UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.  20549

F O R M   10-Q

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIESEXCHANGEACT OF 1934

For the quarterly period ended March 31, 2019

or

oTRANSITIONREPORT 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 April 18, 2019, the registrant had 2,263,742,572 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS

		Page Number
	Glossary	2
	Information Regarding Forward-Looking Statements	3
	PART I.  FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three Months Ended March 31, 2019 and 2018	4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, 2019 and 2018	5
	Consolidated Balance Sheets - March 31, 2019 and December 31, 2018	6
	Consolidated Statements of Cash Flows - Three Months Ended March 31, 2019 and 2018	7
	Consolidated Statements of Stockholders’ Equity - Three Months Ended March 31, 2019 and 2018	9
	Notes to Consolidated Financial Statements	10
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	39
	Results of Operations	39
	Overview	39
	Consolidated Earnings Results	40
	Non-GAAP Financial Measures	40
	Segment Earnings Results	42
	General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests	47
	Income Taxes	48
	Liquidity and Capital Resources	48
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	51
Item 4.	Controls and Procedures	52
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings	52
Item 1A.	Risk Factors	52
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	52
Item 3.	Defaults Upon Senior Securities	52
Item 4.	Mine Safety Disclosures	52
Item 5.	Other Information	52
Item 6.	Exhibits	53
	Signature	54

1

KINDER MORGAN, INC. AND SUBSIDIARIES GLOSSARY Company Abbreviations
CIG	=	Colorado Interstate Gas Company, L.L.C.	KMP	=	Kinder Morgan Energy Partners, L.P. and its
EIG	=	EIG Global Energy Partners			majority-owned and/or controlled subsidiaries
ELC	=	Elba Liquefaction Company, L.L.C.	SFPP	=	SFPP, L.P.
EPNG	=	El Paso Natural Gas Company, L.L.C.	SNG	=	Southern Natural Gas Company, L.L.C.
KMBT	=	Kinder Morgan Bulk Terminals, Inc.	TGP	=	Tennessee Gas Pipeline Company, L.L.C.
KMI	=	Kinder Morgan, Inc. and its majority-owned and/or	TMEP	=	Trans Mountain Expansion Project
		controlled subsidiaries	TMPL	=	Trans Mountain Pipeline System
KML	=	Kinder Morgan Canada Limited and its majority-owned and/or controlled subsidiaries	Trans Mountain	=	Trans Mountain Pipeline ULC
KMLT	=	Kinder Morgan Liquid Terminals, LLC
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	=	U.S. Environmental Protection Agency
Reform			FASB	=	Financial Accounting Standards Board
/d	=	per day	FERC	=	Federal Energy Regulatory Commission
BBtu	=	billion British Thermal Units	GAAP	=	U.S. 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
CO2	=	carbon dioxide or our CO2 business segment	MMBbl	=	million barrels
DCF	=	distributable cash flow	NGL	=	natural gas liquids
DD&A	=	depreciation, depletion and amortization	NYMEX	=	New York Mercantile Exchange
EBDA	=	earnings before depreciation, depletion and	OTC	=	over-the-counter
		amortization expenses, including amortization of	ROU	=	right of use
		excess cost of equity investments	U.S.	=	United States of America
			WTI	=	West Texas Intermediate
When we refer to cubic feet measurements, all measurements are at a pressure of 14.73 pounds per square inch.

2

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “position,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” 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, 2018 (2018 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.

3

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 March 31,
	2019			2018
Revenues
Services	$	2,036		$	1,967
Natural gas sales	774			827
Product sales and other	619			624
Total Revenues	3,429			3,418
Operating Costs, Expenses and Other
Costs of sales	948			1,019
Operations and maintenance	598			619
Depreciation, depletion and amortization	593			570
General and administrative	154			173
Taxes, other than income taxes	118			88
Total Operating Costs, Expenses and Other	2,411			2,469
Operating Income	1,018			949
Other Income (Expense)
Earnings from equity investments	192			220
Amortization of excess cost of equity investments	(21		)	(32		)
Interest, net	(460		)	(467		)
Other, net	10			36
Total Other Expense	(279		)	(243		)
Income Before Income Taxes	739			706
Income Tax Expense	(172		)	(164		)
Net Income	567			542
Net Income Attributable to Noncontrolling Interests	(11		)	(18		)
Net Income Attributable to Kinder Morgan, Inc.	556			524
Preferred Stock Dividends	—			(39		)
Net Income Available to Common Stockholders	$	556		$	485
Class P Shares
Basic and Diluted Earnings Per Common Share	$	0.24		$	0.22
Basic and Diluted Weighted Average Common Shares Outstanding	2,262			2,207
Dividends Per Common Share Declared for the Period	$	0.25		$	0.20

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

4

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions)

(Unaudited)

	Three Months Ended March 31,
	2019			2018
Net income	$	567		$	542
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $64 and $(11), respectively)	(215		)	34
Reclassification of change in fair value of derivatives to net income (net of tax (expense) benefit of $(4) and $5, respectively)	13			(16		)
Foreign currency translation adjustments (net of tax (expense) benefit of $(5) and $12, respectively)	10			(65		)
Benefit plan adjustments (net of tax expense of $2 and $2, respectively)	8			6
Total other comprehensive loss	(184		)	(41		)
Comprehensive income	383			501
Comprehensive (income) loss attributable to noncontrolling interests	(5		)	6
Comprehensive income attributable to Kinder Morgan, Inc.	$	378		$	507

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

5

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS (In Millions, Except Share and Per Share Amounts) (Unaudited)
	March 31, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	221		$	3,280
Restricted deposits	49			51
Accounts receivable, net	1,310			1,498
Fair value of derivative contracts	57			260
Inventories	429			385
Other current assets	196			248
Total current assets	2,262			5,722
Property, plant and equipment, net	37,782			37,897
Investments	7,770			7,481
Goodwill	21,965			21,965
Other intangibles, net	2,826			2,880
Deferred income taxes	1,647			1,566
Deferred charges and other assets	2,040			1,355
Total Assets	$	76,292		$	78,866
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,502		$	3,388
Accounts payable	1,012			1,337
Distributions payable to KML noncontrolling interests	—			876
Accrued interest	336			579
Accrued taxes	289			483
Other current liabilities	870			894
Total current liabilities	5,009			7,557
Long-term liabilities and deferred credits
Long-term debt
Outstanding	32,368			33,105
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	860			731
Total long-term debt	33,328			33,936
Other long-term liabilities and deferred credits	2,794			2,176
Total long-term liabilities and deferred credits	36,122			36,112
Total Liabilities	41,131			43,669
Commitments and contingencies (Notes 3, 10 and 11)
Redeemable Noncontrolling Interest	705			666
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,262,423,688and 2,262,165,783 shares, respectively, issued and outstanding	23			23
Additional paid-in capital	41,716			41,701
Retained deficit	(7,619		)	(7,716		)
Accumulated other comprehensive loss	(508		)	(330		)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,612			33,678
Noncontrolling interests	844			853
Total Stockholders’ Equity	34,456			34,531
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	76,292		$	78,866

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

6

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (In Millions) (Unaudited)
	Three Months Ended March 31,
	2019			2018
Cash Flows From Operating Activities
Net income	$	567		$	542
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	593			570
Deferred income taxes	(31		)	149
Amortization of excess cost of equity investments	21			32
Change in fair market value of derivative contracts	10			40
Earnings from equity investments	(192		)	(220		)
Distributions from equity investment earnings	124			127
Changes in components of working capital
Accounts receivable, net	193			126
Inventories	(52		)	(15		)
Other current assets	128			4
Accounts payable	(189		)	(140		)
Accrued interest, net of interest rate swaps	(236		)	(195		)
Accrued taxes	(202		)	(45		)
Other current liabilities	(149		)	(91		)
Other, net	50			90
Net Cash Provided by Operating Activities	635			974
Cash Flows From Investing Activities
Acquisitions of assets and investments	—			(20		)
Capital expenditures	(554		)	(707		)
Sales of assets and equity investments, net of working capital settlements	(16		)	33
Sales of property, plant and equipment, net of removal costs	14			1
Contributions to investments	(331		)	(66		)
Distributions from equity investments in excess of cumulative earnings	81			42
Loans to related party	(8		)	(8		)
Net Cash Used in Investing Activities	(814		)	(725		)
Cash Flows From Financing Activities
Issuances of debt	1,399			6,039
Payments of debt	(2,990		)	(5,684		)
Debt issue costs	(2		)	(21		)
Cash dividends - common shares	(455		)	(277		)
Cash dividends - preferred shares	—			(39		)
Repurchases of common shares	(2		)	(250		)
Contributions from investment partner	38			38
Contributions from noncontrolling interests	—			3
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	(879		)	—
Distributions to noncontrolling interests - other	(14		)	(17		)
Other, net	(3		)	(1		)
Net Cash Used in Financing Activities	(2,908		)	(209		)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	26			(3		)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(3,061		)	37
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	270		$	363

7

KINDER MORGAN, INC. AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued) (In Millions) (Unaudited)
	Three Months Ended March 31,
	2019			2018
Cash and Cash Equivalents, beginning of period	$	3,280		$	264
Restricted Deposits, beginning of period	51			62
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326
Cash and Cash Equivalents, end of period	221			294
Restricted Deposits, end of period	49			69
Cash, Cash Equivalents, and Restricted Deposits, end of period	270			363
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(3,061	)	$	37
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized (Note 10)	701			—
Increase in property, plant and equipment from both accruals and contractor retainage				44
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	690			657
Cash paid during the period for income taxes, net	345			15

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

8

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Millions)

(Unaudited)

	Common stock
	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, 2018	2,262	$	23	$	41,701		$	(7,716	)	$	(330	)	$	33,678		$	853		$	34,531
Impact of adoption of ASU 2017-12 (Note 5)							(4		)				(4		)				(4		)
Balance at January 1, 2019	2,262	23		41,701			(7,720		)	(330		)	33,674			853			34,527
Repurchase of shares				(2		)							(2		)				(2		)
Restricted shares				17									17						17
Net income							556						556			11			567
Distributions													—			(14		)	(14		)
Common stock dividends							(455		)				(455		)				(455		)
Other comprehensive loss										(178		)	(178		)	(6		)	(184		)
Balance at March 31, 2019	2,262	$	23	$	41,716		$	(7,619	)	$	(508	)	$	33,612		$	844		$	34,456

	Preferred stock			Common 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	$	—	2,217		$	22	$	41,909		$	(7,754	)	$	(541	)	$	33,636		$	1,488		$	35,124
Impact of adoption of ASUs (Note 4)											175			(109		)	66						66
Balance at January 1, 2018	2	—		2,217		22		41,909			(7,579		)	(650		)	33,702			1,488			35,190
Repurchase of shares				(13	)			(250		)							(250		)				(250		)
Restricted shares								18									18						18
Net income											524						524			18			542
Distributions																	—			(21		)	(21		)
Contributions																	—			7			7
Preferred stock dividends											(39		)				(39		)				(39		)
Common stock dividends											(277		)				(277		)				(277		)
Other comprehensive loss														(17		)	(17		)	(24		)	(41		)
Balance at March 31, 2018	2	$	—	2,204		$	22	$	41,677		$	(7,371	)	$	(667	)	$	33,661		$	1,468		$	35,129

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

9

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 157 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ 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 U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), 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 2018 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.

For a discussion of Accounting Standards Updates (ASU) we adopted on January 1, 2019, see Notes 5 and 10.

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.

10

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 March 31,
	2019			2018
Net Income Available to Common Stockholders	$	556		$	485
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3		)	(2		)
Net Income allocated to Class P stockholders	$	553		$	483
Basic Weighted Average Common Shares Outstanding	2,262			2,207
Basic Earnings Per Common Share	$	0.24		$	0.22

________

(a) As of March 31, 2019, 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 March 31,
	2019	2018
Unvested restricted stock awards	13	10
Convertible trust preferred securities	3	3
Mandatory convertible preferred stock(a)	—	58

_______

(a) The holder of each convertible preferred share participated in our earnings by receiving preferred stock dividends through the mandatory conversion date of October 26, 2018, at which time our convertible preferred shares were converted to common shares.

2. Divestiture

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed the 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 net cash consideration of C$4.43 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). Additionally, during the three months ended March 31, 2019, KML settled the remaining C$37.0 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statement of cash flows within “Sales of assets and equity investments, net of working capital settlements” for the three months ended March 31, 2019 and for which we had substantially accrued for as of December 31, 2018.

On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.

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.

11

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):

	March 31, 2019		December 31, 2018
Current portion of debt
$500 million, 364-day credit facility due November 15, 2019	$	—	$	—
$4 billion credit facility due November 16, 2023	—		—
Commercial paper notes(a)	109		433
KML $500 million credit facility, due August 31, 2022(b)(c)	38		—
Current portion of senior notes
9.00%, due February 2019	—		500
2.65%, due February 2019	—		800
3.05%, due December 2019	1,500		1,500
6.85%, due February 2020	700		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion - Other debt	44		44
Total current portion of debt	2,502		3,388
Long-term debt (excluding current portion)
Senior notes	31,649		32,380
EPC Building, LLC, promissory note, 3.967%, due 2017 through 2035	405		409
Kinder Morgan G.P. Inc., $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	204		206
Total long-term debt	32,468		33,205
Total debt(d)	$	34,970	$	36,593

_______

(a) Weighted average interest rates on borrowings outstanding as of March 31, 2019 and December 31, 2018 were 2.75% and 3.10%, respectively.

(b) Weighted average interest rate on borrowings outstanding as of March 31, 2019 was 3.42%.

(c) Borrowings under the KML 2018 Credit Facility are denominated in C$ and are converted to U.S. dollars. At March 31, 2019, the exchange rate was 0.7483 U.S. dollars per C$. See “—Credit Facilities” below.

(d) Excludes our “Debt fair value adjustments” which, as of March 31, 2019 and December 31, 2018, increased our combined debt balances by $860 million and $731 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 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. Also, see Note 13.

Credit Facilities

KMI

As of March 31, 2019, we had no borrowings outstanding under our credit facilities, $109 million outstanding under our $4 billion commercial paper program and $84 million in letters of credit. Our availability under these facilities as of March 31, 2019 was $4,307 million. As of March 31, 2019, we were in compliance with all required covenants.

KML

As of March 31, 2019, KML had C$50 million (U.S.$38 million) borrowings outstanding under its 4-year, C$500 million unsecured revolving credit facility, due August 31, 2022, with C$444 million (U.S.$331 million) available after reducing the C$500 million (U.S.$374 million) capacity for the C$6 million (U.S.$5 million) in letters of credit. Of the total C$6 million of letters of credit issued, approximately C$3 million are related to Trans Mountain for which it has issued a backstop letter of

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credit to KML. As of March 31, 2019, KML was in compliance with all required covenants. As of December 31, 2018, KML had no borrowings outstanding under its credit facility.

4.  Stockholders’ Equity

Common Equity

As of March 31, 2019, 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 2018 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 three months ended March 31, 2019, we settled repurchases of approximately 0.1 million of our Class P shares for approximately $2 million. Since December 2017, in total, we have repurchased approximately 29 million of our Class P shares under the program for approximately $525 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 March 31,
	2019		2018
Per common share cash dividend declared for the period	$	0.25	$	0.20
Per common share cash dividend paid in the period	$	0.20	$	0.125

On April 17, 2019, our board of directors declared a cash dividend of $0.25 per common share for the quarterly period ended March 31, 2019, which is payable on May 15, 2019 to common shareholders of record as of the close of business on April 30, 2019.

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 2018 Form 10-K.

On January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its Restricted Voting Shareholders as a return of capital.

On January 16, 2019, KML’s board of directors suspended KML’s dividend reinvestment plan, which was effective with the payment of the fourth quarter 2018 dividend on February 15, 2019, in light of KML’s reduced need for capital.

During the three months ended March 31, 2019, KML paid dividends to the public on its Restricted Voting Shares and on its Series 1 and Series 3 Preferred Shares of $4 million and $5 million, respectively.

Adoption of Accounting Pronouncements

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 three months ended March 31, 2018.  This ASU also required us to classify EIG

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cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheets as of March 31, 2019 and December 31, 2018, as EIG has the right to redeem their interests for cash under certain conditions.

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 three months ended March 31, 2018.

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.

On January 1, 2019, we adopted ASU 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements to Accounting for Hedging Activities.” The 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. ASU 2017-12 was applied using a modified retrospective approach for cash flow and fair value hedges existing at the date of adoption and prospectively for the presentation and disclosure guidance. The adoption of ASU 2017-12 did not have a material impact on our consolidated financial statements.

Energy Commodity Price Risk Management

As of March 31, 2019, 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 instruments
Crude oil fixed price	(20.2	)	MMBbl
Crude oil basis	(12.2	)	MMBbl
Natural gas fixed price	(55.7	)	Bcf
Natural gas basis	(35.6	)	Bcf
NGL fixed price	(0.7	)	MMBbl
Derivatives not designated as hedging instruments
Crude oil fixed price	(0.6	)	MMBbl
Crude oil basis	(6.1	)	MMBbl
Natural gas fixed price	(2.1	)	Bcf
Natural gas basis	(11.0	)	Bcf
NGL fixed price	(2.6	)	MMBbl

As of March 31, 2019, 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 2023.

Interest Rate Risk Management

 As of March 31, 2019 and December 31, 2018, we had a combined notional principal amount of $10,225 million and $10,575 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 the London Interbank Offered Rate (LIBOR) plus a spread and have termination dates that correspond to the maturity dates of the related series of senior notes. As of March 31, 2019, the principal amount of hedged senior notes consisted of $2,200 million included in “Current portion of debt” and $8,025 million included in “Long-term debt” on our accompanying consolidated balance sheets. As of March 31, 2019, the maximum length of time over

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which we have hedged a portion of our exposure to the variability in the value of debt due to interest rate risk is through March 15, 2035.

Foreign Currency Risk Management

As of both March 31, 2019 and December 31, 2018, 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 year ended December 31, 2018, we entered into foreign currency swap agreements with a combined notional principal amount of C$2,450 million (U.S.$1,888 million). These swaps resulted in our selling fixed C$ and receiving fixed U.S.$, effectively hedging the foreign currency risk associated with a substantial portion of our share of the TMPL Sale proceeds which were held in Canadian dollar denominated accounts until KML’s board and shareholder approved distribution of the proceeds was made on January 3, 2019. At such time, our share of the TMPL Sale proceeds were then transferred into a U.S. dollar denominated account, our exposure to foreign currency risk was eliminated, and our foreign currency swaps were settled. These foreign currency swaps were accounted for as net investment hedges as the foreign currency risk was related to our investment in Canadian dollar denominated foreign operations, and the critical risks of the forward contracts coincided with those of the net investment. As a result, the change in fair value of the foreign currency swaps while outstanding were reflected in the “Cumulative Translation Adjustment” section of Other Comprehensive Income.

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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
		Derivative Assets				Derivative Liabilities
		March 31, 2019		December 31, 2018		March 31, 2019			December 31, 2018
	Location	Fair value				Fair value
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	25	$	135	$	(122	)	$	(45	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	16		64		(26		)	—
Subtotal		41		199		(148		)	(45		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	22		12		(26		)	(37		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	174		121		(24		)	(78		)
Subtotal		196		133		(50		)	(115		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		91		(29		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	95		106		—			—
Subtotal		95		197		(29		)	(6		)
Total		332		529		(227		)	(166		)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	10		22		(5		)	(5		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(1		)	—
Total		10		22		(6		)	(5		)
Total derivatives		$	342	$	551	$	(233	)	$	(171	)

Effect of Derivative Contracts on the Income Statement

The following tables summarize the pre-tax impact of our derivative contracts in our accompanying consolidated statements of income and comprehensive income (in millions): 

Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended March 31,
		2019			2018
Interest rate contracts	Interest, net	$	128		$	(173	)
Hedged fixed rate debt(a)	Interest, net	$	(138	)	$	168

_______

(a) As of March 31, 2019, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $144 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.

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Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Three Months Ended March 31,							Three Months Ended March 31,
	2019			2018				2019			2018
Energy commodity derivative contracts	$	(245	)	$	(22	)	Revenues—Natural   gas sales	$	3		$	1
							Revenues—Product   sales and other	10			(19		)
							Costs of sales	1			—
Interest rate contracts(c)	—			2			Earnings from equity investments	—			(1		)
Foreign currency contracts	(34		)	65			Other, net	(31		)	40
Total	$	(279	)	$	45		Total	$	(17	)	$	21

_______

(a) We expect to reclassify an approximate $45 million loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, 2019 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices. 

(b) Amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

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

Derivatives in net investment hedging relationships	Gain/(loss) recognized in OCI on derivative					Location	Gain/(loss) reclassified from Accumulated OCI into income
	Three Months Ended March 31,						Three Months Ended March 31,
	2019			2018			2019		2018
Foreign currency contracts	$	(8	)	$	—	Loss on impairments and divestitures, net	$	—	$	—
Total	$	(8	)	$	—	Total	$	—	$	—

Derivatives not designated as hedging instruments	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended March 31,
		2019			2018
Energy commodity derivative contracts	Revenues—Natural gas sales	$	20		$	3
	Revenues—Product sales and other	(10		)	(1		)
	Costs of sales	(2		)	—
Total(a)		$	8		$	2

_______

(a) The three months ended March 31, 2019 and 2018 both include approximate gains of $8 million for each respective period, 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 March 31, 2019 and December 31, 2018, we had no outstanding letters of credit supporting our commodity price risk management program. As of March 31, 2019, we had cash margins of $4 million posted by us with our counterparties as collateral and reported within “Restricted Deposits” on our accompanying consolidated balance sheet. As of December 31, 2018, we had cash margins of $16 million posted by our counterparties with us as collateral and reported within “Other Current Liabilities” on our accompanying consolidated balance sheet. The balance at March 31, 2019 consisted of initial margin requirements of $15 million offset by variation margin requirements of $11 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.

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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 March 31, 2019, based on our current mark to market positions and posted collateral, we estimate that if our credit rating were downgraded one notch we would not be required to post additional collateral. If we were downgraded two notches, we would be required to post $73 million of additional collateral.

Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our comprehensive income but excluded from our earnings are reported as “Accumulated other comprehensive loss” within “Stockholders’ Equity” in our consolidated balance sheets. Changes in the components of our “Accumulated other comprehensive loss” not including non-controlling interests are summarized as follows (in millions):

	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
Balance as of December 31, 2018	$	164		$	(91	)	$	(403	)	$	(330	)
Other comprehensive (loss) gain before reclassifications	(215		)	16			8			(191		)
Losses reclassified from accumulated other comprehensive loss	13			—			—			13
Net current-period other comprehensive (loss) income	(202		)	16			8			(178		)
Balance as of March 31, 2019	$	(38	)	$	(75	)	$	(395	)	$	(508	)

	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 gain (loss) before reclassifications	34			(41		)	6			(1		)
Gains reclassified from accumulated other comprehensive loss	(16		)	—			—			(16		)
Impact of adoption of ASU 2018-02 (Note 4)	(4		)	(36		)	(69		)	(109		)
Net current-period other comprehensive income (loss)	14			(77		)	(63		)	(126		)
Balance as of March 31, 2018	$	(13	)	$	(266	)	$	(388	)	$	(667	)

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

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• 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 ASC (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)
As of March 31, 2019
Energy commodity derivative contracts(a)	$	6	$	45	$	—	$	51	$	(19	)	$	(11	)	$	21
Interest rate contracts	—		196		—		196		(8		)	—			188
Foreign currency contracts	—		95		—		95		(29		)	—			66
As of December 31, 2018
Energy commodity derivative contracts(a)	$	28	$	193	$	—	$	221	$	(39	)	$	(25	)	$	157
Interest rate contracts	—		133		—		133		(7		)	—			126
Foreign currency contracts	—		197		—		197		(6		)	—			191

	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)
As of March 31, 2019
Energy commodity derivative contracts(a)	$	(4	)	$	(150	)	$	—	$	(154	)	$	19	$	—	$	(135	)
Interest rate contracts	—			(50		)	—		(50		)	8		—		(42		)
Foreign currency contracts	—			(29		)	—		(29		)	29		—		—
As of December 31, 2018
Energy commodity derivative contracts(a)	$	(11	)	$	(39	)	$	—	$	(50	)	$	39	$	—	$	(11	)
Interest rate contracts	—			(115		)	—		(115		)	7		—		(108		)
Foreign currency contracts	—			(6		)	—		(6		)	6		—		—

_______

(a) Level 1 consists primarily of NYMEX natural gas futures.  Level 2 consists primarily of OTC WTI swaps 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): 

	March 31, 2019				December 31, 2018
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	35,830	$	37,981	$	37,324	$	37,469

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, 2019 and December 31, 2018.

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7.  Revenue Recognition

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 March 31, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations			Total
Revenues from contracts with customers
Services
Firm services(a)	$	930	$	80	$	250	$	—	$	(1	)	$	1,259
Fee-based services	192		235		148		16		(1		)	590
Total services revenues	1,122		315		398		16		(2		)	1,849
Sales
Natural gas sales	754		—		—		1		(2		)	753
Product sales	240		66		2		268		(6		)	570
Total sales revenues	994		66		2		269		(8		)	1,323
Total revenues from contracts with customers	2,116		381		400		285		(10		)	3,172
Other revenues(b)	85		43		109		20		—			257
Total revenues	$	2,201	$	424	$	509	$	305	$	(10	)	$	3,429

	Three Months Ended March 31, 2018
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2			Kinder Morgan Canada(c)			Corporate and Eliminations			Total
Revenues from contracts with customers
Services
Firm services(a)	$	845	$	92	$	256	$	1		$	—		$	(1	)	$	1,193
Fee-based services	164		221		144		17			64			1			611
Total services revenues	1,009		313		400		18			64			—			1,804
Sales
Natural gas sales	828		—		—		—			—			(2		)	826
Product sales	219		92		3		317			—			(7		)	624
Total sales revenues	1,047		92		3		317			—			(9		)	1,450
Total revenues from contracts with customers	2,056		405		403		335			64			(9		)	3,254
Other revenues(b)	70		37		92		(31		)	(3		)	(1		)	164
Total revenues	$	2,126	$	442	$	495	$	304		$	61		$	(10	)	$	3,418

_______

(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 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 Notes 5 and 10 for additional information related to our derivative contracts and lessor contracts, respectively.

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

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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):

	Three Months Ended March 31,
	2019			2018
Contract Assets
Balance at beginning of period(a)	$	24		$	32
Additions	24			24
Transfer to Accounts receivable	(11		)	(21		)
Other	(1		)	—
Balance at end of period(b)	$	36		$	35
Contract Liabilities
Balance at beginning of period(c)	$	292		$	206
Additions	92			110
Transfer to Revenues	(89		)	(78		)
Other	1			—
Balance at end of period(d)	$	296		$	238

_______

(a) Includes current and non-current balances of $14 million and $10 million, respectively, in 2019 and $25 million and $7 million, respectively, in 2018.

(b) Includes current and non-current balances of $26 million and $10 million, respectively, in 2019 and $28 million and $7 million, respectively, in 2018 .

(c) Includes current and non-current balances of $80 million and $212 million, respectively, in 2019 and $79 million and $127 million, respectively, in 2018.

(d) Includes current and non-current balances of $77 million and $219 million, respectively, in 2019 and $88 million and $150 million, respectively, in 2018.

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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 March 31, 2019 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):

Year	Estimated Revenue
Nine months ended December 31, 2019	$	3,796
2020	4,495
2021	3,813
2022	3,196
2023	2,673
Thereafter	15,171
Total	$	33,144

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 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

For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments.  As a result, individual segment results for the three months ended March 31, 2018 and balances as of December 31, 2018 have been reclassified to conform to the current presentation in the following tables.

Financial information by segment follows (in millions):

	Three Months Ended March 31,
	2019			2018
Revenues
Natural Gas Pipelines
Revenues from external customers	$	2,192		$	2,116
Intersegment revenues	9			10
Products Pipelines	424			442
Terminals
Revenues from external customers	508			495
Intersegment revenues	1			—
CO2	305			304
Kinder Morgan Canada(a)	—			61
Corporate and intersegment eliminations	(10		)	(10		)
Total consolidated revenues(b)	$	3,429		$	3,418

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	Three Months Ended March 31,
	2019			2018
Segment EBDA(c)
Natural Gas Pipelines	$	1,203		$	1,128
Products Pipelines	276			266
Terminals	299			296
CO2	198			199
Kinder Morgan Canada(a)	(2		)	46
Total Segment EBDA(d)	1,974			1,935
DD&A	(593		)	(570		)
Amortization of excess cost of equity investments	(21		)	(32		)
General and administrative and corporate charges	(161		)	(160		)
Interest, net	(460		)	(467		)
Income tax expense	(172		)	(164		)
Total consolidated net income	$	567		$	542

	March 31, 2019		December 31, 2018
Assets
Natural Gas Pipelines	$	50,360	$	50,261
Products Pipelines	9,538		9,598
Terminals	9,950		9,415
CO2	3,747		3,928
Corporate assets(e)	2,697		5,664
Total consolidated assets(f)	$	76,292	$	78,866

_______

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

(b) Revenues previously reported for the three months ended March 31, 2018 were $2,166 million, $399 million, $493 million and $(5) million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, and Corporate and intersegment eliminations, respectively.

(c) Includes revenues, earnings from equity investments, other, net, less operating expenses.

(d) Segment EBDA for the three months ended March 31, 2018 were $1,136 million, $259 million and $295 million for the Natural Gas Pipelines, Product Pipelines and Terminals business segments, respectively.

(e) 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.

(f) Assets previously reported as of December 31, 2018 were $51,562 million, $8,429 million and $9,283 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively.  The reclassification included a transfer of $450 million of goodwill from the Natural Gas Pipelines Non-Regulated reporting unit to the Product Pipelines reporting unit.

9.  Income Taxes

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

	Three Months Ended March 31,
	2019			2018
Income tax expense	$	172		$	164
Effective tax rate	23.3		%	23.2		%

The effective tax rate for the three months ended March 31, 2019 and 2018 is higher than the statutory federal rate of 21% primarily due to state and foreign income taxes partially offset by dividend-received deductions from our investments in Florida Gas Pipeline, NGPL Holdings LLC and Plantation Pipe Line Company.

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10.  Leases

Effective January 1, 2019, we adopted ASU No. 2016-02, “Leases (Topic 842)” and the series of related Accounting Standards Updates that followed (collectively referred to as “Topic 842”). The most significant changes under the new guidance include clarification of the definition of a lease, and the requirements for lessees to recognize a ROU asset and a lease liability for all qualifying leases with terms longer than twelve months in the consolidated balance sheet. In addition, under Topic 842, additional disclosures are required to meet the objective of enabling users of financial statements to assess the amount, timing and uncertainty of cash flows arising from leases.

We elected the practical expedient available to us under ASU 2018-11 “Leases: Targeted Improvements” which allows us to apply the transition provision for Topic 842 at our adoption date instead of at the earliest comparative period presented in our financial statements. Therefore, we recognized and measured leases existing at January 1, 2019 but without retrospective application. In addition, we elected the optional practical expedient permitted under the transition guidance related to land easements which allows us to carry forward our historical accounting treatment for land easements on existing agreements upon adoption. We also elected all other available practical expedients except the hindsight practical expedient.

The impact of Topic 842 on our consolidated balance sheet beginning January 1, 2019 was through the recognition of ROU assets and lease liabilities for operating leases, while our accounting for finance leases remained substantially unchanged. Our finance leases were immaterial prior to the adoption of Topic 842, and no change was made to the classification for these leases. Amounts recognized at January 1, 2019 for operating leases were as follows (in millions):

	January 1, 2019
ROU assets	$	696
Short-term lease liability	52
Long-term lease liability	644

No impact was recorded to the income statement or beginning retained earnings for Topic 842.

Lessee

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment and land. Our leases have remaining lease terms of one to 34 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.

Beginning January 1, 2019, operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Operating leases in effect prior to January 1, 2019 were recognized at the present value of the remaining payments on the remaining lease term as of January 1, 2019. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, were reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately, while for the remainder of our agreements we have elected the practical expedient to account for lease and non-lease components as a single lease component. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842, such as land easements, would be reassessed in the event of any modifications to those agreements.

Following are components of our lease cost (in millions):

	Three Months Ended March 31, 2019
Operating leases	$	26
Short-term and variable leases	33
Total lease cost(a)	$	59

_______

(a) Includes $14 million of capitalized lease costs.

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Other information related to our operating leases are as follows (in millions, except lease term and discount rate):

	Three Months Ended March 31, 2019
Operating cash flows from operating leases	$	(45	)
Investing cash flows from operating leases	(14		)
ROU assets obtained in exchange for operating lease obligations, net of retirements	19
Amortization of ROU assets	14
Weighted average remaining lease term	16.84 years
Weighted average discount rate	5.93		%

Amounts recognized in the accompanying consolidated balance sheet are as follows (in millions):

Lease Activity	Balance sheet location	March 31, 2019
ROU assets	Deferred charges and other assets	$	701
Short-term lease liability	Other current liabilities	53
Long-term lease liability	Other long-term liabilities and deferred credits	648
Finance lease assets	Property, plant and equipment, net	3
Finance lease liabilities	Long-term debt—Outstanding	2

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of March 31, 2019 are as follows (in millions):

Nine months ended December 31, 2019	$	71
2020	80
2021	73
2022	67
2023	61
Thereafter	794
Total lease payments(a)	1,146
Less: Interest	(445		)
Present value of lease liabilities	$	701

_______

(a) Amount excludes future minimum rights-of-way obligations (ROW) as they do not constitute a lease obligation. The amounts in our future minimum ROW obligations as presented in the table below have not materially changed since December 31, 2018.

Undiscounted future gross minimum operating lease payments and ROW obligations as of December 31, 2018 are as follows (in millions):

	Leases		ROW		Total(a)
2019	$	90	$	25	$	115
2020	75		25		100
2021	70		25		95
2022	65		26		91
2023	59		25		84
Thereafter	771		88		859
Total payments	$	1,130	$	214	$	1,344

_______

(a) This table has been revised from the previously reported December 31, 2018 future gross minimum rental commitments under our operating leases and ROW obligations table to (i) separately present lease and ROW obligations and (ii) to correct amounts previously reported to include an additional $482 million of undiscounted future lease payments, primarily in the “Thereafter” amount associated with the 2018 extension of the Edmonton South tank lease through December 2038.

Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

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Lessor

The property we lease to others under operating leases consists primarily of specific facilities where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of the asset. These primarily consist of specific tanks, treating and gas equipment and pipelines with separate control locations. Our leases have remaining lease terms of one to 32 years, some of which have options to extend the lease for up to 25 years, and some which may include options to terminate the lease within one year. We determine if an arrangement is a lease at inception. None of our leases allow the lessee to purchase the leased asset.

Lease income for the three months ended March 31, 2019 totaled $218 million, including a significant amount of variable lease payments that is excluded from the following disclosure as the amounts cannot be reasonably estimated for future periods.

Future minimum operating lease revenues based on contractual agreements are as follows (in millions):

	March 31, 2019
2019 (nine months ended December 31, 2019)	$	297
2020	338
2021	320
2022	308
2023	275
Thereafter	3,471
Total	$	5,009

Options for a lessee to renew the contract are not included as part of future minimum operating lease revenues. We elected the practical expedient available to us to not separate lease and non-lease components under these agreements. Any modification of a lease will result in a reevaluation of the lease classification.

11.  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

In July 2018, the FERC issued an order requiring an informational filing by interstate natural gas pipelines on a new Form 501-G, evaluating the impact of the 2017 Tax Reform and the Revised Tax Policy on tax allowances for the pipelines. In the fourth quarter of 2018, KMI filed Form 501-G for 19 of its FERC-regulated assets. The FERC granted SNG a waiver from filing the 501-G based on its previously filed negotiated settlement and TGP was granted an extension from filing based on ongoing negotiations with customers. On April 8, 2019, KMI announced that TGP and EPNG agreed to settlements with their shippers to address FERC’s 501-G process. KMI successfully worked with its shippers without the need for litigation or any additional intervention by the FERC. Rate adjustments have been set forth in the agreements with TGP and EPNG shippers. FERC has approved a settlement that Young Gas Storage reached with its customers and has terminated all but three of the remaining 501-G proceedings without taking further action. FERC initiated a rate investigation of Bear Creek Storage Company. Bear Creek Storage Company filed a cost and revenue study in compliance with the FERC investigation on April 1, 2019. Two other KMI 501-G filings remain pending but relate to systems under rate moratoria. KMI expects the vast majority of KMI's 501-G exposure to be resolved upon FERC’s approval of the EPNG and TGP settlements discussed above.

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FERC Inquiry Regarding the Commission’s Policy for Determining Return on Equity

On March 21, 2019, the FERC issued a notice of inquiry (NOI) seeking comments regarding whether the FERC should revise its policies for determining the base return on equity (ROE) used in setting cost of service rates charged by jurisdictional public utilities and interstate natural gas and liquids pipelines. The NOI seeks comment on whether any aspects of the existing methodologies used by the FERC to set an ROE for a regulated entity should be changed, whether the ROE methodology should be the same across all three industries, and whether alternative methodologies should be considered. Initial comments are due in June 2019. ROE is an important component of a regulated entity’s cost of service calculation, including for our interstate natural gas and liquids pipeline assets. We expect broad industry, pipeline company, and shipper participation in the comment process.

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 2019 (docketed at OR19-21) challenging SFPP’s 2018 index rate increases on certain of its lines. 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. On March 22, 2016, the D.C. Circuit issued a decision in United Airlines, Inc. v. FERC remanding to the 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 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 dockets, and restart the 2011 SFPP complaint proceeding which had been abated. SFPP made its compliance filings and expects to pay in 2019 refunds in the 2008 docket. On March 15, 2019, SFPP filed with the D.C. Circuit a petition for review of the FERC’s decision in the 2008 docket, including the denial of an income tax allowance. SFPP’s request for rehearing in the 2009 docket remains pending at the FERC. SFPP is awaiting a FERC decision in a 2015 complaint against its East Line rates. The FERC has not yet acted on the shippers’ revised complaints in the 2011 SFPP complaint proceeding. 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. SFPP along with another pipeline entity appealed the Revised Policy Statement along with the Order on Rehearing to the D.C. Circuit, and the Court has ordered briefing on the merits. 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 $330 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, as well as the compliance filing methodology recently approved by the FERC 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 in 2015. EPNG sought federal appellate review of Opinion 517-A. On February 21, 2017, the reviewing court delayed the case until the FERC ruled 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. On May 3, 2018, the FERC issued Opinion 528-B upholding its decisions in Opinion 528-A 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,

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EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, all briefing will be completed by April 29, 2019.

Other Commercial Matters

Gulf LNG Facility Arbitration

On March 1, 2016, Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) received 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.  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 called 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 second quarter of 2018 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 February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019. 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. On December 12, 2018, Eni S.p.A. filed a counterclaim seeking unspecified damages from GLNG. GLNG intends to vigorously prosecute and defend the lawsuit.

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. All of the cases have been settled or dismissed, including a Wisconsin class action lawsuit pending in a U.S. District Court in Nevada, in which approximately $300 million in damages plus interest was alleged against all defendants and in which a settlement in principal has been reached that will require class notice and final court approval in 2019. The amount to be paid in settlement of this matter is not material to our results of operations, cash flows or dividends to shareholders.

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 March 31, 2019 and December 31, 2018, our total reserve for legal matters was $222 million and $207 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to federal, state and local laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal and CO₂ field and oil field operations, and there can be no assurance that we will not incur significant costs and

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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 remediation.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, NGL, natural gas and CO₂.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site. The cost for the final remedy is estimated by the EPA to be approximately $1.1 billion and active cleanup is expected to take as long as 13 years to complete. KMLT, KMBT, and 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of two facilities). 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.

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 PRP 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. After a trial which concluded in March 2019, the U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the government. The decision may be appealed by any party to the Court of Appeals for the Ninth Circuit. The decision does not provide or establish the scope of a remedial plan with respect to the sites, nor does it establish the total cost for addressing the sites, all of which remain to be determined in subsequent proceedings and adversarial actions, if necessary, with the EPA. Until such issues are determined, we are unable to reasonably estimate the extent of our potential liability. However, because costs associated with any remedial plan approved by the EPA are expected to be spread over at least several years, we do not anticipate that this decision will have a material adverse impact to our results of operations, cash flows, or dividends to KMI shareholders.

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Lower Passaic River Study Area of the Diamond Alkali Superfund Site, 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 (Site) concerning the lower 17-mile stretch of the Passaic River. It has been alleged that EPEC Polymers and EPEC Oil Trust may be 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) with the EPA 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 is directing and funding the AOC work required by the EPA. Under the first AOC, the CPG submitted draft remedial investigation and feasibility studies (RI/FS) of the Site to the EPA in 2015, and EPA approval remains pending. Under the second AOC, the CPG conducted a CERCLA removal action at the Passaic River Mile 10.9, and is obligated to conduct EPA-directed post-remedy monitoring in the removal area. We have established a reserve for the anticipated cost of compliance with these two AOCs.

On March 4, 2016, the EPA issued its Record of Decision (ROD) for the lower eight miles of the Site. The final cleanup plan in the ROD is estimated by the EPA to cost $1.7 billion. 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 Site. 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 Site. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the ROD. There is also uncertainty as to the impact of the recent EPA FS directive for the upper nine miles of the Site not subject to the lower eight mile 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 and allocations are determined, the scope of potential EPA claims for the Site and liability therefor are not reasonably estimable.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA). The Plaintiffs allege the defendants’ operations caused substantial damage to the coastal waters of Louisiana and nearby lands, including marsh (Coastal Zone). The alleged damages include erosion of property within the Coastal Zone, and discharge of pollutants that are alleged to have adversely impacted the Coastal Zone, including plants and wildlife. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected Coastal Zone to its original condition. The Louisiana Department of Natural Resources (LDNR) and the Louisiana Attorney General (LAG) routinely intervene in these cases, and we expect the LDNR and LAG to intervene in any additional cases that may be filed. There are more than 40 of these cases pending in Louisiana against oil and gas companies, one of which is against TGP and one of which is against SNG, both described further below.

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’ operations in Plaquemines Parish violated SLCRMA and Louisiana law, and that those operations caused substantial damage to the Coastal Zone. 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 remediate, restore, vegetate and detoxify the affected Coastal Zone property. In 2016, the LAG and LDNR intervened in the lawsuit. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. That motion is pending. The case is effectively stayed pending resolution of the removal and remand issues. We will continue to vigorously defend this case.

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On March 29, 2019, the City of New Orleans and Orleans Parish (Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the Coastal Zone. Orleans 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 remediate, restore, vegetate and detoxify the affected Coastal Zone property. On April 5, 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. We will vigorously defend this case.

Louisiana Landowner Coastal Erosion Litigation

Beginning in January 2015, several private landowners in Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including two cases against TGP, two cases against SNG, and two cases against both TGP and SNG. In these cases, the Plaintiffs allege that defendants failed to properly maintain pipeline canals and canal banks on their property, which caused the canals to erode and widen and resulted in substantial land loss, including significant damage to the ecology and hydrology of the affected property, including damage to timber and wildlife. Plaintiffs allege that defendants’ conduct constitutes a breach of the subject right of way agreements, is inconsistent with prudent operating practices, violates Louisiana law, and that defendants’ failure to maintain canals and canal banks constitutes negligence and trespass. Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to return the canals and canal banks to their as-built conditions and restore and remediate the affected property. Plaintiffs allege that defendants are obligated to restore and remediate the affected property without regard to the value of the property. Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. There are no trial dates established in any of the pending cases. In one case filed by Vintage Assets, Inc. and several landowners against SNG and TGP that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana, $80 million was sought 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. 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, a third-party defendant 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 on April 17, 2019 the case was remanded to the State District Court of Plaquemines Parish, Louisiana for further proceedings. We will continue to vigorously defend these cases.

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 March 31, 2019 and December 31, 2018, we have accrued a total reserve for environmental liabilities in the amount of $270 million and $271 million, respectively. In addition, as of both March 31, 2019 and December 31, 2018, we have recorded a receivable of $13 million for expected cost recoveries that have been deemed probable.

Other Contingencies

We have agreed to fund our proportionate share of $700 million of 2019 maturing debt obligations at certain of our equity investees and we would be obligated for our $350 million share of these obligations if the equity investees are unable to satisfy their obligations.

12. Recent Accounting Pronouncements

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 for most financial assets and certain other instruments. For trade and other receivables, held-to-maturity debt securities, loans and other instruments, entities will be required to utilize a new forward-looking “expected loss” methodology that generally will result in the earlier recognition of

31

allowance for 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. 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.

13. 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 March 31, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $14,836 million, $16,610 million, and $2,535 million, respectively, of Guaranteed Notes outstanding.  Included in the Subsidiary Guarantors debt balance as presented in the accompanying March 31, 2019 condensed consolidating balance sheet is approximately $158 million of other financing obligations that are not subject to the cross guarantee agreement.

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Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended March 31, 2019 (In Millions) (Unaudited)
	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	3,150		$	325		$	(46	)	$	3,429
Operating Costs, Expenses and Other
Costs of sales	—			—			918			65			(35		)	948
Depreciation, depletion and amortization	5			—			520			68			—			593
Other operating (income) expense	(1		)	—			740			142			(11		)	870
Total Operating Costs, Expenses and Other	4			—			2,178			275			(46		)	2,411
Operating (Loss) Income	(4		)	—			972			50			—			1,018
Other Income (Expense)
Earnings from consolidated subsidiaries	893			847			49			18			(1,807		)	—
Earnings from equity investments	—			—			192			—			—			192
Interest, net	(190		)	(3		)	(258		)	(9		)	—			(460		)
Amortization of excess cost of equity investments and other, net	(4		)	—			(7		)	—			—			(11		)
Income Before Income Taxes	695			844			948			59			(1,807		)	739
Income Tax Expense	(139		)	(1		)	(21		)	(11		)	—			(172		)
Net Income	556			843			927			48			(1,807		)	567
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(11		)	(11		)
Net Income Attributable to Controlling Interests	$	556		$	843		$	927		$	48		$	(1,818	)	$	556
Net Income	$	556		$	843		$	927		$	48		$	(1,807	)	$	567
Total other comprehensive (loss) income	(178		)	(227		)	(232		)	19			434			(184		)
Comprehensive income	378			616			695			67			(1,373		)	383
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(5		)	(5		)
Comprehensive income attributable to controlling interests	$	378		$	616		$	695		$	67		$	(1,378	)	$	378

33

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended March 31, 2018 (In Millions) (Unaudited)
	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	3,080		$	386		$	(48	)	$	3,418
Operating Costs, Expenses and Other
Costs of sales	—			—			979			77			(37		)	1,019
Depreciation, depletion and amortization	5			—			484			81			—			570
Other operating expenses	(25		)	1			743			172			(11		)	880
Total Operating Costs, Expenses and Other	(20		)	1			2,206			330			(48		)	2,469
Operating Income (Loss)	20			(1		)	874			56			—			949
Other Income (Expense)
Earnings from consolidated subsidiaries	806			745			51			16			(1,618		)	—
Earnings from equity investments	—			—			220			—			—			220
Interest, net	(184		)	(4		)	(273		)	(6		)	—			(467		)
Amortization of excess cost of equity investments and other, net	6			—			(10		)	8			—			4
Income Before Income Taxes	648			740			862			74			(1,618		)	706
Income Tax Expense	(124		)	(2		)	(26		)	(12		)	—			(164		)
Net Income	524			738			836			62			(1,618		)	542
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(18		)	(18		)
Net Income Attributable to Controlling Interests	524			738			836			62			(1,636		)	524
Preferred Stock Dividends	(39		)	—			—			—			—			(39		)
Net Income Available to Common Stockholders	$	485		$	738		$	836		$	62		$	(1,636	)	$	485
Net Income	$	524		$	738		$	836		$	62		$	(1,618	)	$	542
Total other comprehensive loss	(17		)	(56		)	(57		)	(78		)	167			(41		)
Comprehensive income (loss)	507			682			779			(16		)	(1,451		)	501
Comprehensive loss attributable to noncontrolling interests	—			—			—			—			6			6
Comprehensive income (loss) attributable to controlling interests	$	507		$	682		$	779		$	(16	)	$	(1,445	)	$	507

34

Condensed Consolidating Balance Sheets as of March 31, 2019 (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	$	2	$	—	$	—	$	219	$	—		$	221
Other current assets - affiliates	5,647		3,314		27,163		1,396		(37,520		)	—
All other current assets	73		22		1,765		193		(12		)	2,041
Property, plant and equipment, net	246		—		30,607		6,929		—			37,782
Investments	664		—		7,007		99		—			7,770
Investments in subsidiaries	42,572		40,683		4,297		4,337		(91,889		)	—
Goodwill	13,789		22		5,166		2,988		—			21,965
Notes receivable from affiliates	935		20,341		192		1,117		(22,585		)	—
Deferred income taxes	3,049		—		—		—		(1,402		)	1,647
Other non-current assets	656		148		3,973		462		(373		)	4,866
Total assets	$	67,633	$	64,530	$	80,170	$	17,740	$	(153,781	)	$	76,292
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,609	$	700	$	31	$	162	$	—		$	2,502
Other current liabilities - affiliates	16,195		14,209		5,775		1,341		(37,520		)	—
All other current liabilities	358		129		1,591		443		(14		)	2,507
Long-term debt	13,500		16,163		3,013		652		—			33,328
Notes payable to affiliates	1,246		448		20,536		355		(22,585		)	—
Deferred income taxes	—		—		522		880		(1,402		)	—
All other long-term liabilities and deferred credits	1,113		40		1,208		804		(371		)	2,794
Total liabilities	34,021		31,689		32,676		4,637		(61,892		)	41,131
Redeemable noncontrolling interest	—		—		705		—		—			705
Stockholders’ equity
Total KMI equity	33,612		32,841		46,789		13,103		(92,733		)	33,612
Noncontrolling interests	—		—		—		—		844			844
Total stockholders’ equity	33,612		32,841		46,789		13,103		(91,889		)	34,456
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	67,633	$	64,530	$	80,170	$	17,740	$	(153,781	)	$	76,292

35

Condensed Consolidating Balance Sheets as of December 31, 2018 (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	$	8	$	—	$	—	$	3,277	$	(5	)	$	3,280
Other current assets - affiliates	4,465		4,788		23,851		1,031		(34,135		)	—
All other current assets	171		17		2,056		212		(14		)	2,442
Property, plant and equipment, net	231		—		30,750		6,916		—			37,897
Investments	664		—		6,718		99		—			7,481
Investments in subsidiaries	42,096		40,049		6,077		4,324		(92,546		)	—
Goodwill	13,789		22		5,166		2,988		—			21,965
Notes receivable from affiliates	945		20,345		247		1,043		(22,580		)	—
Deferred income taxes	3,137		—		—		—		(1,571		)	1,566
Other non-current assets	233		105		3,823		74		—			4,235
Total assets	$	65,739	$	65,326	$	78,688	$	19,964	$	(150,851	)	$	78,866
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,933	$	1,300	$	30	$	125	$	—		$	3,388
Other current liabilities - affiliates	14,189		14,087		4,898		961		(34,135		)	—
All other current liabilities	486		354		1,838		1,510		(19		)	4,169
Long-term debt	13,474		16,799		3,020		643		—			33,936
Notes payable to affiliates	1,234		448		20,543		355		(22,580		)	—
Deferred income taxes	—		—		503		1,068		(1,571		)	—
Other long-term liabilities and deferred credits	745		59		944		428		—			2,176
Total liabilities	32,061		33,047		31,776		5,090		(58,305		)	43,669
Redeemable noncontrolling interest	—		—		666		—		—			666
Stockholders’ equity
Total KMI equity	33,678		32,279		46,246		14,874		(93,399		)	33,678
Noncontrolling interests	—		—		—		—		853			853
Total stockholders’ equity	33,678		32,279		46,246		14,874		(92,546		)	34,531
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	65,739	$	65,326	$	78,688	$	19,964	$	(150,851	)	$	78,866

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Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 2019 (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	$	(663	)	$	737		$	4,724		$	(98	)	$	(4,065	)	$	635
Cash flows from investing activities
Capital expenditures	(21		)	—			(423		)	(110		)	—			(554		)
Sales of assets and equity investments, net of working capital settlements	—			—			12			(28		)	—			(16		)
Sales of property, plant and equipment, net of removal costs	3			—			14			(3		)	—			14
Contributions to investments	(28		)	—			(302		)	(1		)	—			(331		)
Distributions from equity investments in excess of cumulative earnings	294			—			81			—			(294		)	81
Funding to affiliates	(2,660		)	(7		)	(3,831		)	(244		)	6,742			—
Loans to related party	—			—			(8		)	—			—			(8		)
Net cash used in investing activities	(2,412		)	(7		)	(4,457		)	(386		)	6,448			(814		)
Cash flows from financing activities
Issuances of debt	1,342			—			—			57			—			1,399
Payments of debt	(1,666		)	(1,300		)	(2		)	(22		)	—			(2,990		)
Debt issue costs	(2		)	—			—			—			—			(2		)
Cash dividends - common shares	(455		)	—			—			—			—			(455		)
Repurchases of common shares	(2		)	—			—			—			—			(2		)
Funding from affiliates	3,855			1,705			1,010			172			(6,742		)	—
Contributions from investment partner	—			—			38			—			—			38
Distributions to parents	—			(1,132		)	(1,313		)	(2,812		)	5,257			—
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	—			—			—			—			(879		)	(879		)
Distributions to noncontrolling interests - other	—			—			—			—			(14		)	(14		)
Other, net	(3		)	—			—			—			—			(3		)
Net cash provided by (used in) financing activities	3,069			(727		)	(267		)	(2,605		)	(2,378		)	(2,908		)
Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			26			—			26
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(6		)	3			—			(3,063		)	5			(3,061		)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	8			—			—			3,328			(5		)	3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	2		$	3		$	—		$	265		$	—		$	270

37

Condensed Consolidating Statements of Cash Flows for the Three Months Ended March 31, 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	$	(302	)	$	838		$	2,356		$	263		$	(2,181	)	$	974
Cash flows from investing activities
Acquisitions of assets and investments	—			—			(20		)	—			—			(20		)
Capital expenditures	(19		)	—			(451		)	(237		)	—			(707		)
Proceeds from sales of equity investments	—			—			33			—			—			33
Sales of property, plant and equipment, net of removal costs	2			—			—			(1		)	—			1
Contributions to investments	—			—			(64		)	(2		)	—			(66		)
Distributions from equity investments in excess of cumulative earnings	559			—			42			—			(559		)	42
Funding (to) from affiliates	(3,074		)	34			(1,388		)	(248		)	4,676			—
Loans to related party	—			—			(8		)	—			—			(8		)
Net cash (used in) provided by investing activities	(2,532		)	34			(1,856		)	(488		)	4,117			(725		)
Cash flows from financing activities
Issuances of debt	5,961			—			—			78			—			6,039
Payments of debt	(3,929		)	(975		)	(777		)	(3		)	—			(5,684		)
Debt issue costs	(17		)	—			—			(4		)	—			(21		)
Cash dividends - common shares	(277		)	—			—			—			—			(277		)
Cash dividends - preferred shares	(39		)	—			—			—			—			(39		)
Repurchases of common shares	(250		)	—			—			—			—			(250		)
Funding from affiliates	1,444			1,402			1,639			191			(4,676		)	—
Contribution from investment partner	—			—			38			—			—			38
Contributions from parents	—			—			3			—			(3		)	—
Contributions from noncontrolling interests	—			—			—			—			3			3
Distributions to parents	—			(1,289		)	(1,403		)	(62		)	2,754			—
Distributions to noncontrolling interests	—			—			—			—			(17		)	(17		)
Other, net	(1		)	—			—			—			—			(1		)
Net cash provided by (used in) financing activities	2,892			(862		)	(500		)	200			(1,939		)	(209		)
Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			(3		)	—			(3		)
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	58			10			—			(28		)	(3		)	37
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3			1			—			323			(1		)	326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	61		$	11		$	—		$	295		$	(4	)	$	363

38

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 2018 Form 10-K.

Sale of Trans Mountain Pipeline System and Its Expansion Project

On August 31, 2018, KML completed the 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 net cash consideration of C$4.4 billion (U.S.$3.4 billion), net of working capital adjustments (TMPL Sale). During the three months ended March 31, 2019, KML settled the remaining C$37.0 million (U.S.$28 million) of working capital adjustments, which amount is included in the accompanying consolidated statement of cash flows within “Sales of assets and equity investments, net of working capital settlements” for the three months ended March 31, 2019 and for which we had substantially accrued for as of December 31, 2018.

On January 3, 2019, KML distributed the net proceeds from the TMPL Sale to its shareholders as a return of capital. Public owners of KML’s restricted voting shares, reflected as noncontrolling interests by us, received approximately $0.9 billion (C$1.2 billion), and most of our approximate 70% portion of the net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used to repay our outstanding commercial paper borrowings of $0.4 billion, and in February 2019, to pay down approximately $1.3 billion of maturing long-term debt.

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 unallocated 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 dispositions and acquisitions separately from those that are attributable to businesses owned in both periods.

For segment reporting purposes, effective January 1, 2019, certain assets were transferred among our business segments. As a result, individual segment results for the three months ended March 31, 2018 have been reclassified to conform to the current presentation in the following Management Discussion and Analysis tables, which includes increased (decreased) Segment EBDA for the following business segments: Natural Gas Pipelines $(8) million; Products Pipelines $7 million; and Terminals $1 million.

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Consolidated Earnings Results

	Three Months Ended March 31,
	2019			2018			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,203		$	1,128		$	75		7	%
Products Pipelines	276			266			10			4	%
Terminals	299			296			3			1	%
CO2	198			199			(1		)	(1	)%
Kinder Morgan Canada(b)	(2		)	46			(48		)	(104	)%
Total Segment EBDA(c)	1,974			1,935			39			2	%
DD&A	(593		)	(570		)	(23		)	(4	)%
Amortization of excess cost of equity investments	(21		)	(32		)	11			34	%
General and administrative and corporate charges(d)	(161		)	(160		)	(1		)	(1	)%
Interest, net(e)	(460		)	(467		)	7			1	%
Income before income taxes	739			706			33			5	%
Income tax expense(f)	(172		)	(164		)	(8		)	(5	)%
Net income	567			542			25			5	%
Net income attributable to noncontrolling interests	(11		)	(18		)	7			39	%
Net income attributable to Kinder Morgan, Inc.	556			524			32			6	%
Preferred stock dividends	—			(39		)	39			100	%
Net Income Available to Common Stockholders	$	556		$	485		$	71		15	%

_______

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

(b) As a result of the TMPL Sale on August 31, 2018, this segment does not have results of operations on a prospective basis.

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

(c) 2019 and 2018 amounts include net decreases in earnings of $8 million and $16 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) 2019 and 2018 amounts include a net increase in expense of $3 million and a net decrease in expense of $4 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) 2019 and 2018 amounts include a net increase in expense of $2 million and a net decrease in expense of $5 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.”

(f) 2019 and 2018 amounts include a net increase in expense of $2 million and a net decrease in expense of $3 million, respectively, related to the combined net effect of the certain items related to income tax expense representing the income tax provision on certain items plus discrete income tax items.

The certain item totals reflected in footnotes (c) through (e) to the table above accounted for a $6 million decrease in income before income taxes for the first quarter of 2019, as compared to the same prior year period (representing the difference between decreases of $13 million and $7 million in income before income taxes for the first quarter of 2019 and 2018, respectively). After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining increase of $39 million (5%) from the prior year quarter in income before income taxes is primarily attributable to increased performance from our Natural Gas Pipelines business segment and decreased interest expense, net and decreased general and administrative expense partially offset by lower earnings from our CO₂ business segment, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A.

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).

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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 common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in dividends.

Reconciliation of Net Income Available to Common Stockholders to DCF

	Three Months Ended March 31,
	2019			2018
	(In millions, except per share amounts)
Net Income Available to Common Stockholders	$	556		$	485
Add/(Subtract):
Certain items before book tax(a)	13			51
Book tax certain items(b)	2			(3		)
Impact of 2017 Tax Reform(c)	—			(44		)
Total certain items	15			4
Net Income Available to Common Stockholders before certain items	571			489
Add/(Subtract):
DD&A expense(d)	708			690
Total book taxes(e)	195			184
Cash taxes(f)	(13		)	(13		)
Other items(g)	25			11
Sustaining capital expenditures(h)	(115		)	(114		)
DCF	$	1,371		$	1,247
Weighted average common shares outstanding for dividends(i)	2,275			2,218
DCF per common share	$	0.60		$	0.56
Declared dividend per common share	$	0.25		$	0.20

_______

(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 income tax provision on certain items plus discrete income tax items.

(c) 2018 amount represents 2017 Tax Reform provisional adjustments including our share of certain equity investees’ 2017 Tax Reform provisional adjustments related to our FERC-regulated business.

(d) Includes DD&A and amortization of excess cost of equity investments. 2019 and 2018 amounts also include $94 million and $88 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.

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(e) Excludes book tax certain items of $(2) million and $3 million for 2019 and 2018, respectively. 2019 and 2018 amounts also include $25 million and $17 million, respectively, of our share of taxable equity investees’ book taxes, net of the noncontrolling interests’ portion of KML book taxes.

(f) 2018 amount includes $(10) million of our share of taxable equity investees’ cash taxes.

(g) Includes non-cash pension expense and non-cash compensation associated with our restricted stock program.

(h) 2019 and 2018 amounts include $(19) million and $(16) million, respectively, of our share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.

(i) 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 but is not a performance measure.

Segment Earnings Results

Natural Gas Pipelines

	Three Months Ended March 31,
	2019			2018
	(In millions, except operating statistics)
Revenues(a)	$	2,201		$	2,126
Operating expenses(b)	(1,167		)	(1,201		)
Other income	1			—
Earnings from equity investments(b)	159			187
Other, net	9			16
Segment EBDA(b)	1,203			1,128
Certain items(b)	(2)			(54		)
Segment EBDA before certain items	$	1,201		$	1,074
Change from prior period	Increase/(Decrease)
Revenues before certain items	$	89		4		%
Segment EBDA before certain items	$	127		12		%
Natural gas transport volumes (BBtu/d)(c)	36,674			32,124
Natural gas sales volumes (BBtu/d)(c)	2,332			2,491
Natural gas gathering volumes (BBtu/d)(c)	3,301			2,731
NGLs (MBbl/d)(c)	121			116

_______

Certain items affecting Segment EBDA

(a) 2019 and 2018 amounts include a decrease in revenue of $8 million and an increase in revenue of $6 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales.

(b) In addition to the revenue certain items described in footnote (a) above: 2019 amount also includes an increase in earnings of $11 million for our share of certain equity investees’ amortization of the impact of the 2017 Tax Reform and a $1 million decrease in earnings from other certain items. 2018 amount also includes (i) an increase in earnings of $44 million for our share of certain equity investees’ 2017 Tax Reform provisional adjustments; (ii) an increase in earnings of $6 million related to the release of certain sales and use tax reserves; and (iii) a $2 million decrease in earnings from other certain items.

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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 month periods ended March 31,2019 and 2018:

Three Months Ended March 31, 2019 versus Three Months Ended March 31, 2018

	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
North Region	$	57		18	%	$	42		10	%
West Region	36			14	%	32			10	%
Midstream	34			10	%	15			1	%
South Region	(2		)	(1	)%	4			5	%
Other	2			100	%	2			100	%
Intrasegment eliminations	—			—	%	(6		)	(60	)%
Total Natural Gas Pipelines	$	127		12	%	$	89		4	%

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 month periods ended March 31, 2019 and 2018:

• North Region’s increase of $57 million (18%) was primarily due to an increase in earnings from TGP and Kinder Morgan Louisiana Pipeline LLC (KMLP). TGP contributed increased earnings primarily from expansion projects placed into service in 2018 and higher firm transportation revenues due to higher capacity sales. KMLP increased earnings was from the Sabine Pass expansion which was placed into service in December 2018;

• West Region’s increase of $36 million (14%) was primarily due to higher earnings from EPNG and CIG. EPNG experienced higher volumes in 2019 from increased Permian basin-related activity and associated capacity sales. CIG earnings were higher due to continued growing production in the Denver Julesburg basin;

• Midstream’s increase of $34 million (10%) was primarily due to increased earnings from South Texas Midstream and KinderHawk Field Services LLC resulting from increased drilling and production in the Eagle Ford and Haynesville basins, respectively; and

• South Region’s decrease of $2 million (1%) was primarily due to a decrease in earnings from Southern Gulf LNG Company, L.L.C. as a result of a loss of revenues from an arbitration ruling resulting in a contract termination in 2018 partially offset by an increase in earnings from an SNG expansion.

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Products Pipelines

	Three Months Ended March 31,
	2019			2018
	(In millions, except operating statistics)
Revenues	$	424		$	442
Operating expenses(a)	(166		)	(193		)
Earnings from equity investments	18			16
Other, net	—			1
Segment EBDA(a)	276			266
Certain items(a)	17			31
Segment EBDA before certain items	$	293		$	297
Change from prior period	Increase/(Decrease)
Revenues	$	(18	)	(4		)%
Segment EBDA before certain items	$	(4	)	(1		)%
Gasoline(b)	980			978
Diesel fuel	337			342
Jet fuel	294			289
Total refined product volumes(c)	1,611			1,609
Crude and condensate(c)	643			593
Total delivery volumes (MBbl/d)	2,254			2,202

_______

Certain items affecting Segment EBDA

(a) 2019 amount includes an increase in expense of $17 million related to an adjustment of tax reserves, other than income taxes. 2018 amount includes an increase in expense of $31 million associated with a certain Pacific operations litigation matter.

Other

(b) Volumes include ethanol pipeline volumes.

(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 month periods ended March 31, 2019 and 2018.

Three Months Ended March 31, 2019 versus Three Months Ended March 31, 2018

	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Crude & Condensate	$	(8	)	(7	)%	$	(23	)	(13	)%
Southeast Refined Products	4			6	%	(1		)	(1	)%
West Coast Refined Products	—			—	%	6			4	%
Total Products Pipelines	$	(4	)	(1	)%	$	(18	)	(4	)%

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 month periods ended March 31, 2019 and 2018:

• Crude & Condensate’s decrease of $8 million (7%) was primarily due to a decrease of earnings from Kinder Morgan Crude & Condensate Pipeline driven by lower services revenues as a result of unfavorable rates on contract renewals partially offset by increased earnings from Double H pipeline driven by an increase in Bakken crude oil volumes;

• Southeast Refined Products’ increase of $4 million (6%) was primarily due to increased equity earnings from Plantation pipeline as a result of increased transportation revenues driven by higher volumes and average tariff rate and an increase in earnings from South East Terminals; and

• West Coast Refined Products’ earnings were flat as increased earnings from Calnev due to higher revenues as a result of increased tariff rates on deliveries to Nevada were offset by a decrease in earnings from Pacific operations which was

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driven by an increase in environmental reserves partially offset by higher revenues primarily due to higher tariff rates at certain locations.

Terminals

	Three Months Ended March 31,
	2019			2018
	(In millions, except operating statistics)
Revenues(a)	$	509		$	495
Operating expenses(b)	(216		)	(207		)
Earnings from equity investments	5			7
Other, net	1			1
Segment EBDA(b)	299			296
Certain items(b)	—			1
Segment EBDA before certain items	$	299		$	297
Change from prior period	Increase/(Decrease)
Revenues before certain items	$	15		3		%
Segment EBDA before certain items	$	2		1		%
Liquids tankage capacity available for service (MMBbl)	91.9			90.5
Liquids utilization %(c)	93.9		%	91.4		%
Bulk transload tonnage (MMtons)	14.7			14.4

_______

Certain items affecting Segment EBDA

(a) 2018 amount includes an increase in revenue of $1 million from an other certain item.

(b) In addition to the revenue certain items described in footnote (a) above: 2018 amount also includes an increase in expense of $2 million related to hurricane repair costs.

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 month periods ended March 31, 2019 and 2018.

Three Months Ended March 31, 2019 versus Three Months Ended March 31, 2018

	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Gulf Liquids	$	6		8	%	$	7		7	%
Marine Operations	3			6	%	3			4	%
Alberta Canada	(5		)	(13	)%	6			14	%
Gulf Central	(3		)	(18	)%	(2		)	(8	)%
All others (including intrasegment eliminations)	1			1	%	1			—	%
Total Terminals	$	2		1	%	$	15		3	%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three month periods ended March 31, 2019 and 2018:

• increase of $6 million (8%) from our Gulf Liquids terminals primarily driven by a customer rebate adversely impacting revenue recognized in the prior period and annual rate escalations on existing storage contracts;

• increase of $3 million (6%) from our Marine Operations primarily due to fewer dry dock days on the Florida, one of our Jones Act tankers, and higher charter rates;

• decrease of $5 million (13%) from our Alberta Canada terminals primarily due to an increase in operating expenses associated with lease fees at our Edmonton South Terminal following the TMPL Sale partially offset by an increase in earnings due to the commencement of operations at our Base Line Terminal joint venture; and

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• decrease of $3 million (18%) from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018.

CO2

	Three Months Ended March 31,
	2019			2018
	(In millions, except operating statistics)
Revenues(a)	$	305		$	304
Operating expenses	(117		)	(115		)
Earnings from equity investments	10			10
Segment EBDA(a)	198			199
Certain items(a)	(9		)	38
Segment EBDA before certain items	$	189		$	237
Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(46	)	(13		)%
Segment EBDA before certain items	$	(48	)	(20		)%
SACROC oil production (net)	24.4			24.6
Yates oil production	7.3			7.7
Katz and Goldsmith oil production	4.1			5.2
Tall Cotton oil production	2.6			2.1
Total oil production (net)(MBbl/d)(b)	38.4			39.6
NGL sales volumes (MBbl/d)(b)	10.1			10.2
Southwest Colorado CO2 production (gross)(Bcf/d)	1.3			1.3
Southwest Colorado CO2 production (net)(Bcf/d)	0.6			0.6
Realized weighted-average oil price per Bbl(c)	$	48.67		$	59.72
Realized weighted-average NGL price per Bbl(d)	$	25.98		$	30.39

_______

Certain items affecting Segment EBDA

(a) 2019 and 2018 amounts include unrealized gains of $9 million and unrealized losses of $38 million, respectively, related to derivative contracts used to hedge forecasted commodity sales.

Other

(b) Net after royalties and outside working interests.

(c) Includes all crude oil production properties.

(d) Includes all NGL sales.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three month periods ended March 31, 2019 and 2018.

Three Months Ended March 31, 2019 versus Three Months Ended March 31, 2018

	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	(51	)	(31	)%	$	(51	)	(20	)%
Source and Transportation Activities	3			4	%	3			3	%
Intrasegment eliminations	—			—	%	2			22	%
Total CO2	$	(48	)	(20	)%	$	(46	)	(13	)%

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The changes in Segment EBDA for our CO₂ business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three month periods ended March 31, 2019 and 2018:

• decrease of $51 million (31%) from our Oil and Gas Producing activities primarily due to decreased revenues of $51 million driven by lower crude oil and NGL prices of $44 million and lower volumes of $7 million; and

• increase of $3 million (4%) from our Source and Transportation activities primarily due tohigher CO₂ sales of $3 million driven by higher volumes.

Kinder Morgan Canada

	Three Months Ended March 31,
	2019			2018
	(In millions, except operating statistics)
Revenues	$	—		$	61
Operating expenses	—			(24		)
Loss on divestiture(a)	(2		)	—
Other, net	—			9
Segment EBDA(a)	$	(2	)	$	46
Certain items(a)	2			—
Segment EBDA before certain items	$	—		$	46
Change from prior period	Increase/(Decrease)
Revenues	$	(61	)	(100		)%
Segment EBDA before certain items	$	(46	)	(100		)%
Transport volumes (MBbl/d)(b)	—			288

_______

Certain items affecting Segment EBDA

(a) 2019 amount represents a true-up of the working capital adjustment on the TMPL sale.

Other

(b) Represents TMPL average daily volumes.

For the comparable three month periods of 2019 and 2018, the Kinder Morgan Canada business segment had decreases in Segment EBDA of $46 million (100%) due to the TMPL Sale on August 31, 2018. Subsequent to the TMPL Sale, this business segment does not have results of operations.

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

	Three Months Ended March 31,
	2019			2018		Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	161		$	160	$	1		1	%
Certain items(a)	(3		)	4		(7		)	(175	)%
General and administrative and corporate charges before certain items(a)	$	158		$	164	$	(6	)	(4	)%
Interest, net(b)	$	460		$	467	$	(7	)	(1	)%
Certain items(b)	(2		)	5		(7		)	(140	)%
Interest, net, before certain items(b)	$	458		$	472	$	(14	)	(3	)%
Net income attributable to noncontrolling interests	$	11		$	18	$	(7	)	(39	)%
Net income attributable to noncontrolling interests before certain items	$	11		$	18	$	(7	)	(39	)%

Certain items

(a) 2019 amount includes an increase in expense of $3 million related to other certain items. 2018 amount includes (i) a decrease in expense of $12 million related to an adjustment of tax reserves, other than income taxes; (ii) an increase in expense of $6 million related to certain corporate litigation matters; and (iii) an increase in expense of $2 million related to other certain items.

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(b) 2019 and 2018 amounts include (i) decreases in interest expense of $8 million and $10 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) increases in expense of $10 million and $5 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and hedged debt.

The decrease in general and administrative expenses and corporate charges before certain items of $6 million in the first quarter of 2019 when compared with the same quarter in the prior year was primarily due to higher capitalized costs of $18 million driven by the 2019 construction of Gulf Coast Express and Permian Highway facilities and lower expenses of $7 million due to the sale of TMPL partially offset by higher pension and benefit-related costs of $17 million.

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 first quarter of 2019 when compared with the same quarter in the prior year decreased $14 million. The decrease in interest expense was primarily due to lower weighted average long-term rates and lower debt balances partially offset by higher LIBOR rates which impacted our short-term debt and interest rate swap agreements.

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 March 31, 2019 and December 31, 2018, approximately 31% 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 first quarter of 2019 when compared with the same quarter in the prior year decreased $7 million primarily due to the TMPL Sale.

Income Taxes

Our tax expense for the three months ended March 31, 2019 was approximately $172 million as compared with $164 million for the same period of 2018. The $8 million increase in tax expense was primarily due to an increase in pre-tax earnings.

Liquidity and Capital Resources

General

As of March 31, 2019, we had $221 million of “Cash and cash equivalents,” a decrease of $3,059 million (93%) from December 31, 2018. The 2018 TMPL Sale mentioned above in “—General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project” was the primary source of cash on hand as of December 31, 2018. 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 $635 million and $974 million in the first three months of 2019 and 2018, respectively. The period-to-period decrease 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.

Short-term Liquidity

As of March 31, 2019, our principal sources of short-term liquidity are (i) cash from operations; (ii) our $4.5 billion revolving credit facilities and associated $4.0 billion commercial paper program; and (iii) KML’s 4-year, C$500 million unsecured revolving credit facility (for KML’s working capital needs). The loan commitments under our revolving credit facilities can be used for working capital and other general corporate purposes and, additionally for us, as a backup to our

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commercial paper program. Letters of credit reduce borrowings allowed under our and KML’s respective credit facilities. Issuances of commercial paper also reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.

As of March 31, 2019, our $2,502 million of short-term debt consisted primarily of (i) $38 million outstanding borrowings under KML’s $500 million revolving credit facility; (ii) $109 million outstanding under our $4.0 billion commercial paper program; and (iii) $2,200 million of senior notes that mature in the next twelve months. 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, 2018 was $3,388 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,747 million and $1,835 million as of March 31, 2019 and December 31, 2018, respectively.  Our current liabilities may include short-term borrowings, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $912 million (50%) unfavorable change from year-end 2018 was primarily due to a decrease in cash of $3,059 million partially offset by a decrease in short-term debt and distributions payable of $1,762 million and a net decrease in accrued interest and accrued taxes. 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 that 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—Non-GAAP Financial Measures—DCF”). 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 that 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 a maintenance/sustaining or as an expansion capital expenditure 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 three months ended March 31, 2019, and the amount we expect to spend for the remainder of 2019 to sustain and grow our businesses are as follows:

	Three Months Ended March 31, 2019		2019 Remaining		Total 2019
	(In millions)
Sustaining capital expenditures(a)(b)	$	115	$	597	$	712
KMI Discretionary capital investments(b)(c)(d)	$	594	$	2,367	$	2,961
KML Discretionary capital investments(b)	$	2	$	25	$	27

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(a) Three months ended March 31, 2019, 2019 Remaining, and Total 2019 amounts include $19 million, $104 million, and $123 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) Three months ended March 31, 2019 amount excludes $148 million of net changes from accrued capital expenditures, contractor retainage, and other.

(c) Three months ended March 31, 2019 amount includes $286 million of our contributions to certain unconsolidated joint ventures for capital investments.

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

Off Balance Sheet Arrangements

Other than commitments for the purchase of property, plant and equipment discussed following, 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, 2018 in our 2018 Form 10-K.

Commitments for the purchase of property, plant and equipment as of March 31, 2019 and December 31, 2018 were $443 million and $304 million, respectively.

Cash Flows

Operating Activities

The net decrease of $339 million in cash provided by operating activities for the three months ended March 31, 2019 compared to the respective 2018 period was primarily attributable to:

• $340 million of foreign income tax payments made in the 2019 period associated with the TMPL Sale.

Investing Activities

The $89 million net increase in cash used in investing activities for the three months ended March 31, 2019 compared to the respective 2018 period was primarily attributable to:

• a $265 million increase in cash used for contributions to equity investments primarily due to higher contributions we made to Gulf Coast Express Pipeline LLC, Permian Highway Pipeline LLC, and Citrus Corporation in the 2019 period compared with the 2018 period; partially offset by,

• a $153 million decrease in capital expenditures in the 2019 period over the comparative 2018 period primarily due to lower expenditures in our Terminals business segment and no expenditures in our Kinder Morgan Canada business segment due to the TMPL sale.

Financing Activities

The net increase of $2,699 million in cash used in financing activities for the three months ended March 31, 2019 compared to the respective 2018 period was primarily attributable to:

• a $1,927 million net increase in cash used related to debt activity as a result of net debt payments in the 2019 period compared to net debt issuances in the 2018 period. See Note 3 “Debt” for further information regarding our debt activity;

• an $879 million distribution of the TMPL sale proceeds to the KML restricted shareholders in the 2019 period. See Note 2 “Divestitures” for further information regarding this activity; and

• a $178 million increase in dividend payments to our common shareholders; partially offset by,

• a $248 million decrease in cash used due to less common shares repurchased under our common share buy-back program in the 2019 period compared to the 2018 period; and

• a $39 million decrease in cash used reflecting dividends paid to our mandatory convertible preferred shareholders in the 2018 period. All mandatory convertible preferred shares were converted into common shares in the fourth quarter of 2018.

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Dividends

KMI Common Stock Dividends

We expect to declare common stock dividends of $1.00 per share on our common stock for 2019.

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2018	$	0.20	January 16, 2019	January 31, 2019	February 15, 2019
March 31, 2019	0.25		April 17, 2019	April 30, 2019	May 15, 2019

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 2018 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.

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 January 3, 2019, KML distributed approximately $0.9 billion of the net proceeds from the TMPL Sale to its Restricted Voting Shareholders as a return of capital.

On January 16, 2019, KML’s board of directors suspended KML’s dividend reinvestment plan, effective with the payment of the fourth quarter 2018 dividend on February 15, 2019, in light of KML’s reduced need for capital.

On April 17, 2019, KML’s board of directors declared a dividend for the quarterly period ended March 31, 2019 of C$0.1625 per restricted voting share, payable on May 15, 2019 to KML restricted voting shareholders of record as of the close of business on April 30, 2019.

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, 2018, in Item 7A in our 2018 Form 10-K. For more information on our risk management activities, see Item 1, Note 5 “Risk Management” to our consolidated financial statements.

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Item 4.  Controls and Procedures.

As of March 31, 2019, 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 March 31, 2019 that 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 11 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 2018 Form 10-K.

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

Our Purchases of Our Class P Shares
Period	Total number of securities purchased(a)	Average price paid per security		Total number of securities purchased as part of publicly announced plans(a)	Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
January 1 to January 31, 2019	140,500	$	15.32	140,500	$	1,474,909,370
February 1 to February 28, 2019	—	$	—	—	$	1,474,909,370
March 1 to March 31, 2019	—	$	—	—	$	1,474,909,370
Total	140,500	$	15.32	140,500	$	1,474,909,370

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(a) On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. After repurchase, the shares are canceled and no longer outstanding.

Item 3.  Defaults Upon Senior Securities.

None. 

Item 4.  Mine Safety Disclosures.

The Company does not own or operate 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 March 31, 2019.

Item 5.  Other Information.

None.

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Item 6.  Exhibits.

Exhibit NumberDescription
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 March 31, 2019.
10.2	*	Amendment No. 3 to KMI 2015 Amended and Restated Stock Incentive Plan (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed on January 22, 2019 (File No. 001-35081)).
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 furnished 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 furnished 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 months ended March 31, 2019 and 2018; (ii) our Consolidated Statements of Comprehensive Income for the three months ended March 31, 2019 and 2018; (iii) our Consolidated Balance Sheets as of March 31, 2019 and December 31, 2018; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, 2019 and 2018; (v) our Consolidated Statements of Stockholders’ Equity for the three months ended March 31, 2019 and 2018; and (vi) the notes to our Consolidated Financial Statements.

_______

*Asterisk indicates exhibits incorporated by reference as indicated; all other exhibits are filed herewith.

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SIGNATURE

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

KINDER MORGAN, INC.
	Registrant

Date:	April 22, 2019	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

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