469
Certain items(a)(b)(c)	(34		)	3			(34		)	111
Segment EBDA before certain items	$	290		$	295		$	577		$	580

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	17		4		%	$	23		3		%
Segment EBDA before certain items	$	(5	)	(2		)%	$	(3	)	(1		)%

Gasoline (MMBbl)(d)	96.4			95.0			185.7			183.6
Diesel fuel (MMBbl)	32.2			32.2			61.3			61.7
Jet fuel (MMBbl)	28.0			26.0			53.7			51.1
Total refined product volumes (MMBbl)(e)	156.6			153.2			300.7			296.4
NGL (MMBbl)(e)	11.0			9.7			20.6			19.0
Crude and condensate (MMBbl)(e)	30.1			27.9			61.5			58.8
Total delivery volumes (MMBbl)	197.7			190.8			382.8			374.2
Ethanol (MMBbl)(f)	10.7			10.7			20.6			20.8

_______

Certain items affecting Segment EBDA


(a)	Three and six month 2017 amounts include a decrease in expense of a $34 million for both periods related to a right-of-way settlement, and three and six month 2016 amounts include increases in expense of $20 million for both periods related to a legal settlement. Six month 2016 amount also includes $31 million of rate case liability estimate adjustments associated with prior periods.


(b)	Three and six month 2016 amounts include a decrease in expense of a $5 million and an increase in expense of a $8 million, respectively, of non-cash impairment charges related to the sale of a Transmix facility; and six month 2016 amount also includes an increase in expense of $64 million related to the Palmetto project write-off.


(c)	Three and six month 2016 amounts include $12 million of gains for both periods related to the sale of an equity investment.

Other


(d)	Volumes include ethanol pipeline volumes.


(e)	Joint venture throughput is reported at our ownership share.


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

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2017 and 2016.

Three months ended June 30, 2017 versus Three months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Plantation Pipe Line	$	(4	)	(24	)%	$	—	—	%
Cochin	(4		)	(13	)%	4		10	%
Crude & Condensate Pipeline	3			6	%	10		20	%
Double H pipeline	2			14	%	2		12	%
All others (including eliminations)	(2		)	(1	)%	1		—	%
Total Products Pipelines	$	(5	)	(2	)%	$	17	4	%

Six months ended June 30, 2017 versus Six months ended June 30, 2016



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Plantation Pipe Line	$	(3	)	(9	)%	$	—	—	%
Cochin	(4		)	(7	)%	4		5	%
Crude & Condensate Pipeline	3			3	%	8		7	%
Double H pipeline	4			15	%	4		11	%
All others (including eliminations)	(3		)	(1	)%	7		1	%
Total Products Pipelines	$	(3	)	(1	)%	$	23	3	%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2017 and 2016:


•	decreases of $4 million (24%) and $3 million (9%), respectively, from our equity investment in Plantation Pipe Line primarily due to higher operating costs attributable to a project write-off and higher pipeline environmental costs;


•	decreases of $4 million (13%) and $4 million (7%), respectively, from Cochin primarily due to higher operating costs largely due to increased pipeline integrity and foreign exchange costs partially offset by higher services revenues due to higher volumes;


•	increases of $3 million (6%) and $3 million (3%), respectively, from Kinder Morgan Crude & Condensate Pipeline primarily due to higher services revenues driven by an increase in pipeline throughput volumes from existing customers; and


•	increases of $2 million (14%) and $4 million (15%), respectively, from our Double H pipeline primarily due to higher service revenues driven by higher volumes.

Kinder Morgan Canada



	Three Months Ended June 30,						Six Months Ended June 30,
	2017			2016			2017			2016
	(In millions, except operating statistics)
Revenues	$	60		$	63		$	119		$	122
Operating expenses	(23		)	(21		)	(43		)	(39		)
Other, net	6			4			10			9
Segment EBDA	$	43		$	46		$	86		$	92

Change from prior period	Increase/(Decrease)
Revenues	$	(3	)	(5		)%	$	(3	)	(2		)%
Segment EBDA	$	(3	)	(7		)%	$	(6	)	(7		)%

Transport volumes (MMBbl)(a)	27.5			28.7			55.1			57.3

_______


(a)	Represents Trans Mountain pipeline system volumes.

For the comparable three and six month periods of 2017 and 2016, the Kinder Morgan Canada business segment had decreases in Segment EBDA of $3 million (7%) and $6 million (7%), respectively, largely due to operating expense timing changes and a 21 percent and 20 percent, respectively, decrease in volumes to Washington state, caused by a shift in deliveries from Washington to British Columbia destinations.

General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests



	Three Months Ended June 30,
	2017			2016			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	145		$	184		$	(39	)	(21	)%
Certain items(a)	4			(19		)	23			121	%
General and administrative and corporate charges before certain items(a)	$	149		$	165		$	(16	)	(10	)%

Interest, net(b)	$	463		$	471		$	(8	)	(2	)%
Certain items(b)	5			40			(35		)	(88	)%
Interest, net, before certain items	$	468		$	511		$	(43	)	(8	)%

Net income (loss) attributable to noncontrolling interests	$	7		$	3		$	4		133	%
Noncontrolling interests associated with certain items(c)	(1		)	3			(4		)	(133	)%
Net income attributable to noncontrolling interests before certain items	$	6		$	6		$	—		—	%



	Six Months Ended June 30,
	2017			2016			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	326		$	374		$	(48	)	(13	)%
Certain items(a)	(3		)	(24		)	21			88	%
General and administrative and corporate charges before certain items(a)	$	323		$	350		$	(27	)	(8	)%

Interest, net(b)	$	928		$	912		$	16		2	%
Certain items(b)	17			109			(92		)	(84	)%
Interest, net, before certain items	$	945		$	1,021		$	(76	)	(7	)%

Net income (loss) attributable to noncontrolling interests	$	12		$	2		$	10		500	%
Noncontrolling interests associated with certain items(c)	(1		)	9			(10		)	(111	)%
Net income attributable to noncontrolling interests before certain items	$	11		$	11		$	—		—	%

Certain items

(a)

Three and six month 2017 amounts include (i) increases in expense of $2 million and $7 million, respectively, of acquisition and asset sale related costs; and (ii) decreases in expense of $6 million for both periods related to other certain items. Six month 2017 amount also includes increases in expense of $2 million related to certain corporate litigation matters. Three and six month 2016 amounts include (i) increases in expense of $4 million and $8 million, respectively, related to certain corporate legal matters; (ii) increases in expense of $12 million for both periods related to severance costs; (iii) increases in expense of $5 million and $8 million, respectively, related to acquisition costs; and (iv) a decrease in expense of $2 million and $4 million, respectively, related to other certain items.

(b)

Three and six month 2017 amounts include (i) decreases in interest expense of $14 million and $29 million, respectively, related to debt fair value adjustments associated with acquisitions; (ii) increases in interest expense of $1 million and $4 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness; and (iii) increases in interest expense of $8 million for both periods related to other certain items. Three and six month 2016 amounts include decreases in interest expense of (i) $18 million and $37 million, respectively, related to debt fair value adjustments associated with acquisitions; and (ii) $22 million and $72 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness.


(c)	Three and six month 2016 amounts include losses of $3 million and $9 million, respectively, associated with Natural Gas Pipelines segment certain items and disclosed above in “—Natural Gas Pipelines.”

The decreases in general and administrative expenses and corporate charges before certain items of $16 million and $27 million, respectively, for the three and six months ended June 30, 2017 when compared with the respective prior periods was primarily driven by the sale of a 50% interest in our SNG natural gas pipeline system (effective September 1, 2016), higher capitalized costs, lower state franchise taxes, legal and insurance costs, partially offset by higher benefit costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income before certain items for the three and six months ended June 30, 2017 when compared with the respective prior periods decreased $43 million and $76 million, respectively. The decreases in interest expense were primarily due to lower weighted average debt balances as proceeds from our May 2017 KML IPO and September 2016 sale of a 50% interest in SNG were used to pay down debt, partially offset by a slightly higher overall weighted average interest rate on our outstanding debt.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of June 30, 2017 and December 31, 2016, approximately 30% and 28%, 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. Net income attributable to noncontrolling interests before certain items for the three and six months ended June 30, 2017 when compared with the respective prior periods did not change.

Income Taxes

Our tax expense for the three months ended June 30, 2017 was approximately $216 million as compared to $213 million for the same period of 2016. The $3 million increase in tax expense was primarily due to an increase in our deferred state income tax rate in 2016; partially offset by a valuation allowance on capital loss carryforwards also recorded in 2016.

Our tax expense for the six months ended June 30, 2017 was approximately $462 million as compared to $367 million for the same period of 2016. The $95 million increase in tax expense was primarily due to (i) an increase in our earnings as a result of asset impairments and project write-offs in 2016 and (ii) adjustments to our income tax reserve for uncertain tax positions.

Liquidity and Capital Resources

General

As of June 30, 2017, we had $452 million of “Cash and cash equivalents,” a decrease of $232 million (34%) from December 31, 2016. We believe our cash position, remaining borrowing capacity on our credit facility (discussed below in “—Short-term Liquidity”), and cash flows from operating activities are adequate to allow us to manage our day-to-day cash requirements and anticipated obligations as discussed further below.

We have consistently generated substantial cash flow from operations, providing a source of funds of $2,166 million and $2,345 million in the first six months of 2017 and 2016, respectively. The period-to-period decrease is discussed below in “Cash Flows—Operating Activities.” We have primarily relied on cash provided from operations to fund our operations as well as our debt service, capital expenditures and dividend payments.

On June 16, 2017, KML entered into a definitive credit agreement establishing (i) a C$4.0 billion revolving construction facility for the purposes of funding the development, construction and completion of the Trans Mountain expansion project; (ii) a C$1.0 billion revolving contingent credit facility for the purpose of funding, if necessary, additional Trans Mountain expansion project costs (and, subject to the need to fund such additional costs, meeting the Canadian National Energy Board-mandated liquidity requirements); and (iii) a C$500 million revolving working capital facility, to be used for working capital and other general corporate purposes (collectively, the “Credit Facility”). The Credit Facility has a five year term and is with a syndicate of financial institutions with Royal Bank of Canada as the administrative agent. As of June 30, 2017, KML had a combined $146 million outstanding under its Credit Facility which is included in “Current portion of debt” on our consolidated balance sheet and no outstanding letters of credit.

We expect to fund KML’s Trans Mountain expansion project capital expenditures through (i) additional borrowings on KML’s Credit Facility; (ii) the issuance of KML preferred shares; (iii) the issuance of additional KML restricted voting stock; (iv) the issuance of KML long-term notes payable; and (v) KML’s retained cash flow from operations or a combination of the above. KML established a dividend policy on its restricted voting shares pursuant to which it will pay its quarterly dividend in an amount based on a portion of its distributable cash flow discussed below in “—Noncontrolling interests—KML Restricted Voting Share Dividends below.

Generally, we expect that our short-term liquidity needs will be met primarily through retained cash from operations, short-term borrowings or by issuing new long-term debt to refinance certain of our maturing long-term debt obligations. We also expect that KMI’s current common stock dividend level will allow it to use retained cash to fund our other growth projects in 2017. Moreover, as a result of KMI’s current common stock dividend policy and by continuing to focus on high-grading our other growth project backlog to allocate capital to the highest return opportunities, we do not expect the need to access the equity capital markets to fund our other growth projects for the foreseeable future.

Short-term Liquidity

As of June 30, 2017, our principal sources of short-term liquidity are (i) our $5.0 billion revolving credit facility and associated $4.0 billion commercial paper program; (ii) our KML Credit Facility (described above) and (iii) 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, as previously discussed, have consistently generated strong cash flows from operations.

As of June 30, 2017, our $3,224 million of short-term debt consisted primarily of senior notes that mature in the next year. We intend to refinance our short-term debt through credit facility borrowings, commercial paper borrowings, or by issuing new long-term debt or paying down short-term debt using cash retained from operations or received from asset sales. Our short-term debt balance as of December 31, 2016 was $2,696 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,637 million and $2,695 million as of June 30, 2017 and December 31, 2016, respectively. Our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or partially pay down using retained cash from operations. The overall $942 million (35%) unfavorable change from year-end 2016 was primarily due to a net increase in our current portion of long term debt and a decrease in cash. 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 excess cash from operations after payments for investing and financing activities.

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.

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 DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are. See “—Dividends.”

Our capital expenditures for the six months ended June 30, 2017, and the amount we expect to spend for the remainder of 2017 to sustain and grow our businesses are as follows:



	Six Months Ended June 30, 2017		2017 Remaining		Total
	(In millions)
Sustaining capital expenditures(a)	$	260	$	361	$	621
KMI Discretionary capital investments(b)(c)	$	1,335	$	1,013	$	2,348
KML Discretionary capital investments	$	176	$	638	$	814

_______


(a)	Six months ended June 30, 2017, 2017 Remaining, and Total 2017 amounts include $45 million, $66 million, and $111 million, respectively, for our proportionate share of sustaining capital expenditures of unconsolidated joint ventures.


(b)	Six months ended June 30, 2017 is net of $216 million of contributions from certain partners for capital investments at non-wholly owned consolidated subsidiaries offset by $512 million of our contributions to certain unconsolidated joint ventures for capital investments, and excludes $94 million of net changes from accrued capital expenditures, contractor retainage and other.


(c)	2017 Remaining amount includes our estimated contributions to certain unconsolidated joint ventures, net of contributions estimated from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

Other than commitments for the purchase of property, plant and equipment discussed below, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2016 in our 2016 Form 10-K.

Commitments for the purchase of property, plant and equipment as of June 30, 2017 and December 31, 2016 were $1,058 million and $1,112 million, respectively. The $54 million decrease is primarily the result of our decrease in tankers’ commitment, partially offset by increase in various capital commitments associated with our natural gas pipeline business segment.

Cash Flows

Operating Activities

The net decrease of $179 million in cash provided by operating activities for the first six months of 2017 compared to the respective 2016 period was primarily attributable to:


•	a $102 million decrease associated with net changes in working capital items and non-current assets and liabilities, primarily driven, among other things, by a decrease in cash related to gas in underground storage inventory resulting from an increase in storage injections and price increases; and

•

a $77 million decrease in operating cash flow resulting from the combined effects of adjusting net income for the period-to-period $139 million increase in non-cash items including the following: (i) net losses on impairments and divestitures of assets and equity investments (see discussion above in “—Results of Operations”); (ii) change in fair market value of derivative contracts; (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments.

Investing Activities

The $307 million net decrease in cash used in investing activities for the first six months of 2017 compared to the respective 2016 period was primarily attributable to:


•	a $329 million decrease in expenditures for acquisitions of assets and investments, primarily driven by the $324 million portion of the purchase price we paid in the 2016 period for the BP terminals acquisition;


•	a $134 million reduction in capital expenditures primarily due to lower expenditures related to natural gas expansion projects; and


•	a $133 million increase in cash for distributions received from equity investment in excess of cumulative earnings, primarily driven by the higher distributions from Midcontinent Express Pipeline LLC and Ruby Pipeline Holding Company, L.L.C.; partially offset by


•	a $185 million increase in cash used for contributions to equity investments primarily due to the contributions we made in 2017 to Utopia Holding LLC, Fayetteville Express Pipeline LLC and SNG; and


•	a $149 million lower cash proceeds from sales of property, plant and equipment and other net assets, primarily driven by the higher proceeds we received in 2016 from sales of other long-lived assets.

Financing Activities

The net increase of $316 million in cash used in financing activities for the first six months of 2017 compared to the respective 2016 period was primarily attributable to:


•	a $1,895 million net increase in cash used related to debt activity as a result of net debt payments in the 2017 period compared with net debt proceeds in the 2016 period. See Note 3 “Debt” for further information regarding our debt activity; partially offset by


•	a $1,171 million decrease in cash used due to contributions from noncontrolling interests, primarily reflecting $1,247 million in net proceeds received from the May 2017 KML IPO, compared with $84 million of contributions received from BP for its 25% share of a newly formed joint venture in the 2016 period; and


•	a $415 million increase in cash resulting from contributions received in the 2017 period from EIG, consisting of $386 million for the sale of a 49% partnership interest in ELC and $29 million as additional contributions for 2017 capital expenditures.

Dividends and Stock Buyback Program

KMI Common Stock Dividends

We expect to declare common dividends of $0.50 per share on our common stock for 2017 ($0.125/quarter).



Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2016	$	0.125	January 18, 2017	February 1, 2017	February 15, 2017
March 31, 2017	$	0.125	April 19, 2017	May 1, 2017	May 15, 2017
June 30, 2017	$	0.125	July 19, 2017	July 31, 2017	August 15, 2017

As a result of substantial balance sheet improvement achieved since the end of 2015, we announced multiple steps to return significant value to shareholders. First, we announced our expectation to declare an annual dividend of $0.80 per share for 2018, a 60% increase from the expected 2017 dividend. The first 2018 increase is expected to be the dividend declared for the first quarter of 2018. Additionally, we plan to increase our dividend to $1.00 per share in 2019 and $1.25 per share in 2020, a growth rate of 25% annually.

The actual amount of common 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. See Item 1A. “Risk Factors—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” of our 2016 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our common stock 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 common stock dividends generally are expected to be paid on or about the 15th day of each February, May, August and November.

KMI Preferred Dividends

Dividends on our mandatory convertible preferred stock are payable on a cumulative basis when, as and if declared by our board of directors (or an authorized committee thereof) at an annual rate of 9.750% of the liquidation preference of $1,000 per share on January 26, April 26, July 26 and October 26 of each year, commencing on January 26, 2016 to, and including, October 26, 2018. We may pay dividends in cash or, subject to certain limitations, in shares of common stock or any combination of cash and shares of common stock. The terms of the mandatory convertible preferred stock provide that, unless full cumulative dividends have been paid or set aside for payment on all outstanding mandatory convertible preferred stock for all prior dividend periods, no dividends may be declared or paid on common stock.



Period	Total dividend per share for the period		Date of declaration	Date of record	Date of dividend
October 26, 2016 through January 25, 2017	$	24.375000	October 19, 2016	January 11, 2017	January 26, 2017
January 26, 2017 through April 25, 2017	$	24.375000	January 18, 2017	April 11, 2017	April 26, 2017
April 26, 2017 through July 25, 2017	$	24.375000	April 19, 2017	July 11, 2017	July 26, 2017

The cash dividend of $24.375 per share of our mandatory convertible preferred stock is equivalent to $1.21875 per depository share.

Stock Buyback Program

On July 19, 2017, we announced that our board of directors had approved a $2 billion share buyback program expected to begin in 2018.

Noncontrolling Interests

KML Restricted Voting Share Dividends

KML intends to establish a dividend policy pursuant to which it will pay a quarterly dividend in an amount based on a portion of its distributable cash flow. The payment of dividends is not guaranteed and the amount and timing of any dividends payable will be at the discretion of KML’s board of directors. The actual amount of cash dividends paid to KML’s shareholders, if any, will depend on numerous factors including: (i) KML’s results of operations; (ii) KML’s financial requirements, including the funding of its current and future growth projects; (iii) the amount of distributions paid indirectly by the limited partnership to KML through the general partner, including any contributions from the completion of its growth projects; (iv) the satisfaction by KML and its general partner of certain liquidity and solvency tests; (v) any agreements relating to KML’s indebtedness or the limited partnership; and (vi) the cost and timely completion of current and future growth projects. KML intends to pay quarterly dividends to holders of its restricted voting shares of record as of the close of business on or about the last business day of the month following the end of each calendar quarter, which dividends are expected to be paid to shareholders on or about the 45th day (or next business day) following the end of each calendar quarter. KML anticipates that any dividends paid on the restricted voting shares will be designated as “eligible dividends” for Canadian income tax purposes, unless otherwise notified, and that KML will include disclosure on its website to this effect.

On July 19, 2017, KML’s board of directors declared a prorated dividend for the first quarter of C$0.0571 per restricted voting share, payable on August 15, 2017, to restricted voting shareholders of record as of July 31, 2017. The initial dividend is prorated from May 30, 2017, the day that KML closed its offering, to June 30, 2017. Based on a full quarter, the dividend amounts to C$0.1625 per restricted voting share (C$0.65 annualized). For 2017, KML expects to pay a prorated dividend of

C$0.3821 per restricted voting share (or C$0.65 per restricted voting share on an annualized basis). The total KML dividend declared for the three months ended June 30, 2017 amounted to approximately C$5.9 million.

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, 2016, in Item 7A in our 2016 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 June 30, 2017, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions

regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2017 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation, Environmental and Other Contingencies” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2016 Form 10-K.

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

On July 19, 2017, we announced that our board of directors had approved a $2 billion share buyback program expected to begin in 2018.

The warrant repurchase program, dated June 12, 2015, authorized us to repurchase up to $100 million of warrants, expired along with the warrants on May 25, 2017.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

The Company no longer owns or operates mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank), except for one terminal that is in temporary idle status with the Mine Safety and Health Administration. The Company has not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended June 30, 2017.

Item 5. Other Information.

None.

Item 6. Exhibits.



3.1	*	Amended and Restated Certificate of Incorporation of KMI (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10‑Q for the three months ended June 30, 2015 (file No. 001-35081)).

3.2	*	Amended and Restated Bylaws of KMI (filed as Exhibit 3.1 to KMI’s Current Report on Form 8‑K, filed January 24, 2017 (File No. 001-35081)).

10.1		Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2017.

10.2	*	Credit Agreement, dated June 16, 2017, among Kinder Morgan Cochin ULC and Trans Mountain Pipeline ULC and the lenders party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed June 22, 2017 (File No. 001-35081)) (portions of the exhibit have been omitted pursuant to 17 CFR 240.24b-2 and filed separately with the Securities and Exchange Commission pursuant to a Confidential Treatment Application).

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.

101		Interactive data files pursuant to Rule 405 of Regulation S-T: (i) our Consolidated Statements of Income for the three and six months ended June 30, 2017 and 2016; (ii) our Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2017 and 2016; (iii) our Consolidated Balance Sheets as of June 30, 2017 and December 31, 2016; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2017 and 2016; (v) our Consolidated Statements of Stockholders’ Equity for the six months ended June 30, 2017 and 2016; 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.

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:	July 24, 2017	By:	/s/ Kimberly A. Dang
			Kimberly A. Dang Vice President and Chief Financial Officer (principal financial and accounting officer)