KMI 10-Q Quarterly Report Sept. 30, 2018

KINDER MORGAN, INC.

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10-Q 1 kmi-09302018x10q.htm 10-Q Document

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2018

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 October 18, 2018 , the registrant had 2,207,018,287 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 - Thre e and Nine Months Ended September 30, 2018 and 2017	4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2018 and 2017	5
	Consolidated Balance Sheets - September 30, 2018 and December 31, 2017	6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2018 and 2017	7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 2018 and 2017	9
	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	50
	Results of Operations	50
	Liquidity and Capital Resources	64

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	68

Item 4.	Controls and Procedures	68

	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	69

Item 1A.	Risk Factors	69

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	69

Item 3.	Defaults Upon Senior Securities	69

Item 4.	Mine Safety Disclosures	69

Item 5.	Other Information	69

Item 6.	Exhibits	70

	Signature	71

KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations

CIG	=	Colorado Interstate Gas Company, L.L.C.	KML	=	Kinder Morgan Canada Limited and its majority-
EIG	=	EIG Global Energy Partners			owned and/or controlled subsidiaries
ELC	=	Elba Liquefaction Company, L.L.C.	KMLT	=	Kinder Morgan Liquid Terminals, LLC
EPB	=	El Paso Pipeline Partners, L.P. and its majority-	KMP	=	Kinder Morgan Energy Partners, L.P. and its
		owned and/or controlled subsidiaries			majority-owned and/or controlled subsidiaries
EPNG	=	El Paso Natural Gas Company, L.L.C.	SFPP	=	SFPP, L.P.
Hiland	=	Hiland Partners, LP	SNG	=	Southern Natural Gas Company, L.L.C.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMEP	=	Kinder Morgan Energy Partners, L.P.	TMEP	=	Trans Mountain Expansion Project
KMGP	=	Kinder Morgan G.P., Inc.	TMPL	=	Trans Mountain Pipeline System
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries	Trans Mountain	=	Trans Mountain Pipeline ULC

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
2017 Tax	=	The Tax Cuts & Jobs Act of 2017	EPA	=	United States Environmental Protection Agency
Reform	=	The Tax Cuts & Jobs Act of 2017	FASB	=	Financial Accounting Standards Board
/d	=	per day	FERC	=	Federal Energy Regulatory Commission
BBtu	=	billion British Thermal Units	GAAP	=	United States Generally Accepted Accounting
Bcf	=	billion cubic feet			Principles
CERCLA	=	Comprehensive Environmental Response,	IPO	=	Initial Public Offering
		Compensation and Liability Act	LLC	=	limited liability company
C$	=	Canadian dollars	MBbl	=	thousand barrels
CO ₂	=	carbon dioxide or our CO ₂ business segment	MMBbl	=	million barrels
DCF	=	distributable cash flow	NGL	=	natural gas liquids
DD&A	=	depreciation, depletion and amortization	U.S.	=	United States of America
EBDA	=	earnings before depreciation, depletion and
		amortization expenses, including amortization of
		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, 2017 ( 2017 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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Revenues
Natural gas sales	$	799		$	714		$	2,353		$	2,281
Services	1,959			1,938			5,910			5,855
Product sales and other	759			629			2,100			1,937
Total Revenues	3,517			3,281			10,363			10,073

Operating Costs, Expenses and Other
Costs of sales	1,135			1,007			3,222			3,138
Operations and maintenance	646			609			1,882			1,698
Depreciation, depletion and amortization	569			562			1,710			1,697
General and administrative	154			168			491			509
Taxes, other than income taxes	86			102			259			297
(Gain) loss on divestitures and impairments, net	(588		)	7			65			13
Other income, net	—			—			(2		)	—
Total Operating Costs, Expenses and Other	2,002			2,455			7,627			7,352

Operating Income	1,515			826			2,736			2,721

Other Income (Expense)
Earnings from equity investments	160			167			708			477
Loss on impairment of equity investment	—			—			(270		)	—
Amortization of excess cost of equity investments	(21		)	(15		)	(77		)	(45		)
Interest, net	(473		)	(459		)	(1,456		)	(1,387		)
Other, net	20			28			90			71
Total Other Expense	(314		)	(279		)	(1,005		)	(884		)

Income Before Income Taxes	1,201			547			1,731			1,837

Income Tax Expense	(196		)	(160		)	(314		)	(622		)

Net Income	1,005			387			1,417			1,215

Net Income Attributable to Noncontrolling Interests	(273		)	(14		)	(302		)	(26		)

Net Income Attributable to Kinder Morgan, Inc.	732			373			1,115			1,189

Preferred Stock Dividends	(39		)	(39		)	(117		)	(117		)

Net Income Available to Common Stockholders	$	693		$	334		$	998		$	1,072

Class P Shares
Basic and Diluted Earnings Per Common Share	$	0.31		$	0.15		$	0.45		$	0.48

Basic and Diluted Weighted Average Common Shares Outstanding	2,205			2,231			2,205			2,230

Dividends Per Common Share Declared for the Period	$	0.20		$	0.125		$	0.60		$	0.375

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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017

Net income	$	1,005		$	387		$	1,417		$	1,215
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $26, $(3), $39 and $(105), respectively)	(87		)	7			(133		)	185
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(4), $27, $(23) and $82, respectively)	11			(48		)	78			(144		)
Foreign currency translation adjustments (net of tax expense of $49, $28, $28 and $45, respectively)	300			78			187			129
Benefit plan adjustments (net of tax expense of $21, $8, $25 and $17, respectively)	37			7			49			20
Total other comprehensive income	261			44			181			190

Comprehensive income	1,266			431			1,598			1,405
Comprehensive income attributable to noncontrolling interests	(339		)	(44		)	(328		)	(75		)
Comprehensive income attributable to Kinder Morgan, Inc.	$	927		$	387		$	1,270		$	1,330

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) (Unaudited)

	September 30, 2018			December 31, 2017
ASSETS
Current Assets
Cash and cash equivalents	$	3,459		$	264
Restricted deposits	101			62
Accounts receivable, net	1,384			1,448
Fair value of derivative contracts	51			114
Inventories	383			424
Income tax receivable	161			165
Other current assets	227			238
Total current assets	5,766			2,715

Property, plant and equipment, net	37,795			40,155
Investments	7,432			7,298
Goodwill	21,965			22,162
Other intangibles, net	2,935			3,099
Deferred income taxes	1,874			2,044
Deferred charges and other assets	1,296			1,582
Total Assets	$	79,063		$	79,055

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,337		$	2,828
Accounts payable	1,307			1,340
Accrued interest	399			621
Accrued contingencies	89			291
Other current liabilities	1,357			1,101
Total current liabilities	5,489			6,181
Long-term liabilities and deferred credits
Long-term debt
Outstanding	34,625			33,988
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	543			927
Total long-term debt	35,268			35,015
Other long-term liabilities and deferred credits	2,407			2,735
Total long-term liabilities and deferred credits	37,675			37,750
Total Liabilities	43,164			43,931
Commitments and contingencies (Notes 3 and 10)
Redeemable Noncontrolling Interest	633			—
Stockholders’ Equity
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	—			—
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,205,496,735 and 2,217,110,072 shares, respectively, issued and outstanding	22			22
Additional paid-in capital	41,704			41,909
Retained deficit	(7,744		)	(7,754		)
Accumulated other comprehensive loss	(495		)	(541		)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,487			33,636
Noncontrolling interests	1,779			1,488
Total Stockholders’ Equity	35,266			35,124
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	79,063		$	79,055

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)

	Nine Months Ended September 30,
	2018			2017
Cash Flows From Operating Activities
Net income	$	1,417		$	1,215
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,710			1,697
Deferred income taxes	144			624
Amortization of excess cost of equity investments	77			45
Change in fair market value of derivative contracts	188			28
Loss on divestitures and impairments, net	65			13
Loss on impairment of equity investment	270			—
Earnings from equity investments	(708		)	(477		)
Distributions from equity investment earnings	351			370
Changes in components of working capital
Accounts receivable, net	67			174
Income tax receivable	—			144
Inventories	38			(86		)
Other current assets	(18		)	(2		)
Accounts payable	(27		)	(62		)
Accrued interest, net of interest rate swaps	(198		)	(158		)
Accrued contingencies and other current liabilities	187			(23		)
Rate reparations, refunds and other litigation reserve adjustments	(202		)	(100		)
Other, net	14			(95		)
Net Cash Provided by Operating Activities	3,375			3,307

Cash Flows From Investing Activities
Proceeds from the TMPL Sale, net of cash disposed (Note 2)	3,003			—
Acquisitions of assets and investments	(20		)	(4		)
Capital expenditures	(2,206		)	(2,231		)
Proceeds from sales of equity investments	33			—
Sales of property, plant and equipment, and other net assets, net of removal costs	(4		)	118
Contributions to investments	(294		)	(631		)
Distributions from equity investments in excess of cumulative earnings	197			252
Loans to related party	(23		)	(16		)
Other, net	—			4
Net Cash Provided by (Used in) Investing Activities	686			(2,508		)

Cash Flows From Financing Activities
Issuances of debt	11,837			7,790
Payments of debt	(11,221		)	(9,654		)
Debt issue costs	(31		)	(69		)
Cash dividends - common shares	(1,163		)	(840		)
Cash dividends - preferred shares	(117		)	(117		)
Repurchases of common shares	(250		)	—
Contributions from investment partner	148			444
Contributions from noncontrolling interests - net proceeds from KML IPO	—			1,245
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance	—			230
Contributions from noncontrolling interests - other	19			12
Distributions to noncontrolling interests	(58		)	(26		)
Other, net	(17		)	(9		)
Net Cash Used in Financing Activities	(853		)	(994		)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	26			28

Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	3,234			(167		)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	326			787
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	3,560		$	620

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

	Nine Months Ended September 30,
	2018		2017
Cash and Cash Equivalents, beginning of period	$	264	$	684
Restricted Deposits, beginning of period	62		103
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	326		787

Cash and Cash Equivalents, end of period	3,459		539
Restricted Deposits, end of period	101		81
Cash, Cash Equivalents, and Restricted Deposits, end of period	3,560		620

Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	$	3,234	$	(167	)

Non-cash Investing and Financing Activities
Increase in property, plant and equipment from both accruals and contractor retainage	$	35	$	167
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	$	1,593	$	1,566
Cash paid (refunded) during the period for income taxes, net	37		(144		)

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 June 30, 2018	2,204	$	22	2	$	—	$	41,696	$	(7,993	)	$	(690	)	$	33,035		$	1,459		$	34,494
Restricted shares	1						8								8						8
Net income									732						732			273			1,005
Distributions															—			(25		)	(25		)
Contributions															—			4			4
Preferred stock dividends									(39		)				(39		)				(39		)
Common stock dividends									(444		)				(444		)				(444		)
Other															—			2			2
Other comprehensive income												195			195			66			261
Balance at September 30, 2018	2,205	$	22	2	$	—	$	41,704	$	(7,744	)	$	(495	)	$	33,487		$	1,779		$	35,266



	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 June 30, 2017	2,230	$	22	2	$	—	$	42,092		$	(6,482	)	$	(483	)	$	35,149		$	1,065		$	36,214
Restricted shares	1						9									9						9
Net income										373						373			14			387
KML IPO							(2		)				—			(2		)	1			(1		)
KML preferred share issuance																—			230			230
Distributions																—			(12		)	(12		)
Contributions																—			2			2
Preferred stock dividends										(39		)				(39		)				(39		)
Common stock dividends										(280		)				(280		)				(280		)
Impact of adoption of ASU 2016-09										(1		)				(1		)				(1		)
Sale and deconsolidation of interest in Deeprock Development, LLC																—			(30		)	(30		)
Other							2									2			(1		)	1
Other comprehensive income													14			14			30			44
Balance at September 30, 2017	2,231	$	22	2	$	—	$	42,101		$	(6,429	)	$	(469	)	$	35,225		$	1,299		$	36,524

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(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, 2017	2,217		$	22	2	$	—	$	41,909		$	(7,754	)	$	(541	)	$	33,636		$	1,488		$	35,124
Impact of adoption of ASUs (Note 1)											175			(109		)	66						66
Balance at January 1, 2018	2,217		22		2	—		41,909			(7,579		)	(650		)	33,702			1,488			35,190
Repurchase of shares	(13	)						(250		)							(250		)				(250		)
Restricted shares	1							45									45						45
Net income											1,115						1,115			302			1,417
Distributions																	—			(69		)	(69		)
Contributions																	—			30			30
Preferred stock dividends											(117		)				(117		)				(117		)
Common stock dividends											(1,163		)				(1,163		)				(1,163		)
Other																	—			2			2
Other comprehensive income														155			155			26			181
Balance at September 30, 2018	2,205		$	22	2	$	—	$	41,704		$	(7,744	)	$	(495	)	$	33,487		$	1,779		$	35,266



	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	1						46								46						46
Net income									1,189						1,189			26			1,215
KML IPO							314					51			365			684			1,049
KML preferred share issuance															—			230			230
Distributions															—			(27		)	(27		)
Contributions															—			13			13
Preferred stock dividends									(117		)				(117		)				(117		)
Common stock dividends									(840		)				(840		)				(840		)
Impact of adoption of ASU 2016-09									8						8						8
Sale and deconsolidation of interest in Deeprock Development, LLC															—			(30		)	(30		)
Other							2								2			(17		)	(15		)
Other comprehensive income												141			141			49			190
Balance at September 30, 2017	2,231	$	22	2	$	—	$	42,101	$	(6,429	)	$	(469	)	$	35,225		$	1,299		$	36,524

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 152 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO ₂ and other products, and our terminals transload and store liquid commodities including petroleum products, ethanol and chemicals, and bulk products, including petroleum coke, metals and ores.

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 2017 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.

Accounting Policy Changes

Adoption of New Accounting Pronouncements

On January 1, 2018, we adopted Accounting Standards Updates (ASU) No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates designed to create improved revenue recognition and disclosure comparability in financial statements. For more information, see Note 7.

On January 1, 2018, we retroactively adopted 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 statements of cash flows to present 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 now included with cash and cash equivalents when reconciling the beginning of period and end of period amounts presented on the statements of cash flows. The retrospective application of this new accounting guidance resulted in a decrease of $22 million in “Other, net” in Cash Flows from Investing Activities, an increase of $103 million in “Cash, Cash Equivalents, and Restricted Deposits, beginning of the period,” and an increase of $81 million in “Cash, Cash Equivalents, and Restricted Deposits, end of period” in our accompanying consolidated statement of cash flows for the nine months ended September 30, 2017 from what was previously presented in our Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2017.

Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive and other insurance subsidiaries, and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions.

On January 1, 2018, we adopted ASU No. 2017-05, “ Clarifying the Scope of Asset Derecognition Guidance and Accounting for Partial Sales of Nonfinancial Assets .” This ASU clarifies the scope and application of ASC 610-20 on contracts for the sale or transfer of nonfinancial assets and in substance nonfinancial assets to noncustomers, including partial sales. This ASU also clarifies that the derecognition of all businesses is in the scope of ASC 810 and defines an “in substance nonfinancial asset.” We utilized the modified retrospective method to adopt the provisions of this ASU, which required us to apply the new standard to (i) all new contracts entered into after January 1, 2018, and (ii) to contracts that were not completed contracts as of January 1, 2018 through a cumulative adjustment to our “Retained deficit” balance. The cumulative effect of the adoption of this ASU was a $66 million , net of income taxes, adjustment to our “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018. This ASU also requires us to classify EIG’s cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheet as of September 30, 2018, as EIG has the right under certain conditions to redeem their interests for cash. The December 31, 2017 balance of $485 million is included in “Other long-term liabilities and deferred credits” on our consolidated balance sheet as of December 31, 2017.

On January 1, 2018, we adopted 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, allows only the service cost component of net benefit cost to be eligible for capitalization and establishes how to present the service cost component and the other components of net benefit cost in the income statement. Topic 715 required us to retrospectively reclassify $4 million and $11 million of other components of net benefit credits (excluding the service cost component) from “General and administrative” to “Other, net” in our accompanying consolidated statement of income for the three and nine months ended September 30, 2017 , respectively. We prospectively applied Topic 715 related to net benefit costs eligible for capitalization.

On January 1, 2018, we adopted ASU No. 2018-02, “ Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income .” Our accounting policy for the release of stranded tax effects in accumulated other comprehensive income is on an aggregate portfolio basis. This ASU permits companies to reclassify the income tax effects of the 2017 Tax Reform on items within accumulated other comprehensive income to retained earnings. The FASB refers to these amounts as “stranded tax effects.” Only the stranded tax effects resulting from the 2017 Tax Reform are eligible for reclassification. The adoption of this ASU resulted in a $109 million reclassification adjustment of stranded income tax effects from “Accumulated other comprehensive loss” to “Retained deficit” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2018.

Gains Losses on Divestitures and Impairments, net

During the three and nine months ended September 30, 2018, we recognized (i) a $622 million gain for both periods on the TMPL Sale within our Kinder Morgan Canada business segment (see Note 2); (ii) a $ 35 million project write-off for both periods on the Utica Marcellus Texas pipeline within our Products Pipelines business segment; and (iii) gains of $1 million and $8 million , respectively, related to miscellaneous asset disposals. During the nine months ended September 30, 2018, we also recognized (i) a $600 million non-cash impairment loss associated with certain gathering and processing assets in Oklahoma within our Natural Gas Pipelines business segment; (ii) a $60 million non-cash impairment related to certain Terminal business segment assets; and (iii) a non-cash impairment of $270 million of our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG) within our Natural Gas Pipelines business segment.

The $600 million non-cash impairment for the nine months ended September 30, 2018 was driven by reduced cash flow estimates for some of our gathering and processing assets in Oklahoma during the period as a result of our decision to redirect our focus to other areas of our portfolio. These reduced estimates triggered an impairment analysis as we determined that our carrying value may no longer be recoverable. The impairment analysis for long-lived assets was based upon a two-step process as prescribed in the accounting standards. Step 1 involved comparing the undiscounted future cash flows to be derived from the asset group to the carrying value of the asset group. Based on the results of our step 1 test, we determined that the undiscounted future cash flows were less than the carrying value of the asset group. Step 2 involved using the income approach to calculate the fair value of the asset group and comparing it to the carrying value. The impairment that we recorded represented the difference between the fair and carrying values.

The $270 million non-cash impairment for the nine months ended September 30, 2018 in our equity investment in Gulf LNG was driven by a ruling by an arbitration panel affecting a customer contract. Our share of earnings recognized by Gulf LNG on the respective customer contract is included in “Earnings from equity investments” in the accompanying consolidated statements of income for the nine months ended September 30, 2018.

The estimate of fair value is 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. 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 and investments have been written down to fair value in the last few years, 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

In addition to periodically evaluating long-lived assets for impairment based on changes in market conditions as discussed above, 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) CO ₂ ; (vi) Terminals; and (vii) Kinder Morgan Canada. The evaluation of goodwill for impairment involves a two-step test.

The results of our May 31, 2018 annual step 1 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. A new period of volatile commodity prices could result in a 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.

The fair value estimates used in step 1 of the 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 reporting unit.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares 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 restricted stock or restricted stock units issued to employees and non-employee directors 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 September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Net Income Available to Common Stockholders	$	693		$	334		$	998		$	1,072
Participating securities:
Less: Net Income Allocated to Restricted stock awards(a)	(4		)	(2		)	(5		)	(4		)
Net Income Allocated to Class P Stockholders	$	689		$	332		$	993		$	1,068

Basic Weighted Average Common Shares Outstanding	2,205			2,231			2,205			2,230
Basic Earnings Per Common Share	$	0.31		$	0.15		$	0.45		$	0.48

________


(a)	As of September 30, 2018 , there were approximately 13 million restricted stock awards outstanding.

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 September 30,		Nine Months Ended September 30,
	2018	2017	2018	2017
Unvested restricted stock awards	13	10	11	9
Warrants to purchase our Class P shares(a)	—	—	—	155
Convertible trust preferred securities	3	3	3	3
Mandatory convertible preferred stock(b)	58	58	58	58

_______


(a)	On May 25, 2017, approximately 293 million unexercised warrants expired without the issuance of Class P common stock. Prior to expiration, each warrant entitled the holder to purchase one share of our common stock for an exercise price of $40 per share. The potential dilutive effect of the warrants did not consider the assumed proceeds to KMI upon exercise.


(b)	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 stock dividends.

2. Divestitures

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed its previously announced sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for cash consideration of C$4.43 billion (U.S. $3.4 billion ), which is the contractual purchase price of C $4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). The contractual purchase price is subject to a customary final true up of the estimated working capital calculation as provided in the purchase agreement. We recognized a pre-tax gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated income statements during both the three and nine months ended September 30, 2018.

On September 4, 2018, we announced that KML’s board of directors approved a plan to distribute the net proceeds from the TMPL Sale, after capital gains taxes, customary purchase price adjustments and the repayment of debt outstanding under KML’s Temporary Credit Facility (see Note 3), as a return of capital to its shareholders. The KML board also approved a proposal to effect a consolidation or "reverse stock split" of KML’s Restricted Voting Shares on a one -for- three basis (three shares consolidating to one share). The return of capital requires a reduction in KML’s stated capital, which, together with the reverse stock split is subject to a two-thirds majority vote for approval by KML shareholders. The proposals will be voted on at a special meeting of KML’s shareholders scheduled to be held on November 29, 2018. We intend to vote for these proposals with our 70% voting and ownership interest in KML and use the proceeds we receive in respect of our interest in KML to pay down debt.

May 2017 Sale of Approximate 30% Interest in Canadian Business

On May 30, 2017, KML completed an IPO of 102,942,000 restricted voting shares listed 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 ( US$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 while we retained the remaining 70% interest. We used the proceeds from KML’s IPO to pay down debt.

February 2017 Sale of Noncontrolling Interest in 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 that are wholly owned by us. In certain limited circumstances that are not expected to occur, EIG has the right to relinquish its interest in ELC and redeem its capital account. The sale proceeds of $386 million , and subsequent EIG contributions, have been reflected as of September 30, 2018 within “Redeemable Noncontrolling Interest” and as of December 31, 2017 as a deferred credit within “Other long-term liabilities and deferred credits,” respectively, on our consolidated balance sheets. Once these contingencies expire, EIG’s capital account will be reflected in “Noncontrolling interests” 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 additional information 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):



	September 30, 2018		December 31, 2017
Current portion of debt
Credit facility due November 26, 2019, 3.61% and 2.99%, respectively(a)	$	675	$	125
Commercial paper notes, 2.90% and 2.02%, respectively(a)	207		240
KML 2018 Credit Facility(b)	—		—
Current portion of senior notes
6.00%, due January 2018	—		750
7.00%, due February 2018	—		82
5.95%, due February 2018	—		975
7.25%, due June 2018	—		477
9.00%, due February 2019	500		—
2.65%, due February 2019	800		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion - Other debt	44		68
Total current portion of debt	2,337		2,828

Long-term debt (excluding current portion)
Senior notes	33,897		33,248
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035	399		409
KMGP, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock	100		100
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	219		221
Total long-term debt	34,725		34,088
Total debt(c)	$	37,062	$	36,916

_______


(a)	Interest rates are weighted average rates.


(b)	Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. At September 30, 2018 , the exchange rate was 0.7725 U.S. dollars per C$. See “—Credit Facilities ” below.

(c)

Excludes our “Debt fair value adjustments” which, as of September 30, 2018 and December 31, 2017 , increased our combined debt balances by $543 million and $927 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 12.

Credit Facilities

KMI

As of September 30, 2018 , we had $675 million outstanding under our credit facility, $207 million outstanding under our commercial paper program and $99 million in letters of credit. Our availability under our $5 billion credit facility as of September 30, 2018 was $4,019 million . As of September 30, 2018 , we were in compliance with all required covenants.

KML

In conjunction with the announcement of the TMPL Sale described in Note 2, on May 30, 2018, approximately C$100 million of borrowings outstanding under KML’s June 16, 2017 revolving credit facilities (the “KML 2017 Credit Facility”) were repaid, the underlying credit facilities were terminated, and approximately $46 million of deferred costs associated with the KML 2017 Credit Facility that were being amortized as interest expense over its term were written off.

On May 30, 2018 and concurrently with the termination of the KML 2017 Credit Facility, KML established a C$500 million revolving credit facility (the “KML Temporary Credit Facility”), for general corporate purposes, including working capital during the period from June 1, 2018 through the closing of the TMPL Sale. The approximate C$100 million of borrowings outstanding under the terminated KML 2017 Credit Facility were repaid pursuant to an initial drawdown under the KML Temporary Credit Facility.

Upon the closing of the TMPL Sale on August 31, 2018, the KML Temporary Credit Facility was replaced with a new 4-year, C$500 million unsecured revolving credit facility for working capital purposes (“KML 2018 Credit Facility”) under a credit agreement with the Royal Bank of Canada (the “KML Credit Agreement”). In addition, the C$133 million (U.S. $102 million ) of outstanding borrowings under the KML Temporary Credit Facility were paid off prior to its termination with a portion of the proceeds from the TMPL Sale.

Depending on the type of loan requested, interest on borrowings outstanding are calculated based on: (i) a Canadian prime rate of interest; (ii) a U.S. base rate; (iii) LIBOR; or (iv) bankers’ acceptance fees, plus (i) in the case of Canadian prime rate or U.S. base rate loans, an applicable margin of up to 1.25% ; or (ii) in the case of LIBOR or bankers’ acceptance loans, an applicable margin ranging from 1.00% to 2.25% , with such margin in any case determined by KML’s debt credit rating. Standby fees for the unused portion of the KML 2018 Credit Facility will be calculated at a rate ranging from 0.20% to 0.45% based upon KML’s debt credit rating.

The KML Credit Agreement contains various financial and other covenants that apply to KML and its subsidiaries and that are common in such agreements, including a maximum ratio of KML’s consolidated total funded debt to its consolidated earnings before interest, income taxes, DD&A, and non-cash adjustments as defined in the KML Credit Agreement, of 5.00 :1.00 and restrictions on KML’s ability to incur debt, grant liens, make dispositions, engage in transactions with affiliates, make restricted payments, make investments, enter into sale leaseback transactions, amend organizational documents and engage in corporate reorganization transactions.

In addition, the KML Credit Agreement contains customary events of default, including non-payment; non-compliance with covenants (in some cases, subject to grace periods); payment default under, or acceleration events affecting, certain other indebtedness; bankruptcy or insolvency events involving KML or guarantors; and changes of control. If an event of default under the KML Credit Agreement exists and is continuing, the lenders could terminate their commitments and accelerate the maturity of the outstanding obligations under the KML Credit Agreement.

As of September 30, 2018 , KML had no borrowings outstanding under the KML 2018 Credit Facility, and had C $446 million (U.S. $345 million ) available under the KML 2018 Credit Facility, after reducing the C $500 million (U.S. $386 million) capacity for the C $54 million (U.S. $42 million ) in letters of credit. Of the total C$54 million of letters of credit issued, approximately C$50 million are related to Trans Mountain for which it has issued a backstop letter of credit to KML. As of September 30, 2018 , KML was in compliance with all required covenants. As of December 31, 2017, KML had no borrowings outstanding under the KML 2017 Credit Facility.

4. Stockholders’ Equity

Common Equity

As of September 30, 2018 , 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 2017 Form 10-K.

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the nine months ended September 30, 2018 , we repurchased approximately 13 million of our Class P shares for approximately $250 million . Since December of 2017, in total, we have repurchased approximately 27 million of our Class P shares under the program for approximately $500 million .

KMI Common Stock Dividends

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



	Three Months Ended September 30,				Nine Months Ended September 30,
	2018		2017		2018		2017
Per common share cash dividend declared for the period	$	0.20	$	0.125	$	0.60	$	0.375
Per common share cash dividend paid in the period	$	0.20	$	0.125	$	0.525	$	0.375

On October 17, 2018, our board of directors declared a cash dividend of $0.20 per common share for the quarterly period ended September 30, 2018 , which is payable on November 15, 2018 to common shareholders of record as of the close of business on October 31, 2018.

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 that, unless converted earlier at the option of the holders, will automatically convert into common stock on October 26, 2018. For additional information regarding our mandatory convertible preferred stock, see Note 11 to our consolidated financial statements included in our 2017 Form 10-K.

Preferred Stock Dividends

On July 18, 2018, 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 July 26, 2018 through and including October 25, 2018, which is payable on October 26, 2018 to mandatory convertible preferred shareholders of record as of the close of business on October 11, 2018.

Noncontrolling Interests

KML Distributions

KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount based on a portion of its DCF. For additional information regarding our KML distributions, see Note 11 to our consolidated financial statements included in our 2017 Form 10-K.

During the three and nine months ended September 30, 2018, KML paid dividends on its Restricted Voting Shares to the public valued at $13 million and $39 million , respectively, of which $10 million and $28 million , respectively, were paid in cash. The remaining values of $3 million and $11 million for the three and nine months ended September 30, 2018, respectively, were paid in 189,836 and 846,391 KML Restricted Voting Shares, respectively. KML also paid dividends to the public on its Series 1 and Series 3 Preferred Shares of $6 million and $16 million for the three and nine months ended September 30, 2018, respectively.

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 and net investments in foreign operations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

During the three and nine months ended September 30, 2018, due to volatility in certain basis differentials, we discontinued hedge accounting on certain of our crude derivative contracts as we do not expect them to be highly effective, for accounting purposes, in offsetting the variability in cash flows. As the forecasted transactions are still probable, accumulated gains and losses remain in other comprehensive income until earnings are impacted by the forecasted transactions. Future changes in the derivative contracts’ fair value subsequent to the discontinuance of hedge accounting will be reported in earnings. We may re-designate certain of these hedging relationships if their expected effectiveness improves.

Energy Commodity Price Risk Management

As of September 30, 2018 , 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	(16.4	)	MMBbl
Crude oil basis	(12.8	)	MMBbl
Natural gas fixed price	(28.1	)	Bcf
Natural gas basis	(29.4	)	Bcf
Derivatives not designated as hedging contracts
Crude oil fixed price	(7.6	)	MMBbl
Crude oil basis	(2.3	)	MMBbl
Natural gas fixed price	3.7		Bcf
Natural gas basis	(18.8	)	Bcf
NGL fixed price	(4.1	)	MMBbl

As of September 30, 2018 , 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 2022.

Interest Rate Risk Management

As of September 30, 2018 and December 31, 2017 , we had a combined notional principal amount of $10,575 million and $9,575 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 LIBOR plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of September 30, 2018 , 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 both September 30, 2018 and December 31, 2017, we had a combined 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.

During the three months ended September 30, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S. $1,888 million ). These swaps result in our selling fixed CAD and receiving fixed USD, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which KML expects to distribute in early January 2019. These foreign currency swaps are accounted for as net investment hedges as the foreign currency risk is related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincide with those of the net investment. As a result, the change in fair value of the foreign currency swaps is reflected in the Cumulative Translation Adjustment (CTA) section of Other Comprehensive Income (OCI).

Fair Value of Derivative Contracts

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



Fair Value of Derivative Contracts
		Asset derivatives				Liability derivatives
		September 30, 2018		December 31, 2017		September 30, 2018			December 31, 2017
	Location	Fair value				Fair value
Derivatives designated as hedging contracts
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	26	$	65	$	(159	)	$	(53	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		14		(61		)	(24		)
Subtotal		26		79		(220		)	(77		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	18		41		(33		)	(3		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	71		164		(242		)	(62		)
Subtotal		89		205		(275		)	(65		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(27		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	158		166		—			—
Subtotal		158		166		(27		)	(6		)
Total		273		450		(522		)	(148		)

Derivatives not designated as hedging contracts
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	7		8		(52		)	(22		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(71		)	(2		)
Total		7		8		(123		)	(24		)
Total derivatives		$	280	$	458	$	(645	)	$	(172	)

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 September 30,						Nine Months Ended September 30,
		2018			2017			2018			2017

Interest rate contracts	Interest, net	$	(72	)	$	(19	)	$	(326	)	$	(12	)

Hedged fixed rate debt	Interest, net	$	70		$	17		$	315		$	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)
	Three Months Ended September 30,							Three Months Ended September 30,							Three Months Ended September 30,
	2018			2017				2018			2017				2018		2017
Energy commodity derivative contracts	$	(84	)	$	(32	)	Revenues—Natural gas sales	$	(2	)	$	4		Revenues—Natural gas sales	$	—	$	—
							Revenues—Product sales and other	(3		)	13			Revenues—Product sales and other	6		4
							Costs of sales	2			1			Costs of sales	—		—
Interest rate contracts(c)	—			—			Earnings from equity investments	—			(1		)	Earnings from equity investments	—		—
Foreign currency contracts	(3		)	39			Other, net	(8		)	31			Other, net	—		—
Total	$	(87	)	$	7		Total	$	(11	)	$	48		Total	$	6	$	4



Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative (effective portion)(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(b)						Location	Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Nine Months Ended September 30,							Nine Months Ended September 30,							Nine Months Ended September 30,
	2018			2017				2018			2017				2018			2017
Energy commodity derivative contracts	$	(124	)	$	88		Revenues—Natural gas sales	$	(7	)	$	5		Revenues—Natural gas sales	$	—		$	—
							Revenues—Product sales and other	(30		)	33			Revenues—Product sales and other	(79		)	12
							Costs of sales	2			5			Costs of sales	—			—
Interest rate contracts(c)	2			(1		)	Earnings from equity investments	(4		)	(2		)	Earnings from equity investments	—			—
Foreign currency contracts	(11		)	98			Other, net	(39		)	103			Other, net	—			—
Total	$	(133	)	$	185		Total	$	(78	)	$	144		Total	$	(79	)	$	12

_______

(a)

We expect to reclassify an approximate $44 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balances as of September 30, 2018 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)	During the nine months ended September 30, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. All other 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 in net investment hedging relationships	Gain/(loss) recognized in OCI on derivative (effective portion)					Location	Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a)				Location	Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Three Months Ended September 30,						Three Months Ended September 30,					Three Months Ended September 30,
	2018			2017			2018		2017			2018		2017
Foreign currency contracts	$	(11	)	$	—	(Gain) loss on divestitures and impairments, net	$	12	$	—	Other, net	$	—	$	—
Total	$	(11	)	$	—	Total	$	12	$	—	Total	$	—	$	—



Derivatives in net investment hedging relationships	Gain/(loss) recognized in OCI on derivative (effective portion)					Location	Gain/(loss) reclassified from Accumulated OCI into income (effective portion)(a)				Location	Gain/(loss) recognized in income on derivative (ineffective portion and amount excluded from effectiveness testing)
	Nine Months Ended September 30,						Nine Months Ended September 30,					Nine Months Ended September 30,
	2018			2017			2018		2017			2018		2017
Foreign currency contracts	$	(11	)	$	—	(Gain) loss on divestitures and impairments, net	$	12	$	—	Other, net	$	—	$	—
Total	$	(11	)	$	—	Total	$	12	$	—	Total	$	—	$	—

_______


(a)	During the three and nine months ended September 30, 2018, we recognized a $12 million gain as a result of the TMPL Sale. See Note 2.



Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,						Nine Months Ended September 30,
		2018			2017			2018			2017
Energy commodity derivative contracts	Revenues—Natural gas sales	$	—		$	2		$	2		$	13
	Revenues—Product sales and other	(65		)	(18		)	(111		)	1
	Costs of sales	—			—			1			—
Total(a)		$	(65	)	$	(16	)	$	(108	)	$	14

_______


(a)	The three and nine months ended September 30, 2018 include approximate losses of $ 14 million and $ 11 million , respectively, and the three and nine months ended September 30, 2017 include approximate gains of $18 million and $47 million , respectively. These gains and losses were 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 September 30, 2018 and December 31, 2017 , we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2018 and December 31, 2017 , we had cash margins of $45 million and $1 million , respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The balance at September 30, 2018 consisted of initial margin requirements of $11 million and variation margin requirements of $34 million . We also use industry standard commercial agreements that 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 September 30, 2018 , based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would be required to post $185 million of additional collateral and $17 million of additional collateral beyond this $185 million if we were downgraded two notches.

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, 2017	$	(27	)	$	(189	)	$	(325	)	$	(541	)
Other comprehensive (loss) gain before reclassifications	(133		)	(51		)	16			(168		)
Losses reclassified from accumulated other comprehensive loss(a)	78			223			22			323
Impact of adoption of ASU 2018-02 (Note 1)	(4		)	(36		)	(69		)	(109		)
Net current-period other comprehensive income (loss)	(59		)	136			(31		)	46
Balance as of September 30, 2018	$	(86	)	$	(53	)	$	(356	)	$	(495	)



	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	185			80			20			285
Gains reclassified from accumulated other comprehensive loss	(144		)	—			—			(144		)
KML IPO	—			44			7			51
Net current-period other comprehensive income	41			124			27			192
Balance as of September 30, 2017	$	40		$	(164	)	$	(345	)	$	(469	)

_______


(a)	Amounts for foreign currency translation adjustments and pension and other postretirement liability adjustments reflect the deferred losses recognized in income during the nine months ended September 30, 2018, related to the TMPL Sale.

6. Fair Value

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

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


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


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


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

Fair Value of Derivative Contracts

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



	Balance sheet asset fair value measurements by level														Net amount
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting			Cash collateral held(b)			Net amount
As of September 30, 2018
Energy commodity derivative contracts(a)	$	1	$	32	$	—	$	33	$	(13	)	$	—		$	20
Interest rate contracts	—		89		—		89		(9		)	—			80
Foreign currency contracts	—		158		—		158		(13		)	—			145
As of December 31, 2017
Energy commodity derivative contracts(a)	$	17	$	70	$	—	$	87	$	(42	)	$	(12	)	$	33
Interest rate contracts	—		205		—		205		(15		)	—			190
Foreign currency contracts	$	—	$	166	$	—	$	166	$	(6	)	$	—		$	160



	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 September 30, 2018
Energy commodity derivative contracts(a)	$	(3	)	$	(340	)	$	—	$	(343	)	$	13	$	34	$	(296	)
Interest rate contracts	—			(275		)	—		(275		)	9		—		(266		)
Foreign currency contracts	—			(27		)	—		(27		)	13		—		(14		)
As of December 31, 2017
Energy commodity derivative contracts(a)	$	(3	)	$	(98	)	$	—	$	(101	)	$	42	$	—	$	(59	)
Interest rate contracts	—			(65		)	—		(65		)	15		—		(50		)
Foreign currency contracts	—			(6		)	—		(6		)	6		—		—

_______


(a)	Level 1 consists primarily of New York Mercantile Exchange natural gas futures. Level 2 consists primarily of over-the-counter West Texas Intermediate swaps and options and NGL swaps.


(b)	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.

Fair Value of Financial Instruments

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



	September 30, 2018				December 31, 2017
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	37,605	$	39,125	$	37,843	$	40,050

We used Level 2 input values to measure the estimated fair value of our outstanding debt balances as of both September 30, 2018 and December 31, 2017 .

7. Revenue Recognition

Adoption of Topic 606

Effective January 1, 2018, we adopted ASU No. 2014-09, “Revenue from Contracts with Customers” and the series of related accounting standard updates that followed (collectively referred to as “Topic 606”). We utilized the modified retrospective method to adopt Topic 606, which required us to apply the new revenue standard to (i) all new revenue contracts entered into after January 1, 2018 and (ii) revenue contracts that were not completed as of January 1, 2018. In accordance with this approach, our consolidated revenues for periods prior to January 1, 2018 were not revised. The cumulative effect of this adoption of Topic 606 as of January 1, 2018 was not material.

The impact to our consolidated financial statement line items from the adoption of Topic 606 for these changes was as follows (in millions):



	Three Months Ended September 30, 2018							Nine Months Ended September 30, 2018
Line Item	As Reported		Amounts Without Adoption of Topic 606		Effect of Change Increase/(Decrease)			As Reported		Amounts Without Adoption of Topic 606		Effect of Change Increase/(Decrease)
Consolidated Statement of Income
Natural gas sales	$	799	$	813	$	(14	)	$	2,353	$	2,391	$	(38	)
Services	1,959		2,012		(53		)	5,910		6,060		(150		)
Product sales and other	759		853		(94		)	2,100		2,353		(253		)
Total Revenues	3,517		3,678		(161		)	10,363		10,804		(441		)

Cost of sales	1,135		1,296		(161		)	3,222		3,663		(441		)
Operating Income	1,515		1,515		—			2,736		2,736		—

The effect-of-change amounts in the table above are attributable to the non-FERC-regulated portion of our Natural Gas Pipelines business segment, which provides gathering, processing and processed commodity sales services for various producers.

In those instances where we purchase and obtain control of the entire natural gas stream in our producer arrangements, we have determined these are contracts with suppliers rather than contracts with customers, and therefore, these arrangements are not included in the scope of Topic 606. These supplier arrangements are subject to updated guidance in ASC 705, Cost of Sales and Services, whereby any embedded fees within such contracts, which historically have been reported as Services revenue, are now reported as a reduction to Cost of sales upon adoption of Topic 606.

In our natural gas processing arrangements where we extract and sell the commodities derived from the processed natural gas stream (i.e., residue gas or NGLs), we may take control of: (i) none of the commodities we sell, (ii) a portion of the commodities we sell, or (iii) all of the commodities we sell.

In those instances where we remit all of the cash proceeds received from third parties for selling the extracted commodities, less the fees attributable to these arrangements, we have determined that the producer has control over these commodities. Upon adoption of Topic 606, we eliminated recording both sales revenue (Natural gas and Product) and Cost of sales amounts and now only record fees attributable to these arrangements to Service revenues.

In other instances where we do not obtain control of the extracted commodities we sell, we are acting as an agent for the producer and, upon adoption of Topic 606, we have continued to recognize Services revenue for the net amount of consideration we retain in exchange for our service.

When we purchase and obtain control of a portion of the residue gas or NGLs we sell, we have determined these arrangements contain both a supply and a service revenue element and therefore are partially in the scope of Topic 606. In these arrangements, the producer is a supplier for the cash settled portion of the commodity we purchase and a customer with

regards to the service provided to gather and redeliver the other component. Upon adoption of Topic 606, fees attributable to the supply element are recorded as a reduction to Cost of sales and fees attributable to the service element are recorded as Services revenue. Previously, we recognized Services revenue for both elements.

Revenue from Contracts with Customers

Beginning in 2018, we account for revenue from contracts with customers in accordance with Topic 606. The unit of account in Topic 606 is a performance obligation, which is a promise in a contract to transfer to a customer either a distinct good or service (or bundle of goods or services) or a series of distinct goods or services provided over a period of time. Topic 606 requires that a contract’s transaction price, which is the amount of consideration to which an entity expects to be entitled in exchange for transferring promised goods or services to a customer, is to be allocated to each performance obligation in the contract based on relative standalone selling prices and recognized as revenue when (point in time) or as (over time) control of the goods or services transfers to the customer and the performance obligation is satisfied.

Our customer sales contracts primarily include natural gas sales, NGL sales, crude oil sales, CO ₂ sales, and transmix sales contracts, as described below. Generally, for the majority of these contracts: (i) each unit (Mcf, gallon, barrel, etc.) of commodity is a separate performance obligation, as our promise is to sell multiple distinct units of commodity at a point in time; (ii) the transaction price principally consists of variable consideration, which amount is determinable each month end based on our right to invoice at month end for the value of commodity sold to the customer that month; and (iii) the transaction price is allocated to each performance obligation based on the commodity’s standalone selling price and recognized as revenue upon delivery of the commodity, which is the point in time when the customer obtains control of the commodity and our performance obligation is satisfied.

Our customer services contracts primarily include transportation service, storage service, gathering and processing service, and terminaling service contracts, as described below. Generally, for the majority of these contracts: (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, including a deficiency makeup period) as the services are rendered using a time-based (passage of time) or units-based (units of service transferred) output method for measuring the transfer of control of the services and satisfaction of our performance obligation over the service period, based on the nature of the promised service (e.g., firm or non-firm) and the terms and conditions of the contract (e.g., contracts with or without makeup rights).

Firm Services

Firm services (also called uninterruptible services) are services that are promised to be available to the customer at all times during the period(s) covered by the contract, with limited exceptions. Our firm service contracts are typically structured with take-or-pay or minimum volume provisions, which specify minimum service quantities a customer will pay for even if it chooses not to receive or use them in the specified service period (referred to as “deficiency quantities”). We typically recognize the portion of the transaction price associated with such provisions, including any deficiency quantities, as revenue depending on whether the contract prohibits the customer from making up deficiency quantities in subsequent periods, or the contract permits this practice, as follows:

•

Contracts without Makeup Rights. If contractually the customer cannot make up deficiency quantities in future periods, our performance obligation is satisfied, and revenue associated with any deficiency quantities is generally recognized as each service period expires. Because a service period may exceed a reporting period, we determine at inception of the contract and at the beginning of each subsequent reporting period if we expect the customer to take the minimum volume associated with the service period. If we expect the customer to make up all deficiencies in the specified service period (i.e., we expect the customer to take the minimum service quantities), the minimum volume provision is deemed not substantive and we will recognize the transaction price as revenue in the specified service period as the promised units of service are transferred to the customer. Alternatively, if we expect that there will be any deficiency quantities that the customer cannot or will not make up in the specified service period (referred to as “breakage”), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over such service period in proportion to the revenue that we will recognize for actual units of service transferred to the customer in the service period. For certain take-or-pay contracts where we make the service, or a part of the service (e.g., reservation), continuously available over the service period, we typically recognize the take-or-pay amount as revenue ratably over such period based on the passage of time.

•

Contracts with Makeup Rights. If contractually the customer can acquire the promised service in a future period and make up the deficiency quantities in such future period (the “deficiency makeup period”), we have a performance obligation to deliver those services at the customer’s request (subject to contractual and/or capacity constraints) in the deficiency makeup period. At inception of the contract, and at the beginning of each subsequent reporting period, we estimate if we expect that there will be deficiency quantities that the customer will or will not make up. If we expect the customer will make up all deficiencies it is contractually entitled to, any non-refundable consideration received relating to temporary deficiencies that will be made up in the deficiency makeup period will be deferred as a contract liability, and we will recognize that amount as revenue in the deficiency makeup period when either of the following occurs: (i) the customer makes up the volumes or (ii) the likelihood that the customer will exercise its right for deficiency volumes then becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires). Alternatively, if we expect at inception of the contract, or at the beginning of any subsequent reporting period, that there will be any deficiency quantities that the customer cannot or will not make up (i.e., breakage), we will recognize the estimated breakage amount (subject to the constraint on variable consideration) as revenue ratably over the specified service periods in proportion to the revenue that we will recognize for actual units of service transferred to the customer in those service periods.

Non-Firm Services

Non-firm services (also called interruptible services) are the opposite of firm services in that such services are provided to a customer on an “as available” basis. Generally, we do not have an obligation to perform these services until we accept a customer’s periodic request for service. For the majority of our non-firm service contracts, the customer will pay only for the actual quantities of services it chooses to receive or use, and we typically recognize the transaction price as revenue as those units of service are transferred to the customer in the specified service period (typically a daily or monthly period).

Nature of Revenue by Segment

Natural Gas Pipelines Segment

We provide various types of natural gas transportation and storage services, natural gas and NGL sales contracts, and various types of gathering and processing services for producers, including receiving, compressing, transporting and re-delivering quantities of natural gas and/or NGLs made available to us by producers to a specified delivery location.

Natural Gas Transportation and Storage Contracts

The natural gas we receive under our transportation and storage contracts remains under the control of our customers. Under firm service contracts, the customer generally pays a two-part transaction price that includes (i) a fixed fee reserving the right to transport or store natural gas in our facilities up to contractually specified capacity levels (referred to as “reservation”) and (ii) a per-unit rate for quantities of natural gas actually transported or injected into/withdrawn from storage. In our firm service contracts we generally promise to provide a single integrated service each day over the life of the contract, which is fundamentally a stand-ready obligation to provide services up to the customer’s reservation capacity prescribed in the contract. Our customers have a take-or-pay payment obligation with respect to the fixed reservation fee component, regardless of the quantities they actually transport or store. In other cases, generally described as interruptible service, there is no fixed fee associated with these transportation and storage services because the customer accepts the possibility that service may be interrupted at our discretion in order to serve customers who have firm service contracts. We do not have an obligation to perform under interruptible customer arrangements until we accept and schedule the customer’s request for periodic service. The customer pays a transaction price based on a per-unit rate for the quantities actually transported or injected into/withdrawn from storage.

Natural Gas and NGL Sales Contracts

Our sales and purchases of natural gas and NGL are primarily accounted for on a gross basis as natural gas sales or product sales, as applicable, and cost of sales. These customer contracts generally provide for the customer to nominate a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Gathering and Processing Contracts

We provide various types of gathering and processing services for producers, including receiving, processing, compressing, transporting and re-delivering quantities of natural gas made available to us by producers to a specified delivery location. This integrated service can be firm if subject to a minimum volume commitment or acreage dedication or non-firm when offered on an as requested, non-guaranteed basis. In our gathering contracts we generally promise to provide the contracted integrated services each day over the life of the contract. The customer pays a transaction price typically based on a per-unit rate for the quantities actually gathered and/or processed, including amounts attributable to deficiency quantities associated with minimum volume contracts.

CO ₂ Segment

Our crude oil, NGL, CO ₂ and natural gas production customer sales contracts typically include a specified quantity and quality of commodity product to be delivered and sold to the customer at a specified delivery point. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Terminals Segment

We provide various types of liquid tank and bulk terminal services. These services are generally comprised of inbound, storage and outbound handling of customer products.

Liquids Tank Services

Firm Storage and Handling Contracts: We have liquids tank storage and handling service contracts that include a promised tank storage capacity provision and prepaid volume throughput of the stored product. In these contracts, we have a stand-ready obligation to perform this contracted service each day over the life of the contract. The customer pays a transaction price typically in the form of a fixed monthly charge and is obligated to pay whether or not it uses the storage capacity and throughput service (i.e., a take-or-pay payment obligation). These contracts generally include a per-unit rate for any quantities we handle at the request of the customer in excess of the prepaid volume throughput amount and also typically include per-unit rates for additional, ancillary services that may be periodically requested by the customer.

Firm Handling Contracts: For our firm handling service contracts, we typically promise to handle on a stand-ready basis throughput volumes up to the customer’s minimum volume commitment amount. The customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it used the handling service. The customer pays a transaction price typically based on a per-unit rate for volumes handled, including amounts attributable to deficiency quantities.

Bulk Services

Our bulk storage and handling contracts generally include inbound handling of our customers’ dry bulk material product (e.g. petcoke, metals, ores) into our storage facility and outbound handling of these products from our storage facility. These services are provided on both a firm and non-firm basis. In our firm bulk storage and handling contracts, we are committed to handle and store on a stand-ready basis the minimum throughput quantity of bulk materials contracted by the customer. In some cases, the customer is obligated to pay for its minimum volume commitment amount, regardless of whether or not it uses the storage and handling service. The customer pays a transaction price typically based on a per-unit rate for quantities handled, including amounts attributable to deficiency quantities. For non-firm storage and handling services, the customer pays a transaction price typically based on a per-unit rate for quantities handled on an as requested, non-guaranteed basis.

Products Pipelines Segment

We provide crude oil and refined petroleum transportation and storage services on a firm or non-firm basis. For our firm transportation service, we typically promise to transport on a stand-ready basis the customer’s minimum volume commitment amount. The customer is obligated to pay for its volume commitment amount, regardless of whether or not it flows volumes into our pipeline. The customer pays a transaction price typically based on a per-unit rate for quantities transported, including amounts attributable to deficiency quantities. Our firm storage service generally includes a fixed monthly fee for the portion of storage capacity reserved by the customer and a per-unit rate for actual quantities injected into/withdrawn from storage. The customer is obligated to pay the fixed monthly reservation fee, regardless of whether or not it uses our storage facility (i.e., take-or-pay payment obligation). Non-firm transportation and storage service is provided to our customers when and to the

extent we determine the requested capacity is available in our pipeline system and/or terminal storage facility. The customer typically pays a per-unit rate for actual quantities of product injected into/withdrawn from storage and/or transported.

We sell transmix, crude oil or other commodity products. The customer’s contracts generally include a specified quantity of commodity products to be delivered and sold to the customers at specified delivery points. The customer pays a transaction price typically based on a market indexed per-unit rate for the quantities sold.

Kinder Morgan Canada Segment

On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have revenues on a prospective basis (see Note 2). Prior to the sale of these assets, we provided crude oil and refined petroleum transportation services generally as described above for non-firm, interruptible transportation services in our Products Pipelines business segment. The TMPL regulated tariff was designed to provide revenues sufficient to recover the costs of providing transportation services to shippers, including a return on invested capital. TMPL’s revenue was adjusted according to terms prescribed in our toll settlement with shippers as approved by the National Energy Board (NEB). Differences between transportation revenue recognized pursuant to our toll settlement and actual toll receipts were recognized as regulatory assets or liabilities and settled through future tolls.

Disaggregation of Revenues

The following tables present our revenues disaggregated by revenue source and type of revenue for each revenue source (in millions):



	Three Months Ended September 30, 2018
	Natural Gas Pipelines		CO ₂			Terminals		Products Pipelines		Kinder Morgan Canada		Corporate and Eliminations			Total
Revenues from contracts with customers
Services
Firm services(a)	$	778	$	—		$	230	$	142	$	—	$	(4	)	$	1,146
Fee-based services	215		17			163		204		41		1			641
Total services revenues	993		17			393		346		41		(3		)	1,787
Sales
Natural gas sales	804		—			—		—		—		(2		)	802
Product sales	390		313			8		52		—		—			763
Other sales	1		—			—		—		—		—			1
Total sales revenues	1,195		313			8		52		—		(2		)	1,566
Total revenues from contracts with customers	2,188		330			401		398		41		(5		)	3,353
Other revenues(b)	39		(14		)	101		34		3		1			164
Total revenues	$	2,227	$	316		$	502	$	432	$	44	$	(4	)	$	3,517



	Nine Months Ended September 30, 2018
	Natural Gas Pipelines		CO ₂			Terminals		Products Pipelines		Kinder Morgan Canada		Corporate and Eliminations			Total
Revenues from contracts with customers
Services
Firm services(a)	$	2,365	$	1		$	745	$	427	$	—	$	(12	)	$	3,526
Fee-based services	620		50			459		585		167		2			1,883
Total services revenues	2,985		51			1,204		1,012		167		(10		)	5,409
Sales
Natural gas sales	2,365		1			—		—		—		(6		)	2,360
Product sales	1,028		948			14		160		—		—			2,150
Other sales	5		—			—		—		—		—			5
Total sales revenues	3,398		949			14		160		—		(6		)	4,515
Total revenues from contracts with customers	6,383		1,000			1,218		1,172		167		(16		)	9,924
Other revenues(b)	176		(130		)	290		101		3		(1		)	439
Total revenues	$	6,559	$	870		$	1,508	$	1,273	$	170	$	(17	)	$	10,363

_______


(a)	Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with indexed-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.


(b)	Amounts recognized as revenue under guidance prescribed in Topics of the Accounting Standards Codification other than in Topic 606 and primarily include leases and derivatives. See Note 5 for additional information related to our derivative contracts.

Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections. We recognize contract assets in those instances where billing occurs subsequent to revenue recognition, and our right to invoice the customer is conditioned on something other than the passage of time. Our contract assets are substantially related to breakage revenue associated with our firm service contracts with minimum volume commitment payment obligations and contracts where we apply revenue levelization (i.e., contracts with fixed rates per volume that increase over the life of the contract for which we record revenue ratably per unit over the life of the contract based on our performance obligations that are generally unchanged over the life of the contract). Our contract liabilities are substantially related to (i) capital improvements paid for in advance by certain customers generally in our non-regulated businesses, which we subsequently recognize as revenue on a straight-line basis over the initial term of the related customer contracts; (ii) consideration received from customers for temporary deficiency quantities under minimum volume contracts that we expect will be made up in a future period, which we subsequently recognize as revenue when the customer makes up the volumes or the likelihood that the customer will exercise its right for deficiency volumes becomes remote (e.g., there is insufficient capacity to make up the volumes, the deficiency makeup period expires); and (iii) contracts with fixed rates per volume that decrease over the life of the contract where we apply revenue levelization for amounts received for our future performance obligations.

The following table presents the activity in our contract assets and liabilities (in millions):



	Nine Months Ended September 30, 2018
Contract Assets(a)
Balance at December 31, 2017	$	32
Additions	82
Transfer to Accounts receivable	(59		)
Balance at September 30, 2018	$	55
Contract Liabilities(b)
Balance at December 31, 2017	$	206
Additions	344
Transfer to Revenues	(254		)
Other(c)	(4		)
Balance at September 30, 2018	$	292

_______

(a)

Includes current balances of $46 million and $25 million reported within “Other current assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively, and includes non-current balances of $9 million and $7 million reported within “Deferred charges and other assets” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively.

(b)

Includes current balances of $79 million reported within “Other current liabilities” in our accompanying consolidated balance sheets at both September 30, 2018 and December 31, 2017 and includes non-current balances of $213 million and $127 million reported within “Other long-term liabilities and deferred credits” in our accompanying consolidated balance sheets at September 30, 2018 and December 31, 2017 , respectively.


(c)	Includes 2018 foreign currency translation adjustments associated with the balances at December 31, 2017 .

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2018 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):



Year	Estimated Revenue
Three months ended December 31, 2018	$	1,268
2019	4,595
2020	3,856
2021	3,301
2022	2,796
Thereafter	14,976
Total	$	30,792

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedients that we elected to apply, remaining performance obligations for: (i) contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation or to a wholly unsatisfied promise to transfer a distinct service that forms part of a series of distinct services; (ii) contracts with an original expected duration of one year or less; and (iii) contracts for which we recognize revenue at the amount for which we have the right to invoice for services performed.

8. Reportable Segments

Financial information by segment follows (in millions):



	Three Months Ended September 30,					Nine Months Ended September 30,
	2018			2017		2018			2017
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,225		$	2,022	$	6,552		$	6,283
Intersegment revenues	2			2		7			7
CO ₂	316			289		870			899
Terminals
Revenues from external customers	502			485		1,507			1,458
Intersegment revenues	—			—		1			1
Products Pipelines
Revenues from external customers	429			411		1,263			1,222
Intersegment revenues	3			1		10			10
Kinder Morgan Canada(c)	44			66		170			185
Corporate and intersegment eliminations(a)	(4		)	5		(17		)	8
Total consolidated revenues	$	3,517		$	3,281	$	10,363		$	10,073



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Segment EBDA(b)
Natural Gas Pipelines	$	976		$	884		$	2,425		$	2,846
CO ₂	205			197			561			636
Terminals	301			314			870			925
Products Pipelines	279			302			857			913
Kinder Morgan Canada(c)	654			50			746			136
Total Segment EBDA	2,415			1,747			5,459			5,456
DD&A	(569		)	(562		)	(1,710		)	(1,697		)
Amortization of excess cost of equity investments	(21		)	(15		)	(77		)	(45		)
General and administrative and corporate charges	(151		)	(164		)	(485		)	(490		)
Interest, net	(473		)	(459		)	(1,456		)	(1,387		)
Income tax expense	(196		)	(160		)	(314		)	(622		)
Total consolidated net income	$	1,005		$	387		$	1,417		$	1,215



	September 30, 2018		December 31, 2017
Assets
Natural Gas Pipelines	$	51,100	$	51,173
CO ₂	3,881		3,946
Terminals	9,356		9,935
Products Pipelines	8,497		8,539
Kinder Morgan Canada(c)	—		2,080
Corporate assets(d)	6,229		3,382
Total consolidated assets	$	79,063	$	79,055

_______


(a)	Three and nine month 2017 amounts include a management fee for services we perform as operator of an equity investee of $8 million and $26 million , respectively.


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


(c)	On August 31, 2018, the assets comprising the Kinder Morgan Canada business segment were sold; therefore, this segment will not have results of operations on a prospective basis (see Note 2).

(d)

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 activity) not allocated to our reportable segments.

9. Income Taxes

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



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
Income tax expense	$	196		$	160		$	314		$	622
Effective tax rate	16.3		%	29.3		%	18.1		%	33.9		%

The effective tax rate for the three and nine months ended September 30, 2018 is lower than the statutory federal rate of 21% primarily due to the lower Canadian capital gains tax rate applicable to the TMPL Sale, dividend-received deductions from our investment in Florida Gas Pipeline (Citrus), Plantation Pipe Line and Natural Gas Pipeline Company of America, and a reduction of our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits. These reductions are partially offset by state income taxes.

The effective tax rate for the three months ended September 30, 2017 is lower than the statutory federal rate of 35% primarily due to (i) dividend-received deductions from our investment in Florida Gas Transmission Company (Citrus) and Plantation Pipe Line; (ii) adjustments to our income tax reserve for uncertain tax positions; and (iii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision. These decreases are partially offset by (i) state and foreign income taxes; (ii) a change in our state effective tax rate; and (iii) tax deductions related to equity compensation.

The effective tax rate for the nine months ended September 30, 2017 is lower than the statutory federal rate of 35% primarily due to (i) dividend-received deductions from our investment in Citrus and Plantation Pipe Line; and (ii) the recognition of an enhanced oil recovery credit as a result of our federal return-to-provision; partially offset by state and foreign income taxes.

We continue to assess the impact of the Tax Cuts and Jobs Act of 2017 (2017 Tax Reform) on our business. Any adjustment to our provisional amounts recorded as of December 31, 2017 will be reported in the reporting period in which any such adjustments are determined and may be material in the period in which the adjustments are made. Earnings from equity investments on our statement of income for the three and nine months ended September 30, 2018 was decreased by $3 million ( $2 million impact to us after income tax benefit) and increased by $41 million ( $32 million impact to us after income tax expense), respectively, for our share of certain equity investees’ 2017 Tax Reform provisional adjustments. As a result of our provision to return adjustments, the 2017 Tax Reform transitional tax was reduced by $3 million for the three and nine months ended September 30, 2018. For additional information regarding the 2017 Tax Reform, see Note 5 to our consolidated financial statements included in our 2017 Form 10-K.

10. 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.

FERC Proceedings

FERC Rulemaking on Tax Cuts and Jobs Act for Jurisdictional Natural Gas Pipelines

On March 15, 2018, FERC issued a notice of proposed rule-making (NOPR) which proposed a process to implement for ratemaking purposes the 2017 Tax Reform. The NOPR proposed that each regulated interstate natural gas pipeline make a mandatory filing (Form 501-G) to reflect, based upon certain required assumptions, the rate impact of the reduced statutory corporate tax rate, and in the case of master limited partnerships and other pass-through entities, the elimination of an income tax allowance and unspecified resulting treatment of accumulated deferred income tax (ADIT) in the cost of service. The FERC’s NOPR also provided four options for regulated entities to consider: (1) make a limited filing under section 4 of the NGA to reduce rates for the impact of the 2017 Tax Reform; (2) commit to file a general section 4 rate case in the near future; (3) file an explanation why no rate change is needed, or (4) take no further action other than filing the required Form 501-G report. On July 18, 2018, FERC issued Order No. 849 (Final Rule) promulgating a final rule to implement the 2017 Tax Reform for jurisdictional natural gas pipelines. The Final Rule continues to require the regulated interstate pipelines to file the Form 501-G reflecting certain mandatory assumptions. The Final Rule also maintains substantially the same four options for regulated entities to implement the reduced corporate tax rate. The Final Rule clarifies that pass-through entities whose income consolidates up to a federal income tax paying entity are eligible for a tax allowance. It also clarifies that the required filing is a one-time informational filing and that FERC is not mandating any adjustment in rates as a function of complying with the Final Rule. Companies are also allowed to file an addendum which may reflect an income tax allowance, alternative capital structure and alternative equity returns. The Final Rule establishes a presumption that negotiated rate contracts should not be disturbed. We believe that the required, one-time, informational Form 501-G filings will be distorted, misleading and confusing to customers and investors. The Form 501-G filings will be made in three batches. The first filings were made on October 11, 2018 with additional filings by the remaining companies to be made in November and December of 2018. We continue to believe any initial, downward rate pressure will be mitigated and spread out over multiple years given the procedural options presented in the Final Rule, the prospective nature of rate changes under section 5 of the NGA and the fact that the FERC affirmed its intention to respect negotiated rate contracts. Many of our transportation and storage services are rendered pursuant to negotiated rate agreements that, consistent with the Final Rule, will not be subject to adjustment due to changes in tax law. Also, many of our current transactions are provided at discounted rates that are below maximum tariff rates, many of which would not be impacted by a change in the maximum tariff rate. Further, on many of our pipelines we are operating under settlements that preclude customers from requesting rate changes at the FERC during the life of the settlement.

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 2015 (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. On March 15, 2018, the FERC announced certain policy changes including a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) and, that same day, the FERC issued orders in a series of pending SFPP proceedings which combined to deny income tax allowance to SFPP, direct SFPP to make compliance filings in its 2008 and 2009 rate filing documents, and restart the 2011 SFPP complaint proceeding which had been abated. Requests for rehearing were filed in the Revised Policy Statement docket as well as the SFPP dockets in which the Revised Policy Statement was applied. The requests for rehearing in the SFPP dockets remain pending at the FERC. On July 18, 2018, the FERC issued an Order on Rehearing in the Revised Policy Statement docket in which it denied the rehearing petitions and clarified that the issue of entitlement to an income tax allowance will continue to be

resolved in individual proceedings, including proceedings involving income tax pass-through entities. The FERC also clarified that when an income tax allowance is eliminated from cost of service, previously ADIT balances associated with such income tax allowance may also be eliminated. With respect to the various SFPP related complaints and protest proceedings at the FERC, we estimate that the shippers are seeking approximately $30 million in annual rate reductions and approximately $320 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. All refund obligations related to the 2008 rate case were satisfied during calendar year 2015. 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. On February 23, 2018, a customer group filed a motion in the 2010 rate case requesting the FERC order us to recalculate the rates to be effective on January 1, 2018 to include impacts of the 2017 Tax Reform. We answered in opposition on March 12, 2018. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A, effectively denying the motion of the customer group, and requiring EPNG to implement the rates required by its rulings and provide refunds within 60 days. On July 2, 2018, EPNG reported to the FERC the refund calculations, and that the refunds had been provided as ordered. Also on July 2, 2018, EPNG initiated appellate review of Opinions 528, 528-A and 528-B. On August 23, 2018, the reviewing court established a briefing schedule and consolidated EPNG’s delayed appeal from the 2008 rate case, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case.

Other Commercial Matters

Union Pacific Railroad Company Easements Landowner Litigation

A purported class action lawsuit was filed in 2015 in a U.S. District Court in California against Union Pacific Railroad Company (UPRR), SFPP, KMGP and Kinder Morgan Operating L.P. “D” by private landowners who claimed to be the lawful owners of subsurface real property allegedly used or occupied by UPRR or SFPP for pipeline easements on rights-of-way held by UPRR. Substantially similar follow-on lawsuits were filed in federal courts by landowners in Nevada, Arizona and New Mexico. These suits, which were 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, asserted claims against UPRR, SFPP, KMGP, and Kinder Morgan Operating L.P. “D” alleging that the defendants’ occupation and use of the subsurface real property was improper. Plaintiffs’ motions for class certification were denied by the federal courts in Arizona and California. The Ninth Circuit Court of Appeals denied interlocutory review of the class certification decisions. The New Mexico and Nevada lawsuits were stayed. All pending lawsuits have been settled and dismissed on terms that are not material to KMI’s results of operations, cash flows or dividends to 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 was 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 sought 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. On June 29, 2018, the arbitration panel

delivered its Award, and the panel's ruling calls for the termination of the agreement and Eni USA's payment of compensation to GLNG. The Award resulted in our recording a net loss in the previous quarter of our equity investment in GLNG due to a non-cash impairment of our investment in GLNG partially offset by our share of earnings recognized by GLNG. On September 25, 2018, GLNG filed a lawsuit against Eni USA in the Delaware Court of Chancery to enforce the Award. On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered by Eni S.p.A. in connection with the terminal use agreement. GLNG intends to vigorously prosecute both lawsuits.

Brinckerhoff Merger Litigation

In April 2017, a purported class action suit was filed in the Delaware Court of Chancery by Peter Brinckerhoff, 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, Kinder Morgan Management, LLC and EPB that KMI and its subsidiaries did not already own. The suit alleged 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. The suit claimed that the alleged failure to obtain sufficient merger consideration for the drop down lawsuits constituted a breach of the EPB limited partnership agreement and the implied covenant of good faith and fair dealing. The suit also asserted 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. In November 2017, the Court dismissed the suit in its entirety. On June 8, 2018, the Delaware Supreme Court affirmed the dismissal. Also in November 2017, counsel for Brinckerhoff filed a separate lawsuit against KMEP and KMI seeking to recover up to $44 million in attorneys’ fees allegedly incurred in connection with the assertion of derivative claims that Brinckerhoff lost standing to pursue. On April 9, 2018, the Court dismissed the suit in its entirety, and that dismissal is final.

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 a U.S. District Court in Nevada, include a lawsuit brought by an industrial consumer in Kansas in which approximately $500 million in damages plus interest has been alleged against all defendants, and a Wisconsin class action in which approximately $300 million in damages plus interest has been alleged against all defendants. In the Wisconsin class action, the U.S. District Court denied plaintiff’s motion for class certification, but on appeal the Ninth Circuit Court of Appeals remanded the case with instructions to the U.S. District Court to provide a more detailed analysis of class certification issues. 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 September 30, 2018 and December 31, 2017, our total reserve for legal matters was $200 million and $350 million , respectively. The reduction in the reserve primarily resulted from the payment of refunds in the EPNG rate case matter discussed above in “— FERC Proceedings — EPNG.” The remaining reserve primarily relates to various claims from regulatory proceedings arising in our Products Pipelines business segment.

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 CO ₂ 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 CO ₂ .

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. 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 filed a lawsuit in 2010 against 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. KMGP was dismissed from the suit. 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 against KMEP and SFPP were 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. During the first quarter of 2018, KMEP and SFPP settled all claims made by the Roosevelt Irrigation District on terms that are not material to KMI’s results of operations, cash flows or dividends to shareholders.

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 and the immediate vicinity. On September 3, 2014, EPNG filed a complaint in the U.S. District Court for the District of Arizona seeking cost recovery and contribution from the applicable federal government agencies toward the cost of environmental activities associated with the mines, given the U.S. is the owner of the Navajo Reservation, the U.S.’s exploration and reclamation activities at the mines, and 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. In August 2017, the District Court found the U.S. liable under CERCLA as owner of the Navajo Reservation. The matter seeking cost recovery and contribution from federal government agencies is set for trial in February 2019. We intend to continue to prosecute and defend this case vigorously.

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 44 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 EPA approval remains 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 Record of Decision (ROD) for the lower eight 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 Occidental Chemical Company (OCC), a member of the PRP group requiring OCC to spend an estimated $165 million to perform engineering and design work necessary to begin the cleanup of the lower eight 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. On June 30, 2018 and July 13, 2018, respectively, OCC filed two separate lawsuits in the U.S. District Court for the District of New Jersey seeking cost recovery and contribution under CERCLA from more than 120 defendants, including EPEC Polymers. OCC alleges that each defendant is responsible to reimburse OCC for a proportionate share of the $165 million OCC is required to spend pursuant to its AOC. EPEC Polymers was dismissed without prejudice from the lawsuit on August 8, 2018.

In addition, the EPA and numerous PRPs, including EPEC Polymers, are engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Passaic River Study area. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the FFS and ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine mile segment not subject to the lower eight mile FFS and ROD. In a letter dated October 10, 2018, the EPA directed the CPG to prepare a streamlined FS for the Site that evaluates interim remedy alternatives for sediments in the upper nine miles of the Site. Until this FS is completed and the RI/FS is finalized, the scope of potential EPA claims for the Site is not reasonably estimable.

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 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). The case is one of numerous similar cases pending in Louisiana. 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. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) have intervened in the lawsuit. The Court has separated the defendants into several trial groups and set trials to begin in 2019. The case involving TGP was set for trial in 2020. During May 2018, the defendants removed numerous cases which allege violations under the Coastal Zone Management Act to federal court in Louisiana; the case involving TGP was removed to the U.S. District Court for the Eastern District of Louisiana. Thereafter, the defendants moved the U.S. Judicial Panel on Multidistrict Litigation to transfer all such cases, including the case involving TGP, to the U.S. District Court for the Eastern District of Louisiana for coordinated proceedings. On July 31, 2018, the Panel denied the motion. The plaintiffs and intervenors have moved to remand all of the cases, including the case involving TGP, to the state district courts. Those motions are pending. All of the cases, including the case involving TGP, remain effectively stayed pending resolution of the removal and remand issues. We will continue to vigorously defend the lawsuit.

Vermilion Parish Louisiana Coastal Zone Litigation

On July 28, 2016, the District Attorney for the Fifteenth Judicial District of Louisiana, purporting to act on behalf of Vermilion Parish and the State of Louisiana, filed a 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 alleged 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 sought 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 U.S. District Court for the Western District of Louisiana. Plaintiffs filed a motion to remand the case to the state district court. On September 26, 2017, the U.S. District Court remanded the case to the State District Court for Vermillion Parish. On March 2, 2018, Plaintiffs dismissed the claims made by Vermilion Parish and the State of Louisiana against TGP. During the pendency of the litigation, the LDNR and the LAG intervened in the lawsuit seeking damages from TGP and the other defendants for alleged violations of the Coastal Zone Management Act. On May 22, 2018, the LDNR and LAG likewise dismissed their claims against TGP.

Vintage Assets, Inc. Coastal Erosion Litigation

On December 18, 2015, Vintage Assets, Inc. and several individual landowners filed a lawsuit in the State 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 was held during September 2017. On May 4, 2018, the District Court entered a judgment dismissing the tort and negligence claims against all of the defendants, and dismissing certain of the contract claims against TGP. In ruling in favor of plaintiffs on the remaining contract claims, the District Court ordered the Defendants to pay $1,104 in money damages, and issued a permanent injunction ordering the Defendants to restore a total

of 9.6 acres of land and maintain certain canals at widths designated by the right of way agreements in effect. The Court stayed the judgment and the injunction pending appeal. The parties each filed a separate appeal to the U.S. Court of Appeals for the Fifth Circuit. On September 13, 2018, Highpoint Gas Transmission, LLC filed a motion to vacate the judgment and dismiss all of the appeals for lack of subject matter jurisdiction. On October 2, 2018, the Court of Appeals dismissed the appeals and remanded the suit to the U.S. District Court for the Eastern District of Louisiana. In doing so, the Court of Appeals ordered the District Court to remand the suit to the State District Court of Plaquemines Parish, Louisiana for further proceedings. We will continue 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 September 30, 2018 and December 31, 2017, we have accrued a total reserve for environmental liabilities in the amount of $270 million and $279 million , respectively. In addition, as of both September 30, 2018 and December 31, 2017, we have recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.

Other Contingencies

In 2017, in order to demonstrate to the NEB that Trans Mountain has sufficient financial resources to meet its responsibilities under Canada’s Pipeline Safety Act (the “Act”), we entered into a loan facility with Trans Mountain pursuant to which it may borrow up to C$500 million from us in the event that a TMPL environmental incident occurs giving rise to a liability on the part of Trans Mountain under the Act. Upon the closing of the TMPL Sale on August 31, 2018, the government of Canada delivered to us a C$500 million cash-collateralized letter of credit to fully backstop our obligation under the loan facility, which will continue until the NEB approves a replacement arrangement with which Trans Mountain may satisfy its financial resources requirement.

11. Recent Accounting Pronouncements

Topic 842

On February 25, 2016, the FASB issued ASU No. 2016-02, “ Leases (Topic 842) .” This ASU establishes a comprehensive new lease accounting model, which requires substantially all leases, with the exception for leases with a term of one year or less, to be recorded on the balance sheet as a lease liability measured as the present value of the future lease payments with a corresponding right-of-use asset. The ASU also requires disclosures designed to give financial statement users information on the amount, timing, and uncertainty of cash flows arising from leases.

On January 25, 2018, the FASB issued ASU No. 2018-01, “ Land Easement Practical Expedient for Transition to Topic 842 .” This ASU permits an entity to elect a transition practical expedient to not apply the provisions of ASU No. 2016-02 to land easements that existed or expired before the effective date of ASU No. 2016-02 and that were not previously accounted for as leases under the previous lease guidance in ASC Topic 840 “ Leases .”

On July 30, 2018, the FASB issued ASU No. 2018-11, “ Leases (Topic 842): Targeted Improvements .” This ASU permits an entity to elect an additional transition method to the existing modified retrospective transition requirements. Under the new transition method, an entity could adopt the provisions of ASU No. 2016-02 by recognizing a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption without adjustment to the financial statements for periods prior to adoption. Consequently, an entity’s reporting for the comparative periods presented in the financial statements in which it adopts the new leases standard will continue to be in accordance with the previous lease guidance in ASC Topic 840. ASU No. 2018-11 also allows a practical expedient that permits lessors to not separate non-lease components from the associated lease component if certain conditions are present.

We are in the process of finalizing our review of our lease agreements in light of Topic 842 guidance, implementing a financial lease accounting system, evaluating internal control changes to support management in the accounting for and disclosure of leasing activities, and assessing available transition practical expedients. While we are still in the process of completing our implementation evaluation of ASU No. 2016-02, we currently believe the most significant changes to our financial statements relate to the recognition of a lease liability and offsetting right-of-use asset in our Consolidated Balance Sheet for operating leases. ASU No. 2016-02 will be effective for us as of January 1, 2019.

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, and earlier adoption is permitted. 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, “ Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment. ” This ASU simplifies the accounting for goodwill impairment by removing Step 2 of the goodwill impairment test, which requires a hypothetical purchase price allocation. 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, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2017-12

On August 28, 2017, the FASB issued ASU No. 2017-12, “ Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities .” This ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. The guidance expands the ability to hedge nonfinancial and financial risk components, reduces complexity in fair value hedges of interest rate risk, eliminates the requirement to separately measure and report hedge ineffectiveness, and eases certain hedge effectiveness assessment requirements. While we are still in the process of completing our implementation evaluation of ASU No. 2017-12, we currently believe the most significant changes to our financial statements relate to (i) the ability to hedge contractually specified components of the price of forecasted purchases and sales of nonfinancial assets and (ii) the elimination of the concept of recognizing periodic hedge ineffectiveness for cash flow hedges. ASU No. 2017-12 will be effective for us as of January 1, 2019 and will be applied using a modified retrospective approach for existing cash flow hedging relationships as of the adoption date and prospectively for the presentation and disclosure guidance.

ASU No. 2018-13

On August 28, 2018, the FASB issued ASU No. 2018-13, “ Fair Value Measurement (Topic 820): Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement.” This ASU amends existing fair value measurement disclosure requirements by adding, changing, or removing certain disclosures. ASU No. 2018-13 will be effective for us as of January 1, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

ASU No. 2018-14

On August 28, 2018, the FASB issued ASU No. 2018-14, “ Compensation - Retirement Benefits - Defined Benefit Plans - General (Subtopic 715-20): Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans .” This ASU amends existing annual disclosure requirements applicable to all employers that sponsor defined benefit pension and other postretirement plans by adding, removing, and clarifying certain disclosures. ASU No. 2018-14 will be effective for us for the fiscal year ending December 31, 2020, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our financial statements.

12. 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.

Excluding fair value adjustments, as of September 30, 2018 , Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,658 million , $17,910 million , and $2,535 million , respectively, of Guaranteed Notes outstanding. Included in the Subsidiary Guarantors debt balance as presented in the accompanying September 30,

2018 condensed consolidating balance sheet is approximately $159 million of capital lease obligations that are not subject to the cross guarantee agreement.

On December 31, 2017, KMP’s interests in KMBT were transferred to KMI. The following condensed consolidating financial information reflects this transaction for all periods presented.

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 30, 2018 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	3,159		$	385		$	(27	)	$	3,517

Operating Costs, Expenses and Other
Costs of sales	—			—			1,083			68			(16		)	1,135
Depreciation, depletion and amortization	5			—			487			77			—			569
Other operating (income) expense	(23		)	—			783			(451		)	(11		)	298
Total Operating Costs, Expenses and Other	(18		)	—			2,353			(306		)	(27		)	2,002

Operating Income	18			—			806			691			—			1,515

Other Income (Expense)
Earnings from consolidated subsidiaries	1,183			1,138			579			28			(2,928		)	—
Earnings from equity investments	—			—			160			—			—			160
Interest, net	(201		)	(2		)	(273		)	3			—			(473		)
Amortization of excess cost of equity investments and other, net	7			—			1			(9		)	—			(1		)

Income Before Income Taxes	1,007			1,136			1,273			713			(2,928		)	1,201

Income Tax (Expense) Benefit	(275		)	73			(20		)	26			—			(196		)

Net Income	732			1,209			1,253			739			(2,928		)	1,005
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(273		)	(273		)

Net Income Attributable to Controlling Interests	732			1,209			1,253			739			(3,201		)	732

Preferred Stock Dividends	(39		)	—			—			—			—			(39		)
Net Income Available to Common Stockholders	$	693		$	1,209		$	1,253		$	739		$	(3,201	)	$	693

Net Income	$	732		$	1,209		$	1,253		$	739		$	(2,928	)	$	1,005
Total other comprehensive income	195			207			166			431			(738		)	261
Comprehensive income	927			1,416			1,419			1,170			(3,666		)	1,266
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(339		)	(339		)
Comprehensive income attributable to controlling interests	$	927		$	1,416		$	1,419		$	1,170		$	(4,005	)	$	927

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 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	$	8		$	—		$	2,899		$	413		$	(39	)	$	3,281

Operating Costs, Expenses and Other
Costs of sales	—			—			953			81			(27		)	1,007
Depreciation, depletion and amortization	4			—			487			71			—			562
Other operating expenses	13			1			737			147			(12		)	886
Total Operating Costs, Expenses and Other	17			1			2,177			299			(39		)	2,455

Operating (Loss) Income	(9		)	(1		)	722			114			—			826

Other Income (Expense)
Earnings from consolidated subsidiaries	690			681			111			15			(1,497		)	—
Earnings from equity investments	—			—			167			—			—			167
Interest, net	(174		)	(1		)	(277		)	(7		)	—			(459		)
Amortization of excess cost of equity investments and other, net	1			—			7			5			—			13

Income Before Income Taxes	508			679			730			127			(1,497		)	547

Income Tax Expense	(135		)	(1		)	(18		)	(6		)	—			(160		)

Net Income	373			678			712			121			(1,497		)	387
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(14		)	(14		)

Net Income Attributable to Controlling Interests	373			678			712			121			(1,511		)	373

Preferred Stock Dividends	(39		)	—			—			—			—			(39		)
Net Income Available to Common Stockholders	334			678			712			121			(1,511		)	334

Net Income	$	373		$	678		$	712		$	121		$	(1,497	)	$	387
Total other comprehensive income (loss)	14			(1		)	(3		)	105			(71		)	44
Comprehensive income	387			677			709			226			(1,568		)	431
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(44		)	(44		)
Comprehensive income attributable to controlling interests	$	387		$	677		$	709		$	226		$	(1,612	)	$	387

Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 30, 2018 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	9,286		$	1,170		$	(93	)	$	10,363

Operating Costs, Expenses and Other
Costs of sales	—			—			3,084			197			(59		)	3,222
Depreciation, depletion and amortization	14			—			1,457			239			—			1,710
Other operating (income) expense	(42		)	1			2,903			(133		)	(34		)	2,695
Total Operating Costs, Expenses and Other	(28		)	1			7,444			303			(93		)	7,627

Operating Income (Loss)	28			(1		)	1,842			867			—			2,736

Other Income (Expense)
Earnings from consolidated subsidiaries	1,987			1,828			726			48			(4,589		)	—
Earnings from equity investments	—			—			438			—			—			438
Interest, net	(578		)	(8		)	(819		)	(51		)	—			(1,456		)
Amortization of excess cost of equity investments and other, net	20			—			(14		)	7			—			13

Income Before Income Taxes	1,457			1,819			2,173			871			(4,589		)	1,731

Income Tax (Expense) Benefit	(342		)	69			(65		)	24			—			(314		)

Net Income	1,115			1,888			2,108			895			(4,589		)	1,417
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(302		)	(302		)

Net Income Attributable to Controlling Interests	1,115			1,888			2,108			895			(4,891		)	1,115

Preferred Stock Dividends	(117		)	—			—			—			—			(117		)
Net Income Available to Common Stockholders	$	998		$	1,888		$	2,108		$	895		$	(4,891	)	$	998

Net Income	$	1,115		$	1,888		$	2,108		$	895		$	(4,589	)	$	1,417
Total other comprehensive income	155			109			65			295			(443		)	181
Comprehensive income	1,270			1,997			2,173			1,190			(5,032		)	1,598
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(328		)	(328		)
Comprehensive income attributable to controlling interests	$	1,270		$	1,997		$	2,173		$	1,190		$	(5,360	)	$	1,270

Condensed Consolidating Statements of Income and Comprehensive Income for the Nine Months Ended September 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	$	26		$	—		$	8,959		$	1,190		$	(102	)	$	10,073

Operating Costs, Expenses and Other
Costs of sales	—			—			2,971			235			(68		)	3,138
Depreciation, depletion and amortization	12			—			1,451			234			—			1,697
Other operating expenses	38			1			2,139			373			(34		)	2,517
Total Operating Costs, Expenses and Other	50			1			6,561			842			(102		)	7,352

Operating (Loss) Income	(24		)	(1		)	2,398			348			—			2,721

Other Income (Expense)
Earnings from consolidated subsidiaries	2,283			2,242			323			50			(4,898		)	—
Earnings from equity investments	—			—			477			—			—			477
Interest, net	(528		)	9			(832		)	(36		)	—			(1,387		)
Amortization of excess cost of equity investments and other, net	1			—			13			12			—			26

Income Before Income Taxes	1,732			2,250			2,379			374			(4,898		)	1,837

Income Tax Expense	(543		)	(4		)	(53		)	(22		)	—			(622		)

Net Income	1,189			2,246			2,326			352			(4,898		)	1,215
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(26		)	(26		)

Net Income Attributable to Controlling Interests	1,189			2,246			2,326			352			(4,924		)	1,189

Preferred Stock Dividends	(117		)	—			—			—			—			(117		)
Net Income Available to Common Stockholders	1,072			2,246			2,326			352			(4,924		)	1,072

Net Income	$	1,189		$	2,246		$	2,326		$	352		$	(4,898	)	$	1,215
Total other comprehensive income	141			273			290			178			(692		)	190
Comprehensive income	1,330			2,519			2,616			530			(5,590		)	1,405
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(75		)	(75		)
Comprehensive income attributable to controlling interests	$	1,330		$	2,519		$	2,616		$	530		$	(5,665	)	$	1,330

Condensed Consolidating Balance Sheets as of September 30, 2018 (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	$	1	$	—	$	—	$	3,458	$	—		$	3,459
Other current assets - affiliates	4,275		4,650		22,762		981		(32,668		)	—
All other current assets	234		63		1,797		227		(14		)	2,307
Property, plant and equipment, net	218		—		30,707		6,870		—			37,795
Investments	664		—		6,668		100		—			7,432
Investments in subsidiaries	41,130		39,124		6,368		4,303		(90,925		)	—
Goodwill	13,789		22		5,166		2,988		—			21,965
Notes receivable from affiliates	958		20,349		374		994		(22,675		)	—
Deferred income taxes	3,258		—		—		—		(1,384		)	1,874
Other non-current assets	242		71		3,848		70		—			4,231
Total assets	$	64,769	$	64,279	$	77,690	$	19,991	$	(147,666	)	$	79,063

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	882	$	1,300	$	30	$	125	$	—		$	2,337
Other current liabilities - affiliates	12,997		14,138		4,658		875		(32,668		)	—
All other current liabilities	441		169		1,926		630		(14		)	3,152
Long-term debt	14,900		16,695		3,027		646		—			35,268
Notes payable to affiliates	1,321		448		20,551		355		(22,675		)	—
Deferred income taxes	—		—		499		885		(1,384		)	—
All other long-term liabilities and deferred credits	741		133		1,121		412		—			2,407
Total liabilities	31,282		32,883		31,812		3,928		(56,741		)	43,164

Redeemable noncontrolling interest	—		—		633		—		—			633
Stockholders’ equity
Total KMI equity	33,487		31,396		45,245		16,063		(92,704		)	33,487
Noncontrolling interests	—		—		—		—		1,779			1,779
Total stockholders’ equity	33,487		31,396		45,245		16,063		(90,925		)	35,266
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	64,769	$	64,279	$	77,690	$	19,991	$	(147,666	)	$	79,063

Condensed Consolidating Balance Sheets as of December 31, 2017 (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	$	3	$	—	$	—	$	262	$	(1	)	$	264
Other current assets - affiliates	6,214		5,201		22,402		858		(34,675		)	—
All other current assets	243		59		1,938		235		(24		)	2,451
Property, plant and equipment, net	236		—		31,093		8,826		—			40,155
Investments	665		—		6,498		135		—			7,298
Investments in subsidiaries	37,983		36,728		5,417		4,232		(84,360		)	—
Goodwill	13,789		22		5,166		3,185		—			22,162
Notes receivable from affiliates	1,033		20,363		1,233		776		(23,405		)	—
Deferred income taxes	3,635		—		—		—		(1,591		)	2,044
Other non-current assets	254		164		4,080		183		—			4,681
Total assets	$	64,055	$	62,537	$	77,827	$	18,692	$	(144,056	)	$	79,055

LIABILITIES AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	924	$	975	$	805	$	124	$	—		$	2,828
Other current liabilities - affiliates	13,225		14,188		6,512		750		(34,675		)	—
All other current liabilities	468		347		2,055		508		(25		)	3,353
Long-term debt	13,104		18,206		3,052		653		—			35,015
Notes payable to affiliates	2,009		448		20,593		355		(23,405		)	—
Deferred income taxes	—		—		449		1,142		(1,591		)	—
Other long-term liabilities and deferred credits	689		117		1,462		467		—			2,735
Total liabilities	30,419		34,281		34,928		3,999		(59,696		)	43,931

Stockholders’ equity
Total KMI equity	33,636		28,256		42,899		14,693		(85,848		)	33,636
Noncontrolling interests	—		—		—		—		1,488			1,488
Total stockholders’ equity	33,636		28,256		42,899		14,693		(84,360		)	35,124
Total Liabilities and Stockholders’ Equity	$	64,055	$	62,537	$	77,827	$	18,692	$	(144,056	)	$	79,055

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2018 (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	$	(2,355	)	$	2,879		$	8,204		$	869		$	(6,222	)	$	3,375

Cash flows from investing activities
Proceeds from the TMPL Sale, net of cash disposed	—			—			—			3,003			—			3,003
Acquisitions of assets and investments	—			—			(20		)	—			—			(20		)
Capital expenditures	(3		)	—			(1,433		)	(770		)	—			(2,206		)
Proceeds from sales of equity investments	—			—			33			—			—			33
Sales of property, plant and equipment, and other net assets, net of removal costs	6			—			(18		)	8			—			(4		)
Contributions to investments	—			—			(287		)	(7		)	—			(294		)
Distributions from equity investments in excess of cumulative earnings	1,932			—			197			—			(1,932		)	197
Funding to affiliates	(5,452		)	(30		)	(5,366		)	(780		)	11,628			—
Loans to related party	—			—			(23		)	—			—			(23		)
Net cash (used in) provided by investing activities	(3,517		)	(30		)	(6,917		)	1,454			9,696			686

Cash flows from financing activities
Issuances of debt	11,229			—			—			608			—			11,837
Payments of debt	(9,277		)	(975		)	(780		)	(189		)	—			(11,221		)
Debt issue costs	(24		)	—			—			(7		)	—			(31		)
Cash dividends - common shares	(1,163		)	—			—			—			—			(1,163		)
Cash dividends - preferred shares	(117		)	—			—			—			—			(117		)
Repurchases of common shares	(250		)	—			—			—			—			(250		)
Funding from affiliates	5,484			1,971			3,510			663			(11,628		)	—
Contributions from investment partner	—			—			148			—			—			148
Contributions from parents	—			—			19			—			(19		)	—
Contributions from noncontrolling interests	—			—			—			—			19			19
Distributions to parents	—			(3,801		)	(4,184		)	(228		)	8,213			—
Distributions to noncontrolling interests	—			—			—			—			(58		)	(58		)
Other, net	(12		)	—			—			(5		)	—			(17		)
Net cash provided by (used in) financing activities	5,870			(2,805		)	(1,287		)	842			(3,473		)	(853		)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	—			—			—			26			—			26

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(2		)	44			—			3,191			1			3,234
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3			1			—			323			(1		)	326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	1		$	45		$	—		$	3,514		$	—		$	3,560

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 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	$	(2,191	)	$	2,925		$	8,718		$	657		$	(6,802	)	$	3,307

Cash flows from investing activities
Acquisitions of assets and investments	—			—			(4		)	—			—			(4		)
Capital expenditures	(18		)	—			(1,699		)	(514		)	—			(2,231		)
Sales of property, plant and equipment, and other net assets, net of removal costs	7			—			98			13			—			118
Contributions to investments	(215		)	—			(408		)	(8		)	—			(631		)
Distributions from equity investments in excess of cumulative earnings	1,525			—			223			—			(1,496		)	252
Funding (to) from affiliates	(3,658		)	639			(5,533		)	(567		)	9,119			—
Loans to related party	(16		)	—			—			—			—			(16		)
Other, net	—			—			4			—			—			4
Net cash (used in) provided by investing activities	(2,375		)	639			(7,319		)	(1,076		)	7,623			(2,508		)

Cash flows from financing activities
Issuances of debt	7,570			—			—			220			—			7,790
Payments of debt	(8,053		)	(600		)	(895		)	(106		)	—			(9,654		)
Debt issue costs	(12		)	—			—			(57		)	—			(69		)
Cash dividends - common shares	(840		)	—			—			—			—			(840		)
Cash dividends - preferred shares	(117		)	—			—			—			—			(117		)
Funding from (to) affiliates	5,563			749			3,197			(390		)	(9,119		)	—
Contribution from investment partner	—			—			444			—			—			444
Contributions from parents, including proceeds from KML IPO and preferred share issuance	—			—			—			1,483			(1,483		)	—
Contributions from noncontrolling interests - net proceeds from KML IPO	4			—			—			—			1,241			1,245
Contributions from noncontrolling interests - net proceeds from KML preferred share issuance	—			—			—			—			230			230
Contributions from noncontrolling interests - other	—			—			—			—			12			12
Distributions to parents	—			(3,737		)	(4,154		)	(428		)	8,319			—
Distributions to noncontrolling interests	—			—			—			—			(26		)	(26		)
Other, net	(9		)	—			—			—			—			(9		)
Net cash provided by (used in) financing activities	4,106			(3,588		)	(1,408		)	722			(826		)	(994		)

Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			28			—			28

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(460		)	(24		)	(9		)	331			(5		)	(167		)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	471			36			9			272			(1		)	787
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	11		$	12		$	—		$	603		$	(6	)	$	620

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 2017 Form 10-K.

On January 1, 2018, we adopted ASU No. 2014-09, “ Revenue from Contracts with Customers ” and a series of related accounting standard updates (collectively referred to as “Topic 606”) designed to create improved revenue recognition and disclosure comparability in financial statements. For more information, see Note 7 “Revenue Recognition” to our consolidated financial statements.

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed its previously announced sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer of our staff that operate the business, which were indirectly acquired by the Government of Canada through Trans Mountain Corporation (a subsidiary of the Canada Development Investment Corporation) for cash consideration of C$4.43 billion (U.S. $3.4 billion), which is the contractual purchase price of $4.5 billion net of a preliminary working capital adjustment (the “TMPL Sale”). The contractual purchase price is subject to a customary final true up of the estimated working capital calculation as provided in the purchase agreement. These assets comprised our Kinder Morgan Canada business segment. We recognized a pre-tax gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated income statements during both the three and nine months ended September 30, 2018.

On September 4, 2018, we announced that KML’s board of directors approved a plan to distribute the net proceeds from the TMPL Sale, after capital gains taxes, customary purchase price adjustments and the repayment of debt outstanding under KML’s Temporary Credit Facility (see Note 3), as a return of capital to its shareholders. The KML board also approved a proposal to effect a consolidation or "reverse stock split" of KML’s Restricted Voting Shares on a one-for-three basis (three shares consolidating to one share). The return of capital requires a reduction in KML’s stated capital, which, together with the reverse stock split is subject to a two-thirds majority vote for approval by KML shareholders. The proposals will be voted on at a special meeting of KML’s shareholders scheduled to be held on November 29, 2018. We intend to vote for these proposals with our 70% voting and ownership interest in KML and use the proceeds we receive in respect of our interest in KML to pay down debt. The anticipated payment date for the return of capital is expected to be January 3, 2019. Our share of the after-tax proceeds is expected to be approximately $2 billion.

KML continues to manage a portfolio of strategic infrastructure assets across Western Canada, including (i) the crude terminal facilities, which constitute the largest merchant terminal storage position in the Edmonton market and the largest origination crude by rail loading facility in North America; (ii) the Vancouver Wharves Terminal, the largest mineral concentrate export/import facility on the west coast of North America; (iii) the Jet Fuel pipeline system; and (iv) the Canadian portion of the U.S. and Canadian Cochin pipeline system.

Results of Operations

Overview

Our management evaluates our performance primarily using the measures of Segment EBDA and, as discussed below under “—Non-GAAP Financial Measures,” 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.

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

Consolidated Earnings Results



	Three Months Ended September 30,
	2018			2017			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	976		$	884		$	92		10	%
CO ₂	205			197			8			4	%
Terminals	301			314			(13		)	(4	)%
Products Pipelines	279			302			(23		)	(8	)%
Kinder Morgan Canada(b)	654			50			604			1,208	%
Total Segment EBDA(c)	2,415			1,747			668			38	%
DD&A	(569		)	(562		)	(7		)	(1	)%
Amortization of excess cost of equity investments	(21		)	(15		)	(6		)	(40	)%
General and administrative and corporate charges(d)	(151		)	(164		)	13			8	%
Interest, net(e)	(473		)	(459		)	(14		)	(3	)%
Income before income taxes	1,201			547			654			120	%
Income tax expense	(196		)	(160		)	(36		)	(23	)%
Net income	1,005			387			618			160	%
Net income attributable to noncontrolling interests	(273		)	(14		)	(259		)	(1,850	)%
Net income attributable to Kinder Morgan, Inc.	732			373			359			96	%
Preferred stock dividends	(39		)	(39		)	—			—	%
Net income available to common stockholders	$	693		$	334		$	359		107	%



	Nine Months Ended September 30,
	2018			2017			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	2,425		$	2,846		$	(421	)	(15	)%
CO ₂	561			636			(75		)	(12	)%
Terminals	870			925			(55		)	(6	)%
Products Pipelines	857			913			(56		)	(6	)%
Kinder Morgan Canada(b)	746			136			610			449	%
Total Segment EBDA(c)	5,459			5,456			3			—	%
DD&A	(1,710		)	(1,697		)	(13		)	(1	)%
Amortization of excess cost of equity investments	(77		)	(45		)	(32		)	(71	)%
General and administrative and corporate charges(d)	(485		)	(490		)	5			1	%
Interest, net(e)	(1,456		)	(1,387		)	(69		)	(5	)%
Income before income taxes	1,731			1,837			(106		)	(6	)%
Income tax expense	(314		)	(622		)	308			50	%
Net income	1,417			1,215			202			17	%
Net income attributable to noncontrolling interests	(302		)	(26		)	(276		)	(1,062	)%
Net income attributable to Kinder Morgan, Inc.	1,115			1,189			(74		)	(6	)%
Preferred stock dividends	(117		)	(117		)	—			—	%
Net income available to common stockholders	$	998		$	1,072		$	(74	)	(7	)%

_______


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


(b)	As the assets comprising the Kinder Morgan Canada business segment were sold on August 31, 2018, this segment will not have results of operations on a prospective basis.

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

(c)

Three and nine month 2018 amounts include a net increase in earnings of $533 million and a net decrease in earnings of $268 million, respectively, and three and nine month 2017 amounts include a net decrease in earnings of $46 million and a net increase in earnings of $33 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.”

(d)

Three and nine month 2018 amounts include net increases in expense of $8 million and $18 million, respectively, and three and nine month 2017 amounts include net increases in expense of $5 million and $8 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.”


(e)	Nine month 2018 amount includes a net increase in expense of $34 million and three and nine month 2017 amounts include net decreases in expense of $4 million and $21 million, respectively, related to the combined effect of the certain items related to interest expense, net disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

The certain item totals reflected in footnotes (c) through (e) to the table above accounted for a $572 million increase in income before income taxes for the third quarter of 2018, as compared to the same prior year period (representing the difference between an increase of $525 million and a decrease of $47 million in income before income taxes for the third quarter of 2018 and 2017, respectively) and a $366 million decrease in income before income taxes for the nine months ended September 30, 2018, as compared to the same prior year period (representing the difference between a decrease of $320 million and an increase of $46 million in income before income taxes for the nine months ended September 30, 2018 and 2017, respectively).

After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining increases in income before income taxes from the prior year quarter and year-to-date were $82 million (14%) and $260 million (15%), respectively. The increases from 2017 are primarily attributable to increased performance from our Natural Gas Pipelines, CO2, Products Pipelines and Terminals business segments and decreased general and administrative expense partially offset by increased DD&A, interest expense, net and lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale.

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, as used to calculate our non-GAAP measures, 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, enactment of new tax legislation 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.

DCF

DCF is calculated by adjusting net income available to common stockholders before certain items for DD&A, total book and cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating 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. 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.

Reconciliation of Net Income Available to Common Stockholders to DCF



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except per share amounts)
Net Income Available to Common Stockholders	$	693		$	334		$	998		$	1,072
Add/(Subtract):
Certain items before book tax(a)	(533		)	47			356			(46		)
Noncontrolling interest certain items(b)	256			—			248			1
Book tax certain items(c)	45			(53		)	(149		)	(24		)
Impact of 2017 Tax Reform(d)	8			—			(36		)	—
Total certain items	(224		)	(6		)	419			(69		)

Net income available to common stockholders before certain items	469			328			1,417			1,003
Add/(Subtract):
DD&A expense(e)	682			661			2,056			2,018
Total book taxes(f)	169			241			512			725
Cash taxes(g)	(14		)	(9		)	(60		)	(54		)
Other items(h)	(19		)	(10		)	3			16
Sustaining capital expenditures(i)	(194		)	(156		)	(471		)	(416		)
DCF	$	1,093		$	1,055		$	3,457		$	3,292

Weighted average common shares outstanding for dividends(j)	2,218			2,241			2,217			2,240
DCF per common share	$	0.49		$	0.47		$	1.56		$	1.47
Declared dividend per common share	$	0.20		$	0.125		$	0.60		$	0.375

_______


(a)	Consists of certain items summarized in footnotes (c) through (e) to the “—Results of Operations—Consolidated Earnings Results” table included above, and described in more detail below in the footnotes to tables included in “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.


(b)	Represents noncontrolling interests share of certain items.


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


(d)	Represents 2017 Tax Reform provisional adjustments including our share of certain equity investees’ 2017 Tax Reform provisional adjustments.

(e)

Includes DD&A and amortization of excess cost of equity investments. Three and nine month 2018 amounts also include $92 million and $269 million, respectively, and three and nine month 2017 amounts also include $84 million and $276 million, respectively, of our share of certain equity investees’ DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A.


(f)	Excludes book tax certain items. Three and nine month 2018 amounts also include $18 million and $49 million, respectively, and three and nine month 2017 amounts also include $28 million and $79 million, respectively, of our share of taxable equity investees’ book taxes, net of the noncontrolling interests’ portion of KML book taxes.


(g)	Three and nine month 2018 amounts also include $(12) million and $(50) million, respectively, and three and nine month 2017 amounts also include $(9) million and $(54) million, respectively, of our share of taxable equity investees’ cash taxes.


(h)	Consists primarily of non-cash compensation associated with our restricted stock program and pension contributions.


(i)	Three and nine month 2018 amounts include $(37) million and $(77) million, respectively, and three and nine month 2017 amounts include $(29) million and $(74) million, respectively, of our share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.


(j)	Includes restricted stock awards that participate in common share 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 EBDA.

In the tables for each of our business segments under “ — Segment Earnings Results ” below, Segment EBDA before certain items and Revenues before certain items are calculated by adjusting the Segment EBDA and Revenues for the applicable certain item amounts, which are totaled in the tables and described in the footnotes to those tables. Revenues before certain items is provided to further enhance our analysis of Segment EBDA before certain items and is not a performance measure.

Segment Earnings Results

Natural Gas Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except operating statistics)
Revenues(a)	$	2,227		$	2,024		$	6,559		$	6,290
Operating expenses(b)	(1,380		)	(1,262		)	(3,909		)	(3,846		)
Loss on divestitures and impairments, net(b)	—			(27		)	(599		)	(27		)
Other income	—			—			1			—
Earnings from equity investments(b)	127			134			338			389
Other, net(b)	2			15			35			40
Segment EBDA(b)	976			884			2,425			2,846
Certain items(b)	33			44			667			6
Segment EBDA before certain items	$	1,009		$	928		$	3,092		$	2,852

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	209		10		%	$	288		5		%
Segment EBDA before certain items	$	81		9		%	$	240		8		%

Natural gas transport volumes (BBtu/d)(c)	32,867			28,879			32,234			28,796
Natural gas sales volumes (BBtu/d)(c)	2,615			2,181			2,517			2,329
Natural gas gathering volumes (BBtu/d)(c)	3,025			2,516			2,877			2,629
Crude/condensate gathering volumes (MBbl/d)(c)	313			271			302			268

_______

Certain items affecting Segment EBDA

(a)

Three and nine month 2018 amounts include decreases in revenue of $18 million and $23 million, respectively, and three and nine month 2017 amounts include a decrease of $12 million and an increase of $10 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales. Nine month 2018 amount also includes increases in revenue of $9 million related to a transportation contract refund and $5 million related to the early termination of a long-term natural gas transportation contract.

(b)

In addition to the revenue certain items described in footnote (a) above: three and nine month 2018 amounts also include (i) a decrease in earnings for both periods of $15 million associated with certain litigation matters; (ii) an increase in earnings of $7 million for both periods as a result of a property tax refund; (iii) a decrease in earnings of $3 million and an increase in earnings of $41 million, respectively, for our share of certain equity investees’ 2017 Tax Reform provisional adjustments; and (iv) decreases in earnings of $4 million and $8 million, respectively, related to other certain items. Nine month 2018 amount also includes (i) a $600 million non-cash loss on impairment of certain gathering and processing assets in Oklahoma; (ii) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset by our share of earnings recognized by Gulf LNG on the respective customer contract; and (iii) an increase in earnings of $6 million related to the release of certain sales and use tax reserves. Three and nine month 2017 amounts also include (i) decreases in earnings of $30 million for both periods related to a non-cash impairment loss associated with the Colden storage field; (ii) increases in earnings from our equity investment in EagleHawk of $12 million for both periods related to a customer contract settlement; (iii) decreases in earnings of $7 million and $12 million, respectively, related to early termination of debt at an equity investee; and (iv) decreases in earnings of $7 million and $8 million, respectively, from other certain items. Also, nine month 2017 amount includes an increase in earnings from an equity investment of $22 million on the sale of a claim related to the early termination of a long-term natural gas transportation contract.

Other


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

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and nine month periods ended September 30, 2018 and 2017 :

Three Months Ended September 30, 2018 versus Three Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
KinderHawk	$	14		93	%	$	14		70	%
EPNG	12			10	%	18			11	%
TGP	11			4	%	18			5	%
Hiland Midstream	10			22	%	(25		)	(15	)%
South Texas Midstream	10			20	%	86			35	%
NGPL(a)	10			200	%	9			n/a
Citrus(a)	9			28	%	—			—	%
Texas Intrastate Natural Gas Pipeline Operations	7			8	%	86			11	%
CIG	7			14	%	6			9	%
SNG(a)	4			14	%	—			—	%
Southern Gulf LNG(a)	(8		)	(67	)%	—			—	%
All others (including eliminations)	(5		)	(2	)%	(3		)	(1	)%
Total Natural Gas Pipelines	$	81		9	%	$	209		10	%

Nine Months Ended September 30, 2018 versus Nine Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
KinderHawk	$	25		50	%	$	26		42	%
EPNG	38			11	%	47			10	%
TGP	3			—	%	39			3	%
Hiland Midstream	41			31	%	(62		)	(12	)%
South Texas Midstream	8			5	%	157			22	%
NGPL(a)	23			115	%	27			n/a
Citrus(a)	19			23	%	—			—	%
Texas Intrastate Natural Gas Pipeline Operations	49			18	%	68			3	%
CIG	17			10	%	14			6	%
SNG(a)	13			15	%	1			4	%
Southern Gulf LNG(a)	(7		)	(20	)%	—			—	%
All others (including eliminations)	11			2	%	(29		)	(4	)%
Total Natural Gas Pipelines	$	240		8	%	$	288		5	%

_______

n/a - not applicable


(a)	Equity investment.

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 nine month periods ended September 30, 2018 and 2017 :


•	increases of $14 million (93%) and $25 million (50%), respectively, from KinderHawk primarily due to higher gathering revenues driven by an increase in volumes as a result of incremental production from the Haynesville shale formation;


•	increases of $12 million (10%) and $38 million (11%), respectively, from EPNG primarily due to higher transportation revenues driven by incremental Permian basin capacity sales;


•	increases of $11 million (4%) and $3 million ( — %), respectively, from TGP primarily due to higher firm transportation revenues from expansion projects placed in service in latter part of 2017 and higher transport volumes partially offset by lower capacity sales and higher operations and maintenance expense and ad valorem tax expense. The year-to-date

revenues also benefited from an increase in operational gas sales which was offset by an increase in associated gas cost for a net minimal impact on earnings;

•

increases of $10 million (22%) and $41 million (31%), respectively, from Hiland Midstream primarily due to increased volumes and higher NGL margins resulting from higher NGL sales prices. The year-to-date increase was also impacted by higher crude oil margins driven by higher crude oil transport and sales volumes. The decreases in revenues are primarily due to the effect of the January 1, 2018 adoption of Topic 606 as discussed in Note 7 “Revenue Recognition” to our consolidated financial statements which have corresponding decreases in cost of goods sold, and are partially offset by increases in NGL and crude oil sales;

•

increases of $10 million (20%) and $8 million (5%), respectively, from South Texas Midstream primarily due to increased volumes and higher NGL margins resulting from higher NGL sales prices for quarter-to-date and higher NGL sales prices for year-to-date. The increases in revenues are primarily due to higher NGL sales, partially offset by the effect of the January 1, 2018 adoption of Topic 606 which has a corresponding decrease in cost of goods sold;


•	increases of $10 million (200%) and $23 million (115%), respectively, from NGPL due to higher transportation revenue resulting from increased Permian basin-related activity and lower interest expense resulting from a 2017 refinancing, partially offset by lower storage revenue and a write-off of storage cushion volumes due to a storage field abandonment;


•	increases of $9 million (28%) and $19 million (23%), respectively, from Citrus primarily resulting from lower income tax expense due to the 2017 Tax Reform, lower operating expenses and the favorable outcome of a litigation matter;

•

increases of $7 million (8%) and $49 million (18%), respectively, from our Texas intrastate natural gas pipeline operations. The quarter-to-date increase was primarily due to new customer transportation service revenues, higher volumes with existing customers and higher sales margins primarily due to incremental volumes sold to certain customers and new customer sales revenues partially offset by lower park and loan revenues and storage margins. In addition to the above mentioned factors, the year-to-date increase was favorably impacted by higher weather-related volumes;


•	increases of $7 million (14%) and $17 million (10%), respectively, from CIG primarily due to higher firm transportation revenues driven by growth in the Denver Julesburg basin along with increased capacity sales, expansions and usage revenues due to improved midcontinent pricing;


•	increases of $4 million (14%) and $13 million (15%), respectively, from SNG. The quarter-to-date increase is primarily due to reduced corporate costs, reduced ad valorem taxes and an increase in the allowance for funds used during construction. The year-to-date increase is primarily due to higher transportation revenue, lower operating expenses and lower interest expense; and


•	decreases of $8 million (67%) and $7 million (20%), respectively, from Southern Gulf LNG primarily due to a ruling by an arbitration panel affecting a customer contract on its subsidiary Gulf LNG Holdings, LLC.

CO 2



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except operating statistics)
Revenues(a)	$	316		$	289		$	870		$	899
Operating expenses(b)	(120		)	(102		)	(336		)	(294		)
Gain on divestitures and impairments, net(b)	—			—			—			1
Earnings from equity investments	9			10			27			30
Segment EBDA(b)	205			197			561			636
Certain items(b)	28			20			130			23
Segment EBDA before certain items	$	233		$	217		$	691		$	659

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	35		11		%	$	98		11		%
Segment EBDA before certain items	$	16		7		%	$	32		5		%

Southwest Colorado CO ₂ production (gross)(Bcf/d)(c)	1.2			1.2			1.2			1.3
Southwest Colorado CO ₂ production (net)(Bcf/d)(c)	0.6			0.6			0.6			0.6
SACROC oil production (gross)(MBbl/d)(d)	28.7			27.5			29.1			27.7
SACROC oil production (net)(MBbl/d)(e)	23.9			22.9			24.3			23.1
Yates oil production (gross)(MBbl/d)(d)	16.5			17.1			16.9			17.5
Yates oil production (net)(MBbl/d)(e)	7.5			7.6			7.6			7.8
Katz, Goldsmith and Tall Cotton oil production (gross)(MBbl/d)(d)	8.0			8.4			8.2			7.9
Katz, Goldsmith and Tall Cotton oil production (net)(MBbl/d)(e)	6.8			7.1			7.0			6.7
NGL sales volumes (net)(MBbl/d)(e)	10.4			9.6			10.2			9.9
Realized weighted-average oil price per Bbl(f)	$	57.96		$	58.29		$	58.59		$	58.08
Realized weighted-average NGL price per Bbl(g)	$	36.46		$	24.70		$	33.30		$	23.89

_______

Certain items affecting Segment EBDA

(a)

Three and nine month 2018 amounts include unrealized losses of $28 million and $151 million, respectively, and the three and nine month 2017 amounts include unrealized losses of $20 million and $33 million, respectively, related to derivative contracts used to hedge forecasted commodity sales. Nine month 2017 amount also includes an increase in revenues of $9 million related to the settlement of a CO ₂ customer sales contract.


(b)	In addition to the revenue certain items described in footnote (a) above: nine month 2018 amount also includes an increase in earnings of $21 million as a result of a severance tax refund and nine month 2017 amount also includes a $1 million decrease 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 an approximately 97% working interest in the SACROC unit, an approximately 50% working interest in the Yates unit, an approximately 99% working interest in the Katz 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 all NGL sales.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and nine month periods ended September 30, 2018 and 2017 .

Three Months Ended September 30, 2018 versus Three Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)				Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	2	3	%	$	17	21	%
Oil and Gas Producing Activities	14		10	%	18		8	%
Total CO 2	$	16	7	%	$	35	11	%

Nine Months Ended September 30, 2018 versus Nine Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Source and Transportation Activities	$	(13	)	(6	)%	$	32	12	%
Oil and Gas Producing Activities	45			11	%	62		9	%
Intrasegment eliminations	—			—	%	4		14	%
Total CO 2	$	32		5	%	$	98	11	%

The changes in Segment EBDA for our CO ₂ business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and nine month periods ended September 30, 2018 and 2017 :

•

increase of $2 million (3%) and decrease of $13 million (6%), respectively, from our Source and Transportation activities primarily due to (i) higher CO ₂ sales of $5 million and lower CO ₂ sales $3 million, respectively, driven by lower volumes of $3 million and $21 million, respectively, offset by higher contract sales prices of $8 million and $18 million, respectively; (ii) lower other revenues of $2 million and $5 million, respectively; (iii) higher ad valorem tax expense of $2 million and $4 million, respectively; (iv) lower operating expenses of $2 million for both periods; and (v) decreased earnings from an equity investee of $1 million and $3 million, respectively. The increases in revenues of $17 million and $32 million, respectively, are primarily due to the effect of the January 1, 2018 adoption of Topic 606, which increased both revenues and operating expenses (costs of sales) by $14 million and $40 million, respectively, as discussed in Note 7 “Revenue Recognition” to our consolidated financial statements; and

•

increases of $14 million (10%) and $45 million (11%), respectively, from our Oil and Gas Producing activities primarily due to increased revenues of $18 million and $62 million, respectively, driven by higher NGL prices of $12 million and $37 million, respectively, and higher volumes of $6 million and $25 million, respectively, partially offset by increases of $3 million and $13 million, respectively, in operating expenses and higher severance tax expense of $1 million and $4 million, respectively.

Terminals



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except operating statistics)
Revenues(a)	$	502		$	485		$	1,508		$	1,459
Operating expenses(b)	(208		)	(202		)	(604		)	(575		)
Gain (loss) on divestitures and impairments, net(b)	1			22			(53		)	16
Earnings from equity investments	5			6			17			18
Other, net	1			3			2			7
Segment EBDA(b)	301			314			870			925
Certain items(b)	(2		)	(18		)	33			(28		)
Segment EBDA before certain items	$	299		$	296		$	903		$	897

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	19		4		%	$	54		4		%
Segment EBDA before certain items	$	3		1		%	$	6		1		%

Bulk transload tonnage (MMtons)	16.3			15.5			47.6			44.4
Ethanol (MMBbl)	16.0			17.8			47.1			51.3
Liquids tankage capacity available for service (MMBbl)	89.9			85.6			89.9			85.6
Liquids utilization %(c)	91.8		%	93.9		%	91.8		%	93.9		%

_______

Certain items affecting Segment EBDA


(a)	Nine month 2018 amount includes an increase in revenue of $2 million and three and nine month 2017 amounts include increases in revenue of $2 million and $7 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 nine month 2018 amounts also include (i) decreases in expense of $1 million and $18 million, respectively, related to hurricane damage insurance recoveries, net of repair costs and (ii) a gain of $1 million and a net loss of $53 million on divestitures and impairments, respectively. Three and nine month 2017 amounts also include increases in earnings of $23 million primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017 and decreases in earnings of $7 million related to hurricane repairs, and nine month 2017 amount also includes (i) a decrease in expense of $10 million related to accrued dredging costs; (ii) losses of $8 million related to divestitures and impairments, net; and (iii) an increase in earnings of $3 million related to other certain items.

Other


(c)	The ratio of our tankage capacity in service to tankage capacity available for service.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and nine month periods ended September 30, 2018 and 2017.

Three Months Ended September 30, 2018 versus Three Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	14		22	%	$	15		16	%
Southeast	(5		)	(29	)%	(3		)	(8	)%
Northeast	(4		)	(13	)%	(6		)	(11	)%
Gulf Central	(3		)	(15	)%	(3		)	(10	)%
Alberta Canada	(2		)	(6	)%	5			13	%
Marine Operations	—			—	%	7			9	%
All others (including intrasegment eliminations)	3			4	%	4			3	%
Total Terminals	$	3		1	%	$	19		4	%

Nine Months Ended September 30, 2018 versus Nine Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	21		10	%	$	30		10	%
Southeast	(6		)	(13	)%	(4		)	(3	)%
Northeast	(14		)	(15	)%	(14		)	(9	)%
Gulf Central	(14		)	(20	)%	(14		)	(14	)%
Alberta Canada	6			6	%	18			16	%
Marine Operations	8			6	%	37			17	%
All others (including intrasegment eliminations)	5			2	%	1			—	%
Total Terminals	$	6		1	%	$	54		4	%

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 nine month periods ended September 30, 2018 and 2017:


•	increases of $14 million (22%) and $21 million (10%), respectively, from our Gulf Liquids terminals primarily driven by contributions from expansion projects at our Pasadena Terminal and the Kinder Morgan Export Terminal as well as organic volume growth at several of our Houston Ship Channel locations;


•	decreases of $5 million (29%) and $6 million (13%), respectively, from our Southeast terminals primarily due to the sale of certain terminal assets in December 2017 and higher fuel and labor costs at our steel handling operations;


•	decreases of $4 million (13%) and $14 million (15%), respectively, from our Northeast terminals primarily due to low utilization at our Staten Island terminal;


•	decreases of $3 million (15%) and $14 million (20%), respectively, from our Gulf Central terminals primarily related to the sale of a 40% membership interest in the Deeprock Development joint venture in July 2017;

•

decrease of $2 million (6%) and increase of $6 million (6%), respectively, from our Alberta Canada terminals. The quarter-to-date decrease in earnings was primarily due to the impact of the expiration of a third party crude-by-rail terminaling contract at our Edmonton Rail Terminal joint venture and an increase in operating expenses associated with tank lease fees at our Edmonton South Terminal following the TMPL Sale. The year-to-date increase in earnings was

primarily due to the commencement of operations at our Base Line Terminal joint venture partially offset by above mentioned quarter-to-date drivers; and

•

flat and increase of $8 million (6%), respectively, from our Marine Operation. The year-to-date increase related to the incremental earnings from the March 2017, June 2017, July 2017 and December 2017 deliveries of the Jones Act tankers, the American Freedom , Palmetto State, American Liberty and American Pride, respectively, partially offset by decreased contributions from existing Jones Act tankers driven by lower charter rates.

Products Pipelines



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except operating statistics)
Revenues	$	432		$	412		$	1,273		$	1,232
Operating expenses(a)	(136		)	(124		)	(438		)	(353		)
Loss on divestitures and impairments, net(a)	(35		)	—			(35		)	(1		)
Other (expense) income	(1		)	—			1			—
Earnings from equity investments	19			17			56			40
Other, net	—			(3		)	—			(5		)
Segment EBDA(a)	279			302			857			913
Certain items(a)	30			—			60			(34		)
Segment EBDA before certain items	$	309		$	302		$	917		$	879

Change from prior period	Increase/(Decrease)
Revenues	$	20		5		%	$	41		3		%
Segment EBDA before certain items	$	7		2		%	$	38		4		%

Gasoline (MBbl/d)(b)	1,066			1,071			1,043			1,042
Diesel fuel (MBbl/d)	385			364			370			347
Jet fuel (MBbl/d)	312			298			302			297
Total refined product volumes (MBbl/d)(c)	1,763			1,733			1,715			1,686
NGL (MBbl/d)(c)	117			108			118			112
Crude and condensate (MBbl/d)(c)	327			289			335			323
Total delivery volumes (MBbl/d)	2,207			2,130			2,168			2,121
Ethanol (MBbl/d)(d)	132			121			127			116

_______

Certain items affecting Segment EBDA

(a)

Three and nine month 2018 amounts include (i) a decrease in earnings of $35 million associated with a project write-off on the Utica Marcellus Texas pipeline and (ii) an increase in earnings of $5 million as a result of a property tax refund. Nine month 2018 amount also includes an increase in expense of $31 million associated with a certain Pacific operations litigation matter and a decrease in expense of $1 million related to other certain items. Nine month 2017 amount includes a decrease in expense of $34 million related to a right-of-way settlement.

Other


(b)	Volumes include ethanol pipeline volumes.


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


(d)	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 nine month periods ended September 30, 2018 and 2017.

Three Months Ended September 30, 2018 versus Three Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Cochin pipeline	$	7		28	%	$	2	5	%
Double H Pipeline	4			31	%	5		29	%
South East Terminals	1			5	%	2		7	%
Crude & Condensate Pipeline	1			2	%	4		8	%
Plantation Pipe Line(a)	—			—	%	1		17	%
Pacific Operations	(5		)	(5	)%	1		1	%
All others (including eliminations)	(1		)	(1	)%	5		4	%
Total Products Pipelines	$	7		2	%	$	20	5	%

Nine Months Ended September 30, 2018 versus Nine Months Ended September 30, 2017



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Cochin pipeline	$	18		24	%	$	3	2	%
Double H Pipeline	12			27	%	14		25	%
South East Terminals	8			14	%	5		6	%
Crude & Condensate Pipeline	(10		)	(6	)%	4		2	%
Plantation Pipe Line(a)	10			21	%	1		6	%
Pacific Operations	(5		)	(2	)%	3		1	%
All others (including eliminations)	5			2	%	11		3	%
Total Products Pipelines	$	38		4	%	$	41	3	%

_______


(a)	Equity investment.

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 nine month periods ended September 30, 2018 and 2017:


•	increases of $7 million (28%) and $18 million (24%), respectively, from Cochin pipeline primarily driven by foreign exchange transaction losses in 2017 primarily related to an intercompany note receivable, integrity work during 2017 and increased services revenues driven by an expansion project completed in 2018;


•	increases of $4 million (31%) and $12 million (27%), respectively, from Double H pipeline was primarily due to the recognition of deficiency revenue and an increase in mainline revenues driven by an increase in volumes;


•	increases of $1 million (5%) and $8 million (14%), respectively, from South East Terminals primarily due to higher revenues as a result of higher volumes and favorable pricing on physical gains of product. The year-to-date increase was also impacted by an expansion project that was placed into service in third quarter 2017;


•	increase of $1 million (2%) and decrease of $10 million (6%), respectively, from our Kinder Morgan Crude & Condensate Pipeline. The year-to-date decrease in earnings was primarily due to approximately $25 million lower services revenues driven by a decrease in pipeline throughput volumes partially offset by recognition of deficiency revenue;


•	flat and increase of $10 million (21%), respectively, from Plantation Pipe Line. The year-to-date increase in equity earnings was primarily due to lower income tax expense due to the 2017 Tax Reform, lower operating expense attributable to a project write-off and net legal settlements and lower depreciation expense related to a change in depreciation rate in 2017; and


•	decreases of $5 million (5%) and $5 million (2%), respectively, from our Pacific Operations primarily due higher operating expenses driven by a change in product gain/loss and higher fuel and power costs.

Kinder Morgan Canada



	Three Months Ended September 30,						Nine Months Ended September 30,
	2018			2017			2018			2017
	(In millions, except operating statistics)
Revenues	$	44		$	66		$	170		$	185
Operating expenses	(19		)	(24		)	(72		)	(67		)
Gain on divestiture(a)	622			—			622			—
Other, net	7			8			26			18
Segment EBDA(a)	654			50			746			136
Certain items(a)	(622		)	—			(622		)	—
Segment EBDA before certain items	$	32		$	50		$	124		$	136

Change from prior period	Increase/(Decrease)
Revenues	$	(22	)	(33		)%	$	(15	)	(8		)%
Segment EBDA before certain items	$	(18	)	(36		)%	$	(12	)	(9		)%

Transport volumes (MBbl/d)(b)	292			319			291			309

_______

Certain items affecting Segment EBDA


(a)	Three and nine month 2018 amounts include a gain for both periods of $622 million on the TMPL Sale.

Other


(b)	Represents TMPL volumes reported until date of sale, August 31, 2018.

For the comparable three and nine month periods of 2018 and 2017, the Kinder Morgan Canada business segment had decreases in Segment EBDA of $18 million (36%) and $12 million (9%) primarily due to one less month of earnings from TMPL due to its August 31, 2018 sale. The year-to-date decrease was partially offset by higher capitalized equity financing costs due to spending on TMEP. As the assets comprising the Kinder Morgan Canada business segment were sold on August 31, 2018, this segment will not have results of operations on a prospective basis.

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



	Three Months Ended September 30,
	2018			2017			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	151		$	164		$	(13	)	(8	)%
Certain items(a)	(8		)	(5		)	(3		)	(60	)%
General and administrative and corporate charges before certain items(a)	$	143		$	159		$	(16	)	(10	)%

Interest, net(b)	$	473		$	459		$	14		3	%
Certain items(b)	—			4			(4		)	(100	)%
Interest, net, before certain items(b)	$	473		$	463		$	10		2	%

Net income attributable to noncontrolling interests(c)	$	273		$	14		$	259		1,850	%
Noncontrolling interests associated with certain items(c)	(256		)	—			(256		)	n/a
Net income attributable to noncontrolling interests before certain items(c)	$	17		$	14		$	3		21	%



	Nine Months Ended September 30,
	2018			2017			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	485		$	490		$	(5	)	(1	)%
Certain items(a)	(18		)	(8		)	(10		)	(125	)%
General and administrative and corporate charges before certain items(a)	$	467		$	482		$	(15	)	(3	)%

Interest, net(b)	$	1,456		$	1,387		$	69		5	%
Certain items(b)	(34		)	21			(55		)	(262	)%
Interest, net, before certain items(b)	$	1,422		$	1,408		$	14		1	%

Net income attributable to noncontrolling interests(c)	$	302		$	26		$	276		1,062	%
Noncontrolling interests associated with certain items(c)	(248		)	(1		)	(247		)	(24,700	)%
Net income attributable to noncontrolling interests before certain items(c)	$	54		$	25		$	29		116	%

________

n/a - not applicable

Certain items

(a)

Three and nine month 2018 amounts include (i) increases in expense of $5 million and $7 million, respectively of asset sale related costs; (ii) increases in expense of $1 million and $8 million, respectively, related to certain corporate litigation matters; and (iii) increases in expense of $2 million and $5 million, respectively, related to other certain items. Nine month 2018 amount also includes (i) an increase in expense of $10 million associated with an environmental reserve adjustment and (ii) a decrease in expense of $12 million related to the release of certain sales and use tax reserves. Three and nine month 2017 amounts include (i) increases in expense of $1 million and $3 million, respectively, related to certain corporate legal matters and (ii) an increase in expense of $4 million and a decrease in expense of $2 million, respectively, related to other certain items. Nine month 2017 amount also includes an increase in expense of $7 million related to acquisition and asset sale related costs.

(b)

Three and nine month 2018 amounts include (i) decreases in interest expense of $7 million and $25 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions; (ii) increases in interest expense of $2 million and $10 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness; (iii) increases in interest expense of $1 million and $47 million, respectively, related to the write-off of capitalized KML credit facility fees; and (iv) increases in interest expense of $4 million and $2 million, respectively, related to other certain items. Three and nine month 2017 amounts include (i) decreases in interest expense of $6 million and $35 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in interest expense of $2 million and $6 million, respectively, related to non-cash true-ups of our estimates of swap ineffectiveness. Nine month 2017 amount also includes an increase in interest expense of $8 million related to other certain items.


(c)	Three and nine month 2018 amounts are primarily associated with the $622 million gain on the TMPL Sale.

The decreases in general and administrative expenses and corporate charges before certain items of $16 million and $15 million, respectively, for the three and nine months ended September 30, 2018 when compared with the respective prior year periods were primarily driven by higher capitalized costs and one less month of costs from TMPL due to its August 31, 2018 sale. The year-to-date decrease was partially offset by higher state franchise tax expense due to a favorable adjustment in 2017 and the establishment of a contingent liability associated with a legacy asset.

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 nine months ended September 30, 2018 when compared with the respective prior year periods increased $10 million and $14 million, respectively. The increases in interest expense were primarily due to higher short-term interest rates partially offset by lower weighted average debt balances.

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 September 30, 2018 and December 31, 2017, approximately 32% and 28%, respectively, of the principal amount of our debt balances 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 nine months ended September 30, 2018 when compared with the respective prior year periods increased $3 million and $29 million, respectively, primarily due to the May 30, 2017 sale of approximately 30% of our Canadian business operations to the public in the KML IPO.

Income Taxes

Our tax expense for the three months ended September 30, 2018 was approximately $196 million as compared with $160 million for the same period of 2017. The $36 million increase in tax expense was primarily due to an increase in pre-tax earnings as a result of the gain recognized on the TMPL Sale in the three months ended September 30, 2018; partially offset by the reduction in the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018 and adjustments to our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits in 2018.

Our tax expense for the nine months ended September 30, 2018 was approximately $314 million as compared with $622 million for the same period of 2017. The $308 million decrease in tax expense was primarily due to the reduction in the U.S. federal corporate income tax rate from 35% to 21% effective January 1, 2018 and adjustments to our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits in 2018.

Liquidity and Capital Resources

General

As of September 30, 2018 , we had $3,459 million of “Cash and cash equivalents,” an increase of $3,195 million ( 1,210% ) from December 31, 2017 . 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 $3,375 million and $3,307 million in the first nine months of 2018 and 2017 , respectively. The period-to-period increase is discussed below in “Cash Flows—Operating Activities.” Generally, we primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures. We also generally 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. Moreover, as a result of our current common stock dividend policy and our continued focus on disciplined capital allocation, we do not expect the need to access the equity capital markets to fund our other growth projects for the foreseeable future.

Additionally, the TMPL Sale mentioned above in “— General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project ” was completed on August 31, 2018. On September 4, 2018, we announced that KML’s board of directors approved a plan to distribute the net proceeds from the TMPL Sale, after capital gains taxes, customary purchase price adjustments and the repayment of debt outstanding under the KML Temporary Credit Facility as discuss below, as a return of capital to its shareholders. The KML board also approved a proposal to effect a consolidation or "reverse stock split" of KML’s Restricted Voting Shares on a one-for-three basis (three shares consolidating to one share). The return of capital requires a reduction in KML’s stated capital, which, together with the reverse stock split is subject to a two-thirds majority vote for approval by KML shareholders. The proposals will be voted on at a special meeting of KML’s shareholders currently scheduled to be held on November 29, 2018. We intend to vote for these proposals with our 70% voting and ownership interest in KML and use the proceeds we receive in respect of our interest in KML to pay down debt. The anticipated payment date for the proposed return of capital is expected to be January 3, 2019, and our share of the after-tax proceeds is expected to be approximately $2 billion.

KML 2018 Credit Facility

Upon the closing of the TMPL Sale on August 31, 2018, KML established a 4-year, C$500 million unsecured revolving credit facility (the “KML 2018 Credit Facility”) for working capital purposes, replacing a temporary credit facility that was put in place following the announcement of the TMPL Sale on May 30, 2018 (the “KML Temporary Credit Facility”). The C$133 million (U.S.$102 million) of outstanding borrowings under the KML Temporary Credit Facility were paid off prior to its termination with a portion of the proceeds from the TMPL Sale. As of September 30, 2018, there were no outstanding borrowings under the KML 2018 Credit Facility.

Short-term Liquidity

As of September 30, 2018 , 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) the KML 2018 Credit Facility (for KML’s working capital needs); 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 ours and KML’s respective credit facilities. 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 September 30, 2018 , our $2,337 million of short-term debt consisted primarily of (i) $675 million outstanding borrowings under the KMI $5.0 billion revolving credit facility; (ii) $207 million outstanding under our $4.0 billion commercial paper program; and (iii) $1,300 million of senior notes that mature in the next twelve months. As previously mentioned, we intend to use our share of proceeds from the TMPL Sale after the anticipated return of capital dividend from KML to pay down debt. To the extent that our short-term debt requirements exceeds our share of the proceeds from the TMPL Sale, the proceeds are used to pay down long-term debt requirements, or there is a timing difference in debt obligations coming due versus the anticipated return of capital dividend by KML, 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. Our short-term debt balance as of December 31, 2017 was $2,828 million .

We had a working capital (defined as current assets less current liabilities) surplus of $277 million and a deficit of $3,466 million as of September 30, 2018 and December 31, 2017 , respectively. Our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we generally expect to pay down using retained cash from operations. The overall $3,743 million ( 108% ) favorable change from year-end 2017 was primarily due to (i) the $3,003 million of proceeds from the TMPL Sale, net of cash disposed, with approximately $919 million (estimated as of September 30, 2018) of such proceeds expected to be paid to noncontrolling interests as a return of capital, see above in “— General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project; ” (ii) a decrease in credit facility and commercial paper borrowings and in the current portion of long-term debt; and (iii) a net decrease in accrued interest and accrued contingencies. 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.

Our capital expenditures for the nine months ended September 30, 2018 , and the amount we expect to spend for the remainder of 2018 to sustain and grow our businesses are as follows:



	Nine Months Ended September 30, 2018		2018 Remaining		Total 2018
	(In millions)
Sustaining capital expenditures(a)(b)	$	471	$	179	$	650
KMI Discretionary capital investments(b)(c)(d)	$	1,719	$	739	$	2,458
KML Discretionary capital investments(b)(e)	$	394	$	34	$	428

_______


(a)	Nine months ended September 30, 2018, 2018 Remaining, and Total 2018 amounts include $77 million, $30 million, and $107 million, respectively, for our proportionate share of (i) certain equity investee’s, (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.


(b)	Nine months ended September 30, 2018 amount includes $119 million of net changes from accrued capital expenditures, contractor retainage, and other.


(c)	Nine months ended September 30, 2018 amount includes $182 million of our contributions to certain unconsolidated joint ventures for capital investments.


(d)	Amounts include our actual or estimated contributions to certain unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.


(e)	Amounts exclude TMEP 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, 2017 in our 2017 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2018 and December 31, 2017 were $528 million and $845 million, respectively. The decrease was primarily driven by a reduction in capital commitments related to the TMEP resulting from the TMPL Sale.

Cash Flows

Operating Activities

The net increase of $68 million in cash provided by operating activities for the nine months ended September 30, 2018 compared to the respective 2017 period was primarily attributable to:


•	a $50 million increase associated with net changes in working capital items and non-current assets and liabilities, primarily driven, among other things, by an increase in current income tax liabilities associated with the tax gain on the TMPL Sale in the 2018 period, partially offset by higher payments for litigation matters in the 2018 period compared with the 2017 period; and

•

an $18 million increase in operating cash flow resulting from the combined effects of adjusting the $202 million increase in net income for the period-to-period net changes in non-cash items including the following: (i) net losses on divestitures and impairments, net and an equity investment (see discussion above in “—Results of Operations”); (ii) the 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 $3,194 million net increase in cash provided by investing activities for the nine months ended September 30, 2018 compared to the respective 2017 period was primarily attributable to:


•	a $3,003 million increase in cash reflecting proceeds received from the TMPL Sale, net of cash disposed in the 2018 period. See Note 2 “Divestitures” for further information regarding this transaction;


•	a $337 million decrease in cash used for contributions to equity investments primarily due to lower contributions we made to NGPL Holdings LLC, Fayetteville Express Pipeline LLC and Utopia Holding LLC in the 2018 period

compared to the 2017 period, partially offset by the contributions made to Gulf Coast Express Pipeline LLC in the 2018 period; and


•	a $122 million decrease in cash proceeds from sale of property, plant and equipment and other net assets in the 2018 period compared to the 2017 period.

Financing Activities

The net decrease of $141 million in cash used in financing activities for the nine months ended September 30, 2018 compared to the respective 2017 period was primarily attributable to:


•	a $2,518 million net increase in cash related to debt activity as a result of net debt issuances in the 2018 period compared to net debt payments in the 2017 period. See Note 3 “Debt” for further information regarding our debt activity; partially offset by,


•	a combined $1,475 million decrease in cash reflecting $1,245 million net proceeds we received from the KML IPO in May 2017 and $230 million net proceeds received from the KML preferred share issuance in the 2017 period;


•	a $323 million increase in dividend payments to our common shareholders;


•	a $296 million decrease in cash due to lower contributions received from EIG in the 2018 period compared to the 2017 period as the 2017 period included $386 million we received from EIG for our sale of a 49% partnership interest in ELC; and


•	a $250 million increase in cash used in 2018 for common shares repurchased under our common share buy-back program.

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 that, unless converted earlier at the option of the holders, will automatically convert into common stock on October 26, 2018. Based on the current market price of our common stock, each Series A Preferred Share will convert into 36.2840 shares of our common stock (approximately 58 million common shares).

Dividends and Stock Buyback Program

KMI Common Stock Dividends

We expect to declare common stock dividends of $0.80 per share on our common stock for 2018.



Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2017	$	0.125	January 17, 2018	January 31, 2018	February 15, 2018
March 31, 2018	$	0.20	April 18, 2018	April 30, 2018	May 15, 2018
June 30, 2018	$	0.20	July 18, 2018	July 31, 2018	August 15, 2018
September 30, 2018	$	0.20	October 17, 2018	October 31, 2018	November 15, 2018

The actual amount of common stock 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 2017 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 Stock 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, 2017 through January 25, 2018	$	24.375	October 18, 2017	January 11, 2018	January 26, 2018
January 26, 2018 through April 25, 2018	$	24.375	January 18, 2018	April 11, 2018	April 26, 2018
April 26, 2018 through July 25, 2018	$	24.375	April 18, 2018	July 11, 2018	July 26, 2018
July 26, 2018 through October 25, 2018	$	24.375	July 18, 2018	October 11, 2018	October 26, 2018

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, our board of directors approved a $2 billion share buyback program that began in December 2017. In the first nine months of 2018, we repurchased approximately 13 million of our Class P shares for approximately $250 million . Since December of 2017, in total, we have repurchased approximately 27 million of our Class P shares under the program for approximately $500 million.

Noncontrolling Interests

KML Distributions

KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares 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. KML intends to pay quarterly dividends, if any, on or about the 45th day (or next business day) following the end of each calendar quarter 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.

On October 17, 2018, KML’s board of directors declared a dividend for the quarterly period ended September 30, 2018 of C$0.1625 per restricted voting share, payable on November 15, 2018 to KML restricted voting shareholders of record as of the close of business on October 31, 2018.

KML Dividends on its Series 1 Preferred Shares and Series 3 Preferred Shares

KML also pays dividends on its 12,000,000 Series 1 Preferred Shares and 10,000,000 Series 3 Preferred Shares, which are fixed, cumulative, preferential, and payable quarterly in the annual amount of C$1.3125 per share and C$1.3000 per share, respectively, on the 15th day of February, May, August and November, as and when declared by KML’s board of directors, for the initial fixed rate period to but excluding November 15, 2022 and February 15, 2023, respectively.

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, 2017 , in Item 7A in our 2017 Form 10-K. For more information on our risk management activities, see Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of September 30, 2018 , our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable

assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2018 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 10 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 2017 Form 10-K.

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

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

The 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 September 30, 2018.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number Description

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 September 30, 2018.

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 nine months ended September 30, 2018 and 2017; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2018 and 2017; (iii) our Consolidated Balance Sheets as of September 30, 2018 and December 31, 2017; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2018 and 2017; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2018 and 2017; and (vi) the notes to our Consolidated Financial Statements.

SIGNATURE

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



	KINDER MORGAN, INC.
		Registrant



Date:	October 19, 2018	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

TABLE OF CONTENTS

Part I. Financial Informationprint Item 1. Financial Statementsprint Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operationsprint Item 3. Quantitative and Qualitative Disclosures About Market Riskprint Item 4. Controls and Proceduresprint Part II. Other Informationprint Item 1. Legal Proceedingsprint Item 1A. Risk Factorsprint Item 2. Unregistered Sales Of Equity Securities and Use Of Proceedsprint Item 3. Defaults Upon Senior Securitiesprint Item 4. Mine Safety Disclosuresprint Item 5. Other Informationprint Item 6. Exhibitsprint

Exhibits

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 September 30, 2018. 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.

DIRECTORS	AGE	BIO
Vagt	78	Mr. Vagt has served as a director of KMI since 2012. He served as a director of EP from 2005 until we acquired it in 2012. Mr. Vagt joined the board of directors of EQT Corporation (NYSE: EQT) in July 2024. He previously served as the lead independent director of Equitrans Midstream Corp. (NYSE: ETRN) from 2018 until July 2024. Mr. Vagt also previously served as a member of the board of directors of EQT Corporation from 2017 until the separation of EQT Corporation and Equitrans Midstream Corp. in 2018. He served as Chairman of the board of directors of Rice Energy Inc. from 2014 until its acquisition by EQT Corporation in 2017. Mr. Vagt served as President of The Heinz Endowments from 2008 through 2014. Prior to that time, he served as President of Davidson College from 1997 to 2007. Mr. Vagt served as President and Chief Operating Officer of Seagull Energy Corporation from 1996 to 1997. From 1992 to 1996, he served as President, Chairman and Chief Executive Officer of Global Natural Resources. Mr. Vagt served as President and Chief Operating Officer of Adobe Resources Corporation from 1989 to 1992. Prior to 1989, he served in various positions with Adobe Resources Corporation and its predecessor entities. Mr. Vagt’s professional background in both the public and private sectors make him an important advisor and member of our Board. Mr. Vagt brings to our Board operations and management expertise in both the public and private sectors. In addition, Mr. Vagt provides our Board with a welcome diversity of perspective gained from his service as an executive officer of multiple energy companies, the president of a major charitable foundation and the president of an independent liberal arts college.
Smith	35	Mr. Smith has served as a director of KMI since 2014. He served as a director of EPB GP from 2008 to 2014. From 2003 until his retirement as an active partner in 2012, Mr. Smith was a partner in Galway Group, L.P., an investment banking/energy advisory firm headquartered in Houston, Texas. In 2002, Mr. Smith retired from EP, where he was an Executive Vice President and Chairman of El Paso Merchant Energy’s Global Gas Group. Mr. Smith had a 29-year career with Sonat Inc. prior to its merger with EP in 1999. At the time of the merger, Mr. Smith was Executive Vice President and General Counsel. He previously served as Chairman and President of Southern Natural Gas Company and as Vice Chairman of Sonat Exploration Company. Mr. Smith served as a director of Eagle Rock Energy G&P LLC from 2004 until the sale of that company in 2015. Mr. Smith previously served on the board of directors of Maritrans Inc. until 2006. With over 40 years of experience in the energy industry, Mr. Smith brings to the Board a wealth of knowledge and understanding of our industry, including valuable legal and business expertise. His experience as an executive and attorney provides the Board with an important skill set and perspective. In addition, his experience on the board of directors of other domestic and international energy companies further augments his knowledge and experience.
Shaper	56	Mr. Shaper has served as a director of KMI since 2007. He was a director of KMR and KMGP from 2003 until 2013 and a director of EPB GP from 2012 until 2013. He served in various management roles for the Kinder Morgan companies from 2000 until 2013, when he retired as President. Mr. Shaper has been a director of Service Corporation International (NYSE: SCI) since May 2022. He was appointed Chairman of the Board of Sunnova Energy International (NYSE: NOVA) in March 2025, where he has served as a director since 2019 and serves as chair of its audit committee. From 2007 until August 2021, he served as a trust manager of Weingarten Realty Investors and as the chair of its compensation committee. Mr. Shaper was a member of the board of directors of Star Peak Energy Transition Corp. (NYSE: STPK) from August 2020 until its merger with Stem, Inc. in April 2021 and Star Peak Corp II (NYSE: STPC) from January 2021 until its merger with Benson Hill in September 2021, and he served as the chair of their respective audit, compensation and nominating and governance committees. Mr. Shaper’s previous experience as our President, and as an executive officer of various Kinder Morgan entities, provides him valuable management and operational expertise and intimate knowledge of our business operations, finances and strategy.
Reichstetter	78	Mr. Reichstetter has served as a director of KMI since 2014. He served as a director of EPB GP from 2007 until 2014. He has been a private investor since 2007. Mr. Reichstetter served as Managing Director of Lazard Freres from 2002 until his retirement in 2007. From 1998 to 2002, Mr. Reichstetter was a Managing Director with Dresdner Kleinwort Wasserstein, formerly Wasserstein Parella & Co. Mr. Reichstetter was a Managing Director with Merrill Lynch from 1993 until 1996. Prior to that time, Mr. Reichstetter worked as an investment banker in various positions at The First Boston Corporation from 1974 until 1993, becoming a managing director with that company in 1982. Mr. Reichstetter brings to the Board extensive experience in investment management and capital markets, as highlighted by his years of service at Lazard Freres, Dresdner Klienwort Wasserstein, Merrill Lynch and
Macdonald	80
Hall	40	Mr. Hall has served as a director of KMI since 2012. Previously, he served as a director of EP from 2001 until the closing of our acquisition of EP in 2012. Mr. Hall has been engaged in the private practice of law since 2010. He previously served as Chief Administrative Officer of the City of Houston from 2004 to 2010 and as the City Attorney for the City of Houston from 1998 to 2004. Prior to 1998, Mr. Hall was a partner in the Houston law firm of Jackson Walker, LLP. Mr. Hall is the past Chairman of the Houston Endowment Inc. and served on its board of directors for 12 years. He is also Chairman of the Boulé Foundation. Mr. Hall’s extensive experience in both the public and private sectors, and his affiliations with many different business and philanthropic organizations, provides our Board with important insight from many perspectives. Mr. Hall’s more than 40 years of legal experience provides the Board with valuable guidance on governance issues and initiatives. As an African American, Mr. Hall also brings a diversity of experience and perspective that is welcomed by our Board.
Gardner	67	Mr. Gardner has served as a director of KMI since 2014. He served as a director of KMR and KMGP from 2011 until 2014, and he was a director of the predecessor of KMI from 1999 to 2007. Mr. Gardner has been a Managing Partner of Silverhawk Capital Partners since 2005. Mr. Gardner has served as a director of Incline Energy Partners, LP since 2015. He became chairman of the board of the general partner of CSI Compressco LP following its acquisition by Spartan Energy Partners in January 2021 and served in that role until CSI Compressco LP merged into Kodiak Gas Services in April 2024. Formerly, he served as a director of Encore Acquisition Company from 2001 to 2010, a director of Athlon Energy Inc. from 2013 to 2014, a director of Summit Materials Inc. from 2009 to May 2020, and a director of Spartan Energy Partners from 2010 until November 2021. We believe Mr. Gardner’s
Chronis	30	Ms. Chronis was elected as a director of KMI at the 2024 annual meeting of stockholders. She was a Senior Partner with Deloitte LLP until her retirement in June 2024. Ms. Chronis served as Deloitte’s Vice Chair and US Energy & Chemicals Industry Leader from January 2021 to January 2024 and as the Managing Partner of Deloitte’s Houston practice from February 2018 to January 2024. She joined Deloitte as a Partner in June 2002. Ms. Chronis has served on the board of directors of the Greater Houston Partnership since April 2018 and served as its chairman for 2021. She has served on the board of directors of Texas 2036, a nonpartisan data driven public policy think tank, since September 2019. Ms. Chronis is a CPA, status retired, licensed in the State of Texas and is NACD (National Association of Corporate Directors) certified. Ms. Chronis has over 30 years of experience as a finance and public accounting executive focusing on the energy, chemicals, technology and manufacturing industries. In addition to her financial and accounting expertise and knowledge of the energy industry, she brings to the Board notable expertise in executive leadership, strategic planning, business transformation, technology, sustainability and enterprise risk management. Ms. Chronis also provides a diverse perspective that is important to our Board.

Name and Principal Position		Year		Salary ($)		Bonus ($)		Stock Awards ($)		Non-Equity Incentive Plan Compensation ($)		Change in Pension Value ($)		All Other Comp-ensation ($)		Total ($)
Kimberly A. Dang Chief Executive Officer		2024		500,000		—		11,000,015		—		16,917		17,250		11,534,182
		2023		498,077		—		11,000,016		850,000		40,917		16,500		12,405,510
		2022		473,077		—		5,000,011		1,400,000		—		15,250		6,888,338
David P. Michels Vice President and Chief Financial Officer		2024		500,000		—		2,400,019		735,000		7,912		17,250		3,660,181
		2023		498,077		—		2,100,004		735,000		27,197		16,500		3,376,778
		2022		473,077		—		1,500,015		750,000		—		15,250		2,738,342
Sital K. Mody Vice President (President, Natural Gas Pipelines)		2024		500,000		—		2,400,019		1,050,000		15,834		17,250		3,983,103
	Dax A. Sanders Vice President (President, Products Pipelines)		2024		500,000		—		2,400,019		725,000		11,245		17,250		3,653,514
			2023		498,077		—		2,250,012		675,000		37,380		16,500		3,476,969
		2022		473,077		—		1,875,002		688,000		—		15,250		3,051,329
John W. Schlosser Vice President (President, Terminals)		2024		500,000		—		2,400,012		725,000		27,503		45,118		3,697,633

Customer name	Ticker
American Axle & Manufacturing Holdings, Inc.	AXL
EQT Corporation	EQT
Exxon Mobil Corporation	XOM
Union Pacific Corporation	UNP
Valero Energy Corporation	VLO

Owner	Position	Direct Shares	Indirect Shares
KEAN STEVEN J	-	7,101,060	265,000
MARTIN THOMAS A	-	1,016,770	277,950
MARTIN THOMAS A	-	789,652	277,950
Dang Kimberly A	-	515,756	2,026,050
Sanders Dax	-	309,069	0
GARDNER TED A	-	302,988	196,610
Sanders Dax	-	256,069	0
Schlosser John W	-	220,681	0
Michels David Patrick	-	146,468	0
Michels David Patrick	-	114,700	0
Mathews Denise R	-	79,217	1,761
Grahmann Kevin P	-	58,653	0
ASHLEY ANTHONY B	-	54,242	0
VAGT ROBERT F	-	47,579	0
ASHLEY ANTHONY B	-	41,863	0
Chronis Amy W	-	32,005	0
Mody Sital K	-	26,710	0
Mody Sital K	-	25,169	0
Schlosser John W	-	10,719	0
MORGAN MICHAEL C	-	0	22,811

KMI 10-Q Quarter ended Sept. 30, 2018

Exhibits