Kinder Morgan - 10-Q quarterly report FY2019 Q2

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2019

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)



Delaware	80-0682103
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices)(zip code)

Registrant’s telephone number, including area code: 713-369-9000

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
1.500% Senior Notes due 2022	KMI 22	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New York Stock Exchange

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 every Interactive Data File required to be submitted 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 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.

Large accelerated filer þ Accelerated filer o Non-accelerated filer o Smaller reporting company ☐ Emerging growth company ☐

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 ☐ No þ

As of July 12, 2019, the registrant had 2,263,805,146 Class P shares outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS



		Page Number
	Glossary	2
	Information Regarding Forward-Looking Statements	3

	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Six Months Ended June 30, 2019 and 2018	4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2019 and 2018	5
	Consolidated Balance Sheets - June 30, 2019 and December 31, 2018	6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2019 and 2018	7
	Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30, 2019 and 2018	9
	Notes to Consolidated Financial Statements	11

Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation	43
	Results of Operations	43
	Overview	43
	Consolidated Earnings Results	44
	Non-GAAP Financial Measures	45
	Segment Earnings Results	47
	General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests	53
	Income Taxes	55
	Liquidity and Capital Resources	55

Item 3.	Quantitative and Qualitative Disclosures About Market Risk	58

Item 4.	Controls and Procedures	58

	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	58

Item 1A.	Risk Factors	59

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59

Item 3.	Defaults Upon Senior Securities	59

Item 4.	Mine Safety Disclosures	59

Item 5.	Other Information	59

Item 6.	Exhibits	59

	Signature	60

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	KMP	=	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
KMI	=	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	=	The Tax Cuts & Jobs Act of 2017	FASB	=	Financial Accounting Standards Board
/d	=	per day	FERC	=	Federal Energy Regulatory Commission
BBtu	=	billion British Thermal Units	GAAP	=	U.S. Generally Accepted Accounting
Bcf	=	billion cubic feet	GAAP	=	Principles
CERCLA	=	Comprehensive Environmental Response,	LLC	=	limited liability company
CERCLA	=	Compensation and Liability Act	MBbl	=	thousand barrels
C$	=	Canadian dollars	MMBbl	=	million barrels
CO₂	=	carbon dioxide or our CO₂ business segment	NGL	=	natural gas liquids
DCF	=	distributable cash flow	NYMEX	=	New York Mercantile Exchange
DD&A	=	depreciation, depletion and amortization	OTC	=	over-the-counter
EBDA	=	earnings before depreciation, depletion and	ROU	=	right of use
		amortization expenses, including amortization of	U.S.	=	United States of America
		excess cost of equity investments	WTI	=	West Texas Intermediate


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

Information Regarding Forward-Looking Statements

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
Services	$	2,011		$	1,984		$	4,047		$	3,951
Natural gas sales	609			727			1,383			1,554
Product sales and other	594			717			1,213			1,341
Total Revenues	3,214			3,428			6,643			6,846

Operating Costs, Expenses and Other
Costs of sales	777			1,068			1,725			2,087
Operations and maintenance	646			617			1,244			1,236
Depreciation, depletion and amortization	579			571			1,172			1,141
General and administrative	148			164			302			337
Taxes, other than income taxes	103			85			221			173
(Gain) loss on impairments and divestitures, net	(10		)	653			(10		)	653
Other income, net	(2		)	(2		)	(2		)	(2		)
Total Operating Costs, Expenses and Other	2,241			3,156			4,652			5,625

Operating Income	973			272			1,991			1,221

Other Income (Expense)
Earnings from equity investments	161			58			353			278
Amortization of excess cost of equity investments	(19		)	(24		)	(40		)	(56		)
Interest, net	(452		)	(516		)	(912		)	(983		)
Other, net	13			34			23			70
Total Other Expense	(297		)	(448		)	(576		)	(691		)

Income (Loss) Before Income Taxes	676			(176		)	1,415			530

Income Tax (Expense) Benefit	(148		)	46			(320		)	(118		)

Net Income (Loss)	528			(130		)	1,095			412
Net Income Attributable to Noncontrolling Interests	(10		)	(11		)	(21		)	(29		)

Net Income (Loss) Attributable to Kinder Morgan, Inc.	518			(141		)	1,074			383

Preferred Stock Dividends	—			(39		)	—			(78		)

Net Income (Loss) Available to Common Stockholders	$	518		$	(180	)	$	1,074		$	305

Class P Shares
Basic and Diluted Earnings (Loss) Per Common Share	$	0.23		$	(0.08	)	$	0.47		$	0.14

Basic and Diluted Weighted Average Common Shares Outstanding	2,262			2,204			2,262			2,206

Dividends Per Common Share Declared for the Period	$	0.25		$	0.20		$	0.50		$	0.40

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In Millions)

(Unaudited)



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018

Net income (loss)	$	528		$	(130	)	$	1,095		$	412
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(19), 24, $45 and $13, respectively)	63			(80		)	(152		)	(46		)
Reclassification of change in fair value of derivatives to net income (net of tax benefit (expense) of $6, $(24), $2 and $(19), respectively)	(18		)	83			(5		)	67
Foreign currency translation adjustments (net of tax (expense) benefit of $(2), $9, $(7) and $21, respectively)	13			(48		)	23			(113		)
Benefit plan adjustments (net of tax expense of $3, $2, $5 and $4, respectively)	7			6			15			12
Total other comprehensive income (loss)	65			(39		)	(119		)	(80		)

Comprehensive income (loss)	593			(169		)	976			332
Comprehensive (income) loss attributable to noncontrolling interests	(15		)	5			(20		)	11
Comprehensive income (loss) attributable to Kinder Morgan, Inc.	$	578		$	(164	)	$	956		$	343

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

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

	June 30, 2019			December 31, 2018
ASSETS
Current Assets
Cash and cash equivalents	$	213		$	3,280
Restricted deposits	36			51
Accounts receivable, net	1,227			1,498
Fair value of derivative contracts	110			260
Inventories	450			385
Other current assets	264			248
Total current assets	2,300			5,722

Property, plant and equipment, net	37,840			37,897
Investments	8,124			7,481
Goodwill	21,964			21,965
Other intangibles, net	2,782			2,880
Deferred income taxes	1,487			1,566
Deferred charges and other assets	2,198			1,355
Total Assets	$	76,695		$	78,866

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	3,054		$	3,388
Accounts payable	900			1,337
Distributions payable to KML noncontrolling interests	—			876
Accrued interest	531			579
Accrued taxes	298			483
Other current liabilities	876			894
Total current liabilities	5,659			7,557
Long-term liabilities and deferred credits
Long-term debt
Outstanding	31,848			33,105
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	1,057			731
Total long-term debt	33,005			33,936
Other long-term liabilities and deferred credits	2,772			2,176
Total long-term liabilities and deferred credits	35,777			36,112
Total Liabilities	41,436			43,669
Commitments and contingencies (Notes 3, 10 and 11)
Redeemable Noncontrolling Interest	775			666
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,262,497,678 and 2,262,165,783 shares, respectively, issued and outstanding	23			23
Additional paid-in capital	41,734			41,701
Retained deficit	(7,671		)	(7,716		)
Accumulated other comprehensive loss	(448		)	(330		)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,638			33,678
Noncontrolling interests	846			853
Total Stockholders’ Equity	34,484			34,531
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	76,695		$	78,866

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

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

	Six Months Ended June 30,
	2019			2018
Cash Flows From Operating Activities
Net income	$	1,095		$	412
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,172			1,141
Deferred income taxes	111			102
Amortization of excess cost of equity investments	40			56
Change in fair market value of derivative contracts	(7		)	139
(Gain) loss on impairments and divestitures, net	(10		)	653
Earnings from equity investments	(353		)	(278		)
Distributions from equity investment earnings	257			237
Changes in components of working capital
Accounts receivable, net	279			116
Inventories	(73		)	6
Other current assets	108			(21		)
Accounts payable	(255		)	(77		)
Accrued interest, net of interest rate swaps	(49		)	(26		)
Accrued taxes	(195		)	(30		)
Other current liabilities	(74		)	(82		)
Other, net	52			120
Net Cash Provided by Operating Activities	2,098			2,468

Cash Flows From Investing Activities
Acquisitions of assets and investments	(3		)	(20		)
Capital expenditures	(1,178		)	(1,473		)
Sales of assets and equity investments, net of working capital settlements	80			33
Sales of property, plant and equipment, net of removal costs	3			6
Contributions to investments	(812		)	(111		)
Distributions from equity investments in excess of cumulative earnings	131			149
Loans to related party	(16		)	(16		)
Net Cash Used in Investing Activities	(1,795		)	(1,432		)

Cash Flows From Financing Activities
Issuances of debt	3,042			8,565
Payments of debt	(4,622		)	(8,575		)
Debt issue costs	(6		)	(31		)
Cash dividends - common shares	(1,024		)	(719		)
Cash dividends - preferred shares	—			(78		)
Repurchases of common shares	(2		)	(250		)
Contributions from investment partner	109			97
Contributions from noncontrolling interests	1			17
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	(879		)	—
Distributions to noncontrolling interests - other	(28		)	(35		)
Other, net	(4		)	(1		)
Net Cash Used in Financing Activities	(3,413		)	(1,010		)

Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	28			(5		)

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(3,082		)	21
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	249		$	347

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

	Six Months Ended June 30,
	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	213			271
Restricted Deposits, end of period	36			76
Cash, Cash Equivalents, and Restricted Deposits, end of period	249			347

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(3,082	)	$	21

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized (Note 10)	$	743
Increase in property, plant and equipment from both accruals and contractor retainage				$	33
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	952			954
Cash paid during the period for income taxes, net	370			18

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In Millions)

(Unaudited)



	Common stock
	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 March 31, 2019	2,262	$	23	$	41,716	$	(7,620	)	$	(508	)	$	33,611		$	844		$	34,455
Restricted shares				18								18						18
Net income						518						518			10			528
Distributions												—			(14		)	(14		)
Contributions												—			1			1
Common stock dividends						(569		)				(569		)				(569		)
Other comprehensive income									60			60			5			65
Balance at June 30, 2019	2,262	$	23	$	41,734	$	(7,671	)	$	(448	)	$	33,638		$	846		$	34,484



	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 March 31, 2018	2	$	—	2,204	$	22	$	41,677	$	(7,371	)	$	(667	)	$	33,661		$	1,468		$	35,129
Restricted shares							19								19						19
Net (loss) income									(141		)				(141		)	11			(130		)
Distributions															—			(23		)	(23		)
Contributions															—			19			19
Preferred stock dividends									(39		)				(39		)				(39		)
Common stock dividends									(442		)				(442		)				(442		)
Other comprehensive loss												(23		)	(23		)	(16		)	(39		)
Balance at June 30, 2018	2	$	—	2,204	$	22	$	41,696	$	(7,993	)	$	(690	)	$	33,035		$	1,459		$	34,494

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(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)							(5		)				(5		)				(5		)
Balance at January 1, 2019	2,262	23		41,701			(7,721		)	(330		)	33,673			853			34,526
Repurchase of shares				(2		)							(2		)				(2		)
Restricted shares				35									35						35
Net income							1,074						1,074			21			1,095
Distributions													—			(28		)	(28		)
Contributions													—			1			1
Common stock dividends							(1,024		)				(1,024		)				(1,024		)
Other comprehensive loss										(118		)	(118		)	(1		)	(119		)
Balance at June 30, 2019	2,262	$	23	$	41,734		$	(7,671	)	$	(448	)	$	33,638		$	846		$	34,484



	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								37									37						37
Net income											383						383			29			412
Distributions																	—			(44		)	(44		)
Contributions																	—			26			26
Preferred stock dividends											(78		)				(78		)				(78		)
Common stock dividends											(719		)				(719		)				(719		)
Other comprehensive loss														(40		)	(40		)	(40		)	(80		)
Balance at June 30, 2018	2	$	—	2,204		$	22	$	41,696		$	(7,993	)	$	(690	)	$	33,035		$	1,459		$	34,494

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 84,000 miles of pipelines and 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. In compliance with 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.

Impairments and Losses on Divestitures, net

During the three and six months ended June 30, 2018, we recognized (i) a $600 million non-cash impairment loss associated with certain gathering and processing assets in Oklahoma within our Natural Gas Pipelines business segment; (ii) a $60 million non-cash impairment related to certain Terminal business segment assets; (iii) a non-cash impairment of $270 million of our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG) which is included in “Earnings from equity investments” in the accompanying consolidated statements of income for both the three and six months ended June 30, 2018; and (iv) a gain of $7 million related to miscellaneous asset dispositions. For additional information regarding our 2018 impairments and divestitures, see Note 4 to our consolidated financial statements included in our 2018 Form 10-K.

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

Goodwill

In addition to periodically evaluating long-lived assets for impairment based on changes in market conditions as discussed above, we evaluate goodwill for impairment on May 31 of each year. For this purpose, we have six reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO₂; and (vi) Terminals. The evaluation of goodwill for impairment involves a two-step test.

The results of our May 31, 2019 annual step 1 impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. A future period of volatile commodity prices could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital and our cash flow estimates. Changes to any one or combination of these factors would result in a change to the reporting unit fair values discussed above, which could lead to future impairment charges. Such potential impairment could have a material effect on our results of operations.

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

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P shares and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

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



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Net Income (Loss) Available to Common Stockholders	$	518		$	(180	)	$	1,074		$	305
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3		)	(2		)	(6		)	(3		)
Net Income (Loss) Allocated to Class P Stockholders	$	515		$	(182	)	$	1,068		$	302

Basic Weighted Average Common Shares Outstanding	2,262			2,204			2,262			2,206
Basic Earnings (Loss) Per Common Share	$	0.23		$	(0.08	)	$	0.47		$	0.14

________


(a)	As of June 30, 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 June 30,		Six Months Ended June 30,
	2019	2018	2019	2018
Unvested restricted stock awards	13	10	13	10
Convertible trust preferred securities	3	3	3	3
Mandatory convertible preferred stock(a)	—	58	—	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 first quarter of 2019, KML settled the remaining C$37 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 six months ended June 30, 2019 and 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

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):



	June 30, 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)	136		433
KML C$500 million credit facility, due August 31, 2022(b)(c)	27		—
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		—
6.50%, due April 2020	535		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion - Other debt	45		44
Total current portion of debt	3,054		3,388

Long-term debt (excluding current portion)
Senior notes	31,133		32,380
EPC Building, LLC, promissory note, 3.967%, due 2018 through 2035	388		395
Kinder Morgan G.P. Inc., $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057	100		100
Trust I preferred securities, 4.75%, due March 2028	110		110
Other	217		220
Total long-term debt	31,948		33,205
Total debt(d)	$	35,002	$	36,593

_______


(a)	Weighted average interest rates on borrowings outstanding as of June 30, 2019 and December 31, 2018 were 2.62% and 3.10%, respectively.


(b)	Weighted average interest rate on borrowings outstanding as of June 30, 2019 was 3.41%.


(c)	Borrowings under the KML $500 million credit facility are denominated in C$ and are presented above in U.S. dollars. At June 30, 2019, the exchange rate was 0.7641 U.S. dollars per C$. See “—Credit Facilities—KML” below.


(d)	Excludes our “Debt fair value adjustments” which, as of June 30, 2019 and December 31, 2018, increased our total debt balances by $1,057 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. For more information, see Note 13.

Credit Facilities

KMI

As of June 30, 2019, we had no borrowings outstanding under our credit facilities, $136 million outstanding under our $4 billion commercial paper program and $84 million in letters of credit. Our availability under these facilities as of June 30, 2019 was $4,280 million. As of June 30, 2019, we were in compliance with all required covenants.

KML

As of June 30, 2019, KML had C$35 million (U.S.$27 million) of borrowings outstanding under its 4-year, C$500 million unsecured revolving credit facility, due August 31, 2022, with C$459 million (U.S.$350 million) available after further reducing the C$500 million (U.S.$382 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 credit to KML. As of June 30, 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 June 30, 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 six months ended June 30, 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 at an average price of approximately $18.18 per share 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 June 30,				Six Months Ended June 30,
	2019		2018		2019		2018
Per common share cash dividend declared for the period	$	0.25	$	0.20	$	0.50	$	0.40
Per common share cash dividend paid in the period	$	0.25	$	0.20	$	0.45	$	0.325

On July 17, 2019, our board of directors declared a cash dividend of $0.25 per common share for the quarterly period ended June 30, 2019, which is payable on August 15, 2019 to common shareholders of record as of the close of business on July 31, 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 and six months ended June 30, 2019, KML paid dividends to the public on its restricted voting shares of $5 million and $9 million, respectively, and on its Series 1 and Series 3 Preferred Shares of $6 million and $11 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 our adoption of this ASU was a $66 million, net of income taxes, adjustment to our beginning “Retained deficit” balance as presented in our consolidated statement of stockholders’ equity for the six months ended June 30, 2018. This ASU also required us to classify EIG’s cumulative contribution to ELC as mezzanine equity, which we have included as “Redeemable noncontrolling interest” on our consolidated balance sheets as of June 30, 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. Our 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 six months ended June 30, 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 No. 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. We applied ASU No. 2017-12 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. Our adoption of ASU No. 2017-12 did not have a material impact on our consolidated financial statements.

Energy Commodity Price Risk Management

As of June 30, 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	(18.7	)	MMBbl
Crude oil basis	(10.3	)	MMBbl
Natural gas fixed price	(56.4	)	Bcf
Natural gas basis	(35.2	)	Bcf
NGL fixed price	(0.7	)	MMBbl
Derivatives not designated as hedging instruments
Crude oil fixed price	(0.7	)	MMBbl
Crude oil basis	(5.5	)	MMBbl
Natural gas fixed price	(1.7	)	Bcf
Natural gas basis	(31.5	)	Bcf
NGL fixed price	(2.1	)	MMBbl

As of June 30, 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 June 30, 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 June 30, 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 June 30, 2019, the maximum length of time over 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.

During the three months ended June 30, 2019, we entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $250 million, which was designated as a cash flow hedge. This agreement effectively converts the interest expense associated with certain variable rate debt issuances from floating rates to fixed rates. As of June 30, 2019, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is through January 15, 2023.

Foreign Currency Risk Management

As of both June 30, 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 critical terms of the cross-currency swap agreements correspond to the related 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 “Foreign currency translation adjustments” section of “Other comprehensive income (loss), net of tax” on our consolidated statements of comprehensive income.

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
		June 30, 2019		December 31, 2018		June 30, 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)	$	59	$	135	$	(81	)	$	(45	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	22		64		(11		)	—
Subtotal		81		199		(92		)	(45		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	34		12		(7		)	(37		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	328		121		(1		)	(78		)
Subtotal		362		133		(8		)	(115		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		91		(21		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	95		106		—			—
Subtotal		95		197		(21		)	(6		)
Total		538		529		(121		)	(166		)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	17		22		(5		)	(5		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(2		)	—
Total		17		22		(7		)	(5		)
Total derivatives		$	555	$	551	$	(128	)	$	(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 June 30,						Six Months Ended June 30,
		2019			2018			2019			2018

Interest rate contracts	Interest, net	$	208		$	(81	)	$	336		$	(254	)

Hedged fixed rate debt(a)	Interest, net	$	(211	)	$	77		$	(349	)	$	245

_______


(a)	As of June 30, 2019, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of $355 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheets.



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 June 30,							Three Months Ended June 30,
	2019			2018				2019			2018
Energy commodity derivative contracts	$	75		$	(23	)	Revenues—Natural gas sales	$	2		$	(5	)
							Revenues—Product sales and other	(9		)	(13		)
							Costs of sales	10			—
Interest rate contracts	(1		)	1			Earnings from equity investments(c)	2			(3		)
Foreign currency contracts	8			(58		)	Other, net	19			(62		)
Total	$	82		$	(80	)	Total	$	24		$	(83	)



Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,							Six Months Ended June 30,
	2019			2018				2019			2018
Energy commodity derivative contracts	$	(170	)	$	(40	)	Revenues—Natural gas sales	$	5		$	(5	)
							Revenues—Product sales and other	1			(27		)
							Costs of sales	11			—
Interest rate contracts	(1		)	2			Earnings from equity investments(c)	2			(4		)
Foreign currency contracts	(26		)	(8		)	Other, net	(12		)	(31		)
Total	$	(197	)	$	(46	)	Total	$	7		$	(67	)

_______

(a)

We expect to reclassify an approximate $9 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 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)	During the three months ended June 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).


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



Derivatives not designated as hedging instruments	Location	Gain/(loss) recognized in income on derivative
		Three Months Ended June 30,						Six Months Ended June 30,
		2019			2018			2019			2018
Energy commodity derivative contracts	Revenues—Natural gas sales	$	5		$	(1	)	$	25		$	2
	Revenues—Product sales and other	9			(45		)	(1		)	(46		)
	Costs of sales	(1		)	1			(3		)	1
	Earnings from equity investments(b)	2			—			2			—
Total(a)		$	15		$	(45	)	$	23		$	(43	)

_______


(a)	The three and six months ended June 30, 2019 include an approximate loss of $6 million and gain of $2 million, respectively, and the three and six months ended June 30, 2018 include an approximate loss of $5 million and gain of $3 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

(b) Amounts represent our share of an equity investee’s income (loss).

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of June 30, 2019 and December 31, 2018, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2019 and December 31, 2018, we had cash margins of $33 million and $16 million, respectively, posted by our counterparties with us as collateral and reported within “Other Current Liabilities” on our accompanying consolidated balance sheets. The balance at June 30, 2019 consisted of initial margin requirements of $10 million offset by variation margin requirements of $43 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of June 30, 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 estimate that we would be required to post $29 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	(152		)	24			15			(113		)
Gains reclassified from accumulated other comprehensive loss	(5		)	—			—			(5		)
Net current-period change in accumulated other comprehensive (loss) income	(157		)	24			15			(118		)
Balance as of June 30, 2019	$	7		$	(67	)	$	(388	)	$	(448	)



	Net unrealized gains/(losses) on cash flow hedge derivatives			Foreign currency translation adjustments			Pension and other postretirement liability adjustments			Total accumulated other comprehensive loss
Balance as of December 31, 2017	$	(27	)	$	(189	)	$	(325	)	$	(541	)
Other comprehensive (loss) gain before reclassifications	(46		)	(73		)	12			(107		)
Losses reclassified from accumulated other comprehensive loss	67			—			—			67
Impact of adoption of ASU 2018-02 (Note 4)	(4		)	(36		)	(69		)	(109		)
Net current-period change in accumulated other comprehensive income (loss)	17			(109		)	(57		)	(149		)
Balance as of June 30, 2018	$	(10	)	$	(298	)	$	(382	)	$	(690	)

6. Fair Value

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

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


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


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


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

Fair Value of Derivative Contracts

The following two tables summarize the fair value measurements of our (i) energy commodity derivative contracts; (ii) interest rate swap agreements; and (iii) cross-currency swap agreements, based on the three levels established by the 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)			Net amount
As of June 30, 2019
Energy commodity derivative contracts(a)	$	31	$	67	$	—	$	98	$	(24	)	$	(43	)	$	31
Interest rate contracts	—		362		—		362		(5		)	—			357
Foreign currency contracts	—		95		—		95		(21		)	—			74
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)		Net amount
As of June 30, 2019
Energy commodity derivative contracts(a)	$	(5	)	$	(94	)	$	—	$	(99	)	$	24	$	—	$	(75	)
Interest rate contracts	—			(8		)	—		(8		)	5		—		(3		)
Foreign currency contracts	—			(21		)	—		(21		)	21		—		—
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, NGL swaps and natural gas basis swaps.


(b)	Any cash collateral paid or received is reflected in this table, but only to the extent that such cash collateral 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):



	June 30, 2019				December 31, 2018
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	36,059	$	39,216	$	37,324	$	37,469

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2019 and December 31, 2018.

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 June 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	889	$	84	$	279	$	—	$	(1	)	$	1,251
Fee-based services	187		252		118		15		1			573
Total services revenues	1,076		336		397		15		—			1,824
Sales
Natural gas sales	607		—		—		—		(4		)	603
Product sales	197		61		5		291		(10		)	544
Total sales revenues	804		61		5		291		(14		)	1,147
Total revenues from contracts with customers	1,880		397		402		306		(14		)	2,971
Other revenues(c)	88		45		105		4		1			243
Total revenues	$	1,968	$	442	$	507	$	310	$	(13	)	$	3,214



	Three Months Ended June 30, 2018
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂			Kinder Morgan Canada(d)		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	826	$	99	$	263	$	—		$	—	$	(1	)	$	1,187
Fee-based services	162		239		153		16			62		(1		)	631
Total services revenues	988		338		416		16			62		(2		)	1,818
Sales
Natural gas sales	736		—		—		1			—		(1		)	736
Product sales	327		124		4		318			—		(10		)	763
Total sales revenues	1,063		124		4		319			—		(11		)	1,499
Total revenues from contracts with customers	2,051		462		420		335			62		(13		)	3,317
Other revenues(c)	56		41		95		(85		)	3		1			111
Total revenues	$	2,107	$	503	$	515	$	250		$	65	$	(12	)	$	3,428



	Six Months Ended June 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,819	$	164	$	529	$	—	$	(2	)	$	2,510
Fee-based services	379		487		266		31		—			1,163
Total services revenues	2,198		651		795		31		(2		)	3,673
Sales
Natural gas sales	1,361		—		—		1		(6		)	1,356
Product sales	437		127		7		559		(16		)	1,114
Total sales revenues	1,798		127		7		560		(22		)	2,470
Total revenues from contracts with customers	3,996		778		802		591		(24		)	6,143
Other revenues(c)	173		88		214		24		1			500
Total revenues	$	4,169	$	866	$	1,016	$	615	$	(23	)	$	6,643



	Six Months Ended June 30, 2018
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂			Kinder Morgan Canada(d)		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,671	$	191	$	519	$	1		$	—	$	(2	)	$	2,380
Fee-based services	326		460		297		33			126		—			1,242
Total services revenues	1,997		651		816		34			126		(2		)	3,622
Sales
Natural gas sales	1,564		—		—		1			—		(3		)	1,562
Product sales	546		216		7		635			—		(17		)	1,387
Total sales revenues	2,110		216		7		636			—		(20		)	2,949
Total revenues from contracts with customers	4,107		867		823		670			126		(22		)	6,571
Other revenues(c)	126		78		187		(116		)	—		—			275
Total revenues	$	4,233	$	945	$	1,010	$	554		$	126	$	(22	)	$	6,846

_______


(a)	Differences between the revenue classifications presented on the consolidated statements of income and the categories for the disaggregated revenues by type of revenue above are primarily attributable to revenues reflected in the “Other revenues” category above (see note (c) below).


(b)	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 index-based pricing, which along with revenues from other customer service contracts are reported as Fee-based services.


(c)	Amounts recognized as revenue under guidance prescribed in Topics of the ASC 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.


(d)	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).

Contract Balances

Contract assets and contract liabilities are the result of timing differences between revenue recognition, billings and cash collections.

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



	Six Months Ended June 30, 2019
Contract Assets
Balance at December 31, 2018(a)	$	24
Additions	52
Transfer to Accounts receivable	(20		)
Other	(1		)
Balance at June 30, 2019(b)	$	55
Contract Liabilities
Balance at December 31, 2018(c)	$	292
Additions	203
Transfer to Revenues	(193		)
Other(d)	1
Balance at June 30, 2019(e)	$	303

_______


(a)	Includes current and non-current balances of $14 million and $10 million, respectively.


(b)	Includes current and non-current balances of $45 million and $10 million, respectively.


(c)	Includes current and non-current balances of $80 million and $212 million, respectively.


(d)	Includes foreign currency translation adjustments.


(e)	Includes current and non-current balances of $84 million and $219 million, respectively.

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 June 30, 2019 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):



Year	Estimated Revenue
Six months ended December 31, 2019	$	2,555
2020	4,602
2021	3,884
2022	3,250
2023	2,717
Thereafter	15,299
Total	$	32,307

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 and six months ended June 30, 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 June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,956		$	2,095		$	4,148		$	4,211
Intersegment revenues	12			12			21			22
Products Pipelines	442			503			866			945
Terminals
Revenues from external customers	506			514			1,014			1,009
Intersegment revenues	1			1			2			1
CO₂	310			250			615			554
Kinder Morgan Canada(a)	—			65			—			126
Corporate and intersegment eliminations	(13		)	(12		)	(23		)	(22		)
Total consolidated revenues(b)	$	3,214		$	3,428		$	6,643		$	6,846



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Segment EBDA(c)
Natural Gas Pipelines	$	1,088		$	310		$	2,291		$	1,438
Products Pipelines	307			321			583			587
Terminals	290			275			589			571
CO₂	196			157			394			356
Kinder Morgan Canada(a)	—			46			(2		)	92
Total Segment EBDA(d)	1,881			1,109			3,855			3,044
DD&A	(579		)	(571		)	(1,172		)	(1,141		)
Amortization of excess cost of equity investments	(19		)	(24		)	(40		)	(56		)
General and administrative and corporate charges	(155		)	(174		)	(316		)	(334		)
Interest, net	(452		)	(516		)	(912		)	(983		)
Income tax (expense) benefit	(148		)	46			(320		)	(118		)
Total consolidated net income (loss)	$	528		$	(130	)	$	1,095		$	412



	June 30, 2019		December 31, 2018
Assets
Natural Gas Pipelines	$	50,750	$	50,261
Products Pipelines	9,543		9,598
Terminals	9,963		9,415
CO₂	3,729		3,928
Corporate assets(e)	2,710		5,664
Total consolidated assets(f)	$	76,695	$	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 (before reclassifications) for the three months ended June 30, 2018 were $2,166 million, $442 million, $513 million and $(8) million and for the six months ended June 30, 2018 were $4,332 million, $841 million, $1,006 million and $(13) million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, and the Corporate and intersegment eliminations, respectively.


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


(d)	Segment EBDA previously reported (before reclassifications) for the three months ended June 30, 2018 were $313 million, $319 million and $274 million and for the six months ended June 30, 2018 were $1,449 million, $578 million and $569 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 expense (benefit) included in our accompanying consolidated statements of income were as follows (in millions, except percentages):



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
Income tax expense (benefit)	$	148		$	(46	)	$	320		$	118
Effective tax rate	21.9		%	26.1		%	22.6		%	22.3		%

The effective tax rate for the three and six months ended June 30, 2019 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 Citrus Corporation (Citrus), NGPL Holdings LLC and Plantation Pipe Line Company (Plantation).

The effective tax rate for the three months ended June 30, 2018 is higher than the statutory federal rate of 21% primarily due to the reduction in our reserves for uncertain tax positions as a result of the settlement of our 2011 – 2014 federal tax audit reducing our income tax expense.

The effective tax rate for the six months ended June 30, 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 Citrus and Plantation and the reduction in our reserves for uncertain tax positions as a result of the settlement of our 2011 – 2014 federal tax audit reducing our income tax expense.

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, are reassessed when agreements are modified.

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



	Six Months Ended June 30, 2019
Operating leases	$	71
Short-term and variable leases	41
Total lease cost(a)	$	112

_______


(a)	Includes $20 million of capitalized lease costs.

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



	Six Months Ended June 30, 2019
Operating cash flows from operating leases	$	(92	)
Investing cash flows from operating leases	(20		)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	54
Amortization of ROU assets	37

Weighted average remaining lease term	16.74 years
Weighted average discount rate	5.92		%

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



Lease Activity	Balance sheet location	June 30, 2019
ROU assets	Deferred charges and other assets	$	713
Short-term lease liability	Other current liabilities	51
Long-term lease liability	Other long-term liabilities and deferred credits	662
Finance lease assets	Property, plant and equipment, net	2
Finance lease liabilities	Long-term debt—Outstanding	2

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of June 30, 2019 are as follows (in millions):



Six months ended December 31, 2019	$	49
2020	84
2021	76
2022	71
2023	65
Thereafter	825
Total lease payments(a)	1,170
Less: Interest	(457		)
Present value of lease liabilities	$	713

_______


(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 in our 2018 Form 10-K 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.

Lessor

Our assets that 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 that asset. These leases 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 an additional 25 years, and some of 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 and six months ended June 30, 2019 totaled $216 million and $434 million, respectively, 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 payments to be received based on contractual agreements are as follows (in millions):



	June 30, 2019
2019 (six months ended December 31, 2019)	$	197
2020	365
2021	348
2022	334
2023	304
Thereafter	3,668
Total	$	5,216

Options for a lessee to renew the agreement 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. KMI and certain of its pipeline affiliates successfully worked with their shippers to achieve settlements without the need for litigation or any additional intervention by the FERC. The FERC has approved settlements filed by EPNG, SNG, TGP and Young Gas Storage, and a settlement filed on Bear Creek Storage Company, L.L.C. is pending approval. The FERC has terminated all but two of the remaining 501-G proceedings without taking further action. The two remaining 501-G proceedings relate to systems under rate moratoriums. Accordingly, the vast majority of KMI’s 501-G exposure has been resolved.

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 were filed on June 26, 2019 by industry groups, pipeline companies, and shippers. There will be a round of reply comments before further action is taken by FERC.

SFPP

The tariffs and rates charged by SFPP are subject to a number of ongoing shipper-initiated proceedings at the FERC. These include IS08-390, filed in June 2008, in which various shippers are challenging SFPP’s West Line rates (currently on appeal to the D.C. Circuit Court); IS09-437, filed in July 2009, in which various shippers are challenging SFPP’s East Line rates (currently before the FERC on rehearing); OR11-13/16/18, filed in June 2011, in which various shippers are seeking to challenge SFPP’s North Line, Oregon Line, and West Line rates (not yet been set for hearing by the FERC); OR14-35/36, filed in June 2014, in which various shippers are challenging SFPP’s index increases in 2012 and 2013 (dismissed by the FERC, but remanded back to the FERC from the D.C. Circuit for further consideration); OR16-6, filed in December 2015, in which various shippers are challenging SFPP’s East line rates (pending before the FERC for an order on the initial decision); and OR19-21, filed in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 (currently pending before the FERC for an order on the complaints). 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. The issues involved in these proceedings include, among others, whether indexed rate increases are justified, and the appropriate level of return and income tax allowance SFPP may include in its rates. 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.

Per order of the FERC, in May 2019 SFPP paid refunds to shippers in the IS08-390 proceeding based on the denial of an income tax allowance. 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, EPNG’s appeal from the 2010 rate case, and the intervenors’ delayed appeal in the 2010 case. In accordance with that schedule, all briefing was 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. 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 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 into 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. On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract claim that had been asserted in the first arbitration and alleging that GLNG negligently misrepresented certain facts or contentions in the first arbitration. By its second Notice of Arbitration, Eni USA seeks to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Delaware Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Delaware Court of Chancery together with a motion seeking to permanently enjoin the arbitration. Oral argument on GLNG’s complaint and related motion will occur in August 2019, and all deadlines in the Second Arbitration have been stayed until September 2019. GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.

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 June 30, 2019 and December 31, 2018, our total reserve for legal matters was $215 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 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 20 uranium mines in the vicinity of Cameron, Arizona, many of which are located on the Navajo Indian Reservation. The mining activities were in response to numerous incentives provided to industry by the U.S. to locate and produce domestic sources of uranium to support the Cold War-era nuclear weapons program. In May 2012, EPNG received a general notice letter from the EPA notifying EPNG of the EPA’s investigation of certain sites and its determination that the EPA considers EPNG to be a 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 was not appealed by any party. 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. 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.

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 money damages, 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 on several grounds including federal officer liability. Plaquemines Parish, along with the intervenors, moved to remand the case to the state district court. On May 28, 2019, the case was remanded to the state district court for Plaquemines Parish. At the same time, the U.S. District Court certified the federal officer liability jurisdiction issue for review by the U.S. Fifth Circuit Court of Appeals and on June 11, 2019, the U.S. District Court stayed the remand order pending the outcome of that review. The case is effectively stayed pending resolution of the federal officer liability issue by the Court of Appeals. We will continue to vigorously defend this case.

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 money damages, 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. On May 28, 2019, Orleans moved to remand the case to the state district court. We will continue to 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, and 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. 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 for Plaquemines Parish, Louisiana for further proceedings. The case is set for trial February 3, 2020. 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 June 30, 2019 and December 31, 2018, we have accrued a total reserve for environmental liabilities in the amount of $264 million and $271 million, respectively. In addition, as of both June 30, 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 $450 million of 2019 maturing debt obligations at a certain equity investee and we would be obligated for our $225 million share of these obligations if the equity investee was unable to satisfy its 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 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 June 30, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $14,883 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 June 30, 2019 condensed consolidating balance sheet is approximately $157 million of other financing obligations that are not subject to the cross guarantee agreement.

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended June 30, 2019 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	2,934		$	299		$	(19	)	$	3,214

Operating Costs, Expenses and Other
Costs of sales	—			—			761			23			(7		)	777
Depreciation, depletion and amortization	5			—			506			68			—			579
Other operating expenses	4			—			768			125			(12		)	885
Total Operating Costs, Expenses and Other	9			—			2,035			216			(19		)	2,241

Operating (Loss) Income	(9		)	—			899			83			—			973

Other Income (Expense)
Earnings from consolidated subsidiaries	846			811			85			18			(1,760		)	—
Earnings from equity investments	—			—			161			—			—			161
Interest, net	(194		)	(2		)	(250		)	(6		)	—			(452		)
Amortization of excess cost of equity investments and other, net	(3		)	—			(1		)	(2		)	—			(6		)

Income Before Income Taxes	640			809			894			93			(1,760		)	676

Income Tax Expense	(122		)	(1		)	(21		)	(4		)	—			(148		)

Net Income	518			808			873			89			(1,760		)	528
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(10		)	(10		)
Net Income Attributable to Controlling Interests	$	518		$	808		$	873		$	89		$	(1,770	)	$	518

Net Income	$	518		$	808		$	873		$	89		$	(1,760	)	$	528
Total other comprehensive income	60			78			76			16			(165		)	65
Comprehensive income	578			886			949			105			(1,925		)	593
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(15		)	(15		)
Comprehensive income attributable to controlling interests	$	578		$	886		$	949		$	105		$	(1,940	)	$	578

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

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	3,047		$	399		$	(18	)	$	3,428

Operating Costs, Expenses and Other
Costs of sales	—			—			1,022			52			(6		)	1,068
Depreciation, depletion and amortization	4			—			486			81			—			571
Other operating expenses	6			—			1,377			146			(12		)	1,517
Total Operating Costs, Expenses and Other	10			—			2,885			279			(18		)	3,156

Operating (Loss) Income	(10		)	—			162			120			—			272

Other Income (Expense)
(Losses) earnings from consolidated subsidiaries	(2		)	(55		)	96			4			(43		)	—
Earnings from equity investments	—			—			58			—			—			58
Interest, net	(193		)	(2		)	(273		)	(48		)	—			(516		)
Amortization of excess cost of equity investments and other, net	7			—			(5		)	8			—			10

(Loss) Income Before Income Taxes	(198		)	(57		)	38			84			(43		)	(176		)

Income Tax Benefit (Expense)	57			(2		)	(19		)	10			—			46

Net (Loss) Income	(141		)	(59		)	19			94			(43		)	(130		)
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(11		)	(11		)

Net (Loss) Income Attributable to Controlling Interests	(141		)	(59		)	19			94			(54		)	(141		)

Preferred Stock Dividends	(39		)	—			—			—			—			(39		)
Net (Loss) Income Available to Common Stockholders	$	(180	)	$	(59	)	$	19		$	94		$	(54	)	$	(180	)

Net (Loss) Income	$	(141	)	$	(59	)	$	19		$	94		$	(43	)	$	(130	)
Total other comprehensive loss	(23		)	(42		)	(44		)	(58		)	128			(39		)
Comprehensive (loss) income	(164		)	(101		)	(25		)	36			85			(169		)
Comprehensive loss attributable to noncontrolling interests	—			—			—			—			5			5
Comprehensive (loss) income attributable to controlling interests	$	(164	)	$	(101	)	$	(25	)	$	36		$	90		$	(164	)

Condensed Consolidating Statements of Income and Comprehensive Income for the Six Months Ended June 30, 2019 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	6,084		$	624		$	(65	)	$	6,643

Operating Costs, Expenses and Other
Costs of sales	—			—			1,679			88			(42		)	1,725
Depreciation, depletion and amortization	10			—			1,026			136			—			1,172
Other operating expenses	3			—			1,508			267			(23		)	1,755
Total Operating Costs, Expenses and Other	13			—			4,213			491			(65		)	4,652

Operating (Loss) Income	(13		)	—			1,871			133			—			1,991

Other Income (Expense)
Earnings from consolidated subsidiaries	1,739			1,658			134			36			(3,567		)	—
Earnings from equity investments	—			—			353			—			—			353
Interest, net	(384		)	(5		)	(508		)	(15		)	—			(912		)
Amortization of excess cost of equity investments and other, net	(7		)	—			(8		)	(2		)	—			(17		)

Income Before Income Taxes	1,335			1,653			1,842			152			(3,567		)	1,415

Income Tax Expense	(261		)	(2		)	(42		)	(15		)	—			(320		)

Net Income	1,074			1,651			1,800			137			(3,567		)	1,095
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(21		)	(21		)
Net Income Attributable to Controlling Interests	$	1,074		$	1,651		$	1,800		$	137		$	(3,588	)	$	1,074

Net Income	$	1,074		$	1,651		$	1,800		$	137		$	(3,567	)	$	1,095
Total other comprehensive (loss) income	(118		)	(149		)	(156		)	35			269			(119		)
Comprehensive income	956			1,502			1,644			172			(3,298		)	976
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(20		)	(20		)
Comprehensive income attributable to controlling interests	$	956		$	1,502		$	1,644		$	172		$	(3,318	)	$	956

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

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Total Revenues	$	—		$	—		$	6,127		$	785		$	(66	)	$	6,846

Operating Costs, Expenses and Other
Costs of sales	—			—			2,001			129			(43		)	2,087
Depreciation, depletion and amortization	9			—			970			162			—			1,141
Other operating (income) expenses	(19		)	1			2,120			318			(23		)	2,397
Total Operating Costs, Expenses and Other	(10		)	1			5,091			609			(66		)	5,625

Operating Income (Loss)	10			(1		)	1,036			176			—			1,221

Other Income (Expense)
Earnings from consolidated subsidiaries	804			690			147			20			(1,661		)	—
Earnings from equity investments	—			—			278			—			—			278
Interest, net	(377		)	(6		)	(546		)	(54		)	—			(983		)
Amortization of excess cost of equity investments and other, net	13			—			(15		)	16			—			14

Income Before Income Taxes	450			683			900			158			(1,661		)	530

Income Tax Expense	(67		)	(4		)	(45		)	(2		)	—			(118		)

Net Income	383			679			855			156			(1,661		)	412
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(29		)	(29		)

Net Income Attributable to Controlling Interests	383			679			855			156			(1,690		)	383

Preferred Stock Dividends	(78		)	—			—			—			—			(78		)
Net Income Available to Common Stockholders	$	305		$	679		$	855		$	156		$	(1,690	)	$	305

Net Income	$	383		$	679		$	855		$	156		$	(1,661	)	$	412
Total other comprehensive loss	(40		)	(98		)	(101		)	(136		)	295			(80		)
Comprehensive income	343			581			754			20			(1,366		)	332
Comprehensive loss attributable to noncontrolling interests	—			—			—			—			11			11
Comprehensive income attributable to controlling interests	$	343		$	581		$	754		$	20		$	(1,355	)	$	343

Condensed Consolidating Balance Sheets as of June 30, 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	$	—	$	—	$	212	$	(1	)	$	213
Other current assets - affiliates	5,179		4,748		27,566		1,089		(38,582		)	—
All other current assets	101		30		1,795		184		(23		)	2,087
Property, plant and equipment, net	245		—		30,636		6,959		—			37,840
Investments	664		—		7,361		99		—			8,124
Investments in subsidiaries	44,939		41,753		4,489		4,380		(95,561		)	—
Goodwill	13,789		22		5,165		2,988		—			21,964
Notes receivable from affiliates	928		20,338		200		1,171		(22,637		)	—
Deferred income taxes	2,909		—		—		—		(1,422		)	1,487
Other non-current assets	726		224		3,925		468		(363		)	4,980
Total assets	$	69,482	$	67,115	$	81,137	$	17,550	$	(158,589	)	$	76,695

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt	$	1,636	$	1,235	$	31	$	152	$	—		$	3,054
Other current liabilities - affiliates	17,793		14,144		5,667		978		(38,582		)	—
All other current liabilities	388		343		1,545		349		(20		)	2,605
Long-term debt	13,615		15,738		3,003		649		—			33,005
Notes payable to affiliates	1,302		448		20,532		355		(22,637		)	—
Deferred income taxes	—		—		539		883		(1,422		)	—
All other long-term liabilities and deferred credits	1,110		21		1,207		801		(367		)	2,772
Total liabilities	35,844		31,929		32,524		4,167		(63,028		)	41,436

Redeemable noncontrolling interest	—		—		775		—		—			775
Stockholders’ equity
Total KMI equity	33,638		35,186		47,838		13,383		(96,407		)	33,638
Noncontrolling interests	—		—		—		—		846			846
Total stockholders’ equity	33,638		35,186		47,838		13,383		(95,561		)	34,484
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	69,482	$	67,115	$	81,137	$	17,550	$	(158,589	)	$	76,695

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

Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 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	$	(1,554	)	$	2,081		$	7,965		$	51		$	(6,445	)	$	2,098

Cash flows from investing activities
Acquisitions of assets and investments	—			—			(3		)	—			—			(3		)
Capital expenditures	(27		)	—			(874		)	(277		)	—			(1,178		)
Sales of assets and equity investments, net of working capital settlements	—			—			108			(28		)	—			80
Sales of property, plant and equipment, net of removal costs	4			—			4			(5		)	—			3
Contributions to investments	(128		)	—			(683		)	(1		)	—			(812		)
Distributions from equity investments in excess of cumulative earnings	865			—			131			—			(865		)	131
Funding to affiliates	(3,509		)	(9		)	(5,668		)	(445		)	9,631			—
Loans to related party	—			—			(16		)	—			—			(16		)
Net cash used in investing activities	(2,795		)	(9		)	(7,001		)	(756		)	8,766			(1,795		)

Cash flows from financing activities
Issuances of debt	2,966			—			—			76			—			3,042
Payments of debt	(3,263		)	(1,300		)	(4		)	(55		)	—			(4,622		)
Debt issue costs	(6		)	—			—			—			—			(6		)
Cash dividends - common shares	(1,024		)	—			—			—			—			(1,024		)
Repurchases of common shares	(2		)	—			—			—			—			(2		)
Funding from affiliates	5,676			1,731			1,781			443			(9,631		)	—
Contributions from investment partner	—			—			109			—			—			109
Contributions from parents	—			—			1			—			(1		)	—
Contributions from noncontrolling interests	—			—			—			—			1			1
Distributions to parents	—			(2,503		)	(2,851		)	(2,867		)	8,221			—
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds	—			—			—			—			(879		)	(879		)
Distributions to noncontrolling interests - other	—			—			—			—			(28		)	(28		)
Other, net	(4		)	—			—			—			—			(4		)
Net cash provided by (used in) financing activities	4,343			(2,072		)	(964		)	(2,403		)	(2,317		)	(3,413		)

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

Net decrease in Cash, Cash Equivalents and Restricted Deposits	(6		)	—			—			(3,080		)	4			(3,082		)
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		$	—		$	—		$	248		$	(1	)	$	249

Condensed Consolidating Statements of Cash Flows for the Six Months Ended June 30, 2018 (In Millions) (Unaudited)

	Parent Issuer and Guarantor			Subsidiary Issuer and Guarantor - KMP			Subsidiary Guarantors			Subsidiary Non-Guarantors			Consolidating Adjustments			Consolidated KMI
Net cash (used in) provided by operating activities	$	(2,142	)	$	2,048		$	5,644		$	519		$	(3,601	)	$	2,468

Cash flows from investing activities
Acquisitions of assets and investments	—			—			(20		)	—			—			(20		)
Capital expenditures	(16		)	—			(940		)	(517		)	—			(1,473		)
Proceeds from sales of equity investments	—			—			33			—			—			33
Sales of property, plant and equipment, net of removal costs	3			—			(6		)	9			—			6
Contributions to investments	—			—			(106		)	(5		)	—			(111		)
Distributions from equity investments in excess of cumulative earnings	1,910			—			149			—			(1,910		)	149
Funding (to) from affiliates	(4,016		)	5			(3,737		)	(489		)	8,237			—
Loans to related party	—			—			(16		)	—			—			(16		)
Net cash (used in) provided by investing activities	(2,119		)	5			(4,643		)	(1,002		)	6,327			(1,432		)

Cash flows from financing activities
Issuances of debt	8,297			—			—			268			—			8,565
Payments of debt	(6,737		)	(975		)	(779		)	(84		)	—			(8,575		)
Debt issue costs	(24		)	—			—			(7		)	—			(31		)
Cash dividends - common shares	(719		)	—			—			—			—			(719		)
Cash dividends - preferred shares	(78		)	—			—			—			—			(78		)
Repurchases of common shares	(250		)	—			—			—			—			(250		)
Funding from affiliates	3,779			1,517			2,499			442			(8,237		)	—
Contribution from investment partner	—			—			97			—			—			97
Contributions from parents	—			—			17			—			(17		)	—
Contributions from noncontrolling interests	—			—			—			—			17			17
Distributions to parents	—			(2,573		)	(2,835		)	(135		)	5,543			—
Distributions to noncontrolling interests	—			—			—			—			(35		)	(35		)
Other, net	(1		)	—			—			—			—			(1		)
Net cash provided by (used in) financing activities	4,267			(2,031		)	(1,001		)	484			(2,729		)	(1,010		)

Effect of exchange rate changes on cash, cash equivalents and restricted deposits	—			—			—			(5		)	—			(5		)

Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits	6			22			—			(4		)	(3		)	21
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3			1			—			323			(1		)	326
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	9		$	23		$	—		$	319		$	(4	)	$	347

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 first quarter of 2019, KML settled the remaining C$37 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 six months ended June 30, 2019 and for which we had substantially accrued for as of December 31, 2018.

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 and six months ended June 30, 2018 have been reclassified to conform to the current presentation in the following Management Discussion and Analysis tables. The reclassified amounts were not material.

Consolidated Earnings Results



	Three Months Ended June 30,
	2019			2018			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	1,088		$	310		$	778		251	%
Products Pipelines	307			321			(14		)	(4	)%
Terminals	290			275			15			5	%
CO₂	196			157			39			25	%
Kinder Morgan Canada(b)	—			46			(46		)	(100	)%
Total Segment EBDA(c)	1,881			1,109			772			70	%
DD&A	(579		)	(571		)	(8		)	(1	)%
Amortization of excess cost of equity investments	(19		)	(24		)	5			21	%
General and administrative and corporate charges(d)	(155		)	(174		)	19			11	%
Interest, net(e)	(452		)	(516		)	64			12	%
Income (loss) before income taxes	676			(176		)	852			484	%
Income tax (expense) benefit(f)	(148		)	46			(194		)	(422	)%
Net income (loss)	528			(130		)	658			506	%
Net income attributable to noncontrolling interests	(10		)	(11		)	1			9	%
Net income (loss) attributable to Kinder Morgan, Inc.	518			(141		)	659			467	%
Preferred stock dividends	—			(39		)	39			100	%
Net Income (Loss) Available to Common Stockholders	$	518		$	(180	)	$	698		388	%



	Six Months Ended June 30,
	2019			2018			Earnings increase/(decrease)
	(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	2,291		$	1,438		$	853		59	%
Products Pipelines	583			587			(4		)	(1	)%
Terminals	589			571			18			3	%
CO₂	394			356			38			11	%
Kinder Morgan Canada(b)	(2		)	92			(94		)	(102	)%
Total Segment EBDA(c)	3,855			3,044			811			27	%
DD&A	(1,172		)	(1,141		)	(31		)	(3	)%
Amortization of excess cost of equity investments	(40		)	(56		)	16			29	%
General and administrative and corporate charges(d)	(316		)	(334		)	18			5	%
Interest, net(e)	(912		)	(983		)	71			7	%
Income before income taxes	1,415			530			885			167	%
Income tax expense(f)	(320		)	(118		)	(202		)	(171	)%
Net income	1,095			412			683			166	%
Net income attributable to noncontrolling interests	(21		)	(29		)	8			28	%
Net income attributable to Kinder Morgan, Inc.	1,074			383			691			180	%
Preferred stock dividends	—			(78		)	78			100	%
Net Income Available to Common Stockholders	$	1,074		$	305		$	769		252	%

_______


(a)	Includes revenues, earnings from equity investments, and other, net, less operating expenses, (gain) loss on impairments and divestitures, net, and other income, net. 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 Financial Measures” below)


(c)	Three and six month 2019 amounts include net increases in earnings of $29 million and $21 million, respectively, and three and six month 2018 amounts include net decreases in earnings of $785 million and $801 million, respectively, related to the combined effect of

the certain items. The extent to which these items affect each of our business segments is discussed below in the footnotes to the tables within “—Segment Earnings Results.”


(d)	Three and six month 2019 amounts include net increases in expense of $3 million and $6 million, respectively, and three and six month 2018 amounts include net increases in expense of $14 million and $10 million, respectively, related to the combined effect of the certain items disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”

(e)

Three and six month 2019 amounts include net decreases in expense of $3 million and $1 million, respectively, and the three and six month 2018 amounts include net increases in expense of $39 million and $34 million, respectively, related to the combined effect of the certain items disclosed below in “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests.”


(f)	Three and six month 2019 amounts include net increases in expense of $5 million and $7 million, respectively, and three and six month 2018 amounts include net decreases in expense of $191 million and $194 million, respectively, related to the combined net effect of the certain items 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 an $867 million increase in income before income taxes for the second quarter of 2019, as compared to the same prior year period (representing the difference between an increase of $29 million and a decrease of $838 million in income before income taxes for the second quarter of 2019 and 2018, respectively) and an $861 million increase in income before income taxes for the six months ended June 30, 2019, as compared to the same prior year period (representing the difference between an increase of $16 million and a decrease of $845 million in income before income taxes for the six months ended June 30, 2019 and 2018, respectively).

After giving effect to these certain items, which are discussed in more detail in the discussion that follows, the remaining decrease in income before income taxes from the prior year quarter was $15 million (2%) and the remaining increase in income before income taxes from the prior year-to-date period was $24 million (2%). The quarter-to-date decrease from 2018 is primarily attributable to lower earnings from our CO₂, Terminals, and Products Pipelines business segments and lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale, partially offset by increased performance from our Natural Gas Pipelines business segment and decreased interest expense, net. The year-to-date increase from 2018 is primarily attributable to increased performance from our Natural Gas Pipelines business segment, decreased interest expense, net and decreased general and administrative expense, partially offset by lower earnings from our CO₂, Terminals, and Products Pipelines business segments, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A expense.

Non-GAAP Financial Measures

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

Our non-GAAP performance measures described below should not be considered alternatives to GAAP net income or other GAAP measures and have important limitations as analytical tools. Our computations of DCF and Segment EBDA before certain items may differ from similarly titled measures used by others. You should not consider these non-GAAP performance measures in isolation or as substitutes for an analysis of our results as reported under GAAP. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. Management compensates for the limitations of these non-GAAP performance measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

DCF

DCF is calculated by adjusting net income available to common stockholders before certain items for DD&A, total book and cash taxes, sustaining capital expenditures and other items. DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, 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 net income available to common stockholders to DCF 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 (Loss) Available to Common Stockholders to DCF



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except per share amounts)
Net Income (Loss) Available to Common Stockholders	$	518		$	(180	)	$	1,074		$	305
Add/(Subtract):
Certain items before book tax(a)	(29		)	838			(16		)	889
Noncontrolling interest certain items(b)	(1		)	(8		)	(1		)	(8		)
Book tax certain items(c)	5			(191		)	7			(194		)
Impact of 2017 Tax Reform(d)	—			—			—			(44		)
Total certain items	(25		)	639			(10		)	643

Net Income Available to Common Stockholders before certain items	493			459			1,064			948
Add/(Subtract):
DD&A expense(e)	691			684			1,399			1,374
Total book taxes(f)	162			159			357			343
Cash taxes(g)	(51		)	(33		)	(64		)	(46		)
Other items(h)	22			11			47			22
Sustaining capital expenditures(i)	(189		)	(163		)	(304		)	(277		)
DCF	$	1,128		$	1,117		$	2,499		$	2,364

Weighted average common shares outstanding for dividends(j)	2,275			2,214			2,275			2,216
DCF per common share	$	0.50		$	0.50		$	1.10		$	1.07
Declared dividends per common share	$	0.25		$	0.20		$	0.50		$	0.40

_______


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


(b)	Represents noncontrolling interests associated with certain items.


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


(d)	Six month 2018 amount primarily relates to our share of certain equity investees’ 2017 Tax Reform provisional adjustments and 2017 Tax Reform adjustments related to our FERC-regulated business.

(e)

Includes DD&A and amortization of excess cost of equity investments. Three and six month 2019 amounts also include $93 million and $187 million, respectively, and three and six month 2018 amounts also include $89 million and $177 million, respectively, of our share of certain equity investees’ DD&A, net of the noncontrolling interests’ portion of KML DD&A and consolidating joint venture partners’ share of DD&A.


(f)	Excludes book tax certain items. Three and six month 2019 amounts also include $19 million and $44 million, respectively, and three and six month 2018 amounts also include $14 million and $31 million, respectively, of our share of taxable equity investees’ book taxes, net of the noncontrolling interests’ portion of KML book taxes.


(g)	Three and six month 2019 amounts also include $(34) million for both periods and three and six month 2018 amounts also include $(28) million and $(38) million, respectively, of our share of taxable equity investees’ cash taxes.


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


(i)	Three and six month 2019 amounts include $(31) million and $(50) million, respectively, and three and six month 2018 amounts include $(24) million and $(40) million, respectively, of our share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.


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

Segment EBDA Before Certain Items

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

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

Segment Earnings Results

Natural Gas Pipelines



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	1,968		$	2,107		$	4,169		$	4,233
Operating expenses	(1,030		)	(1,245		)	(2,197		)	(2,446		)
Gain (loss) on impairments and divestitures, net	10			(599		)	10			(599		)
Other income	1			1			2			1
Earnings from equity investments	131			29			290			216
Other, net	8			17			17			33
Segment EBDA	1,088			310			2,291			1,438
Certain items(a)(b)	(17		)	688			(19)			634
Segment EBDA before certain items	$	1,071		$	998		$	2,272		$	2,072

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(144	)	(7		)%	$	(55	)	(1		)%
Segment EBDA before certain items	$	73		7		%	$	200		10		%

Volumetric data
Transport volumes (BBtu/d)(c)	34,790			31,704			35,413			31,913
Sales volumes (BBtu/d)(c)	2,323			2,445			2,327			2,468
Gathering volumes (BBtu/d)(c)	3,323			2,871			3,312			2,801
NGLs (MBbl/d)(c)	128			121			124			119

_______

Certain items affecting Segment EBDA

(a)

Includes revenue certain item amounts of $(8) million for the three months ended June 30, 2019 and $(3) million and $(9) million for the three and six months ended June 30, 2018, respectively. Certain item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas, NGL and crude oil sales in the 2019 and 2018 periods, and additionally in the 2018 periods, to a transportation contract refund and the early termination of a long-term natural gas transportation contract.

(b)

Includes non-revenue certain item amounts of $(9) million and $(19) million for the three and six months ended June 30, 2019, respectively, and $691 million and $643 million for the three and six months ended June 30, 2018, respectively. 2018 certain item amounts primarily related to (i) a $600 million non-cash loss on impairment of certain gathering and processing assets in Oklahoma; (ii) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset by our share of earnings recognized by Gulf LNG on the respective customer contract; and (iii) an increase in earnings of $44 million (six month 2018 period) for our share of certain equity investees’ 2017 Tax Reform provisional adjustments and 2017 Tax Reform adjustments related to our FERC-regulated business.

Other


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

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2019 and 2018:

Three Months Ended June 30, 2019 versus Three Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
West Region	$	28		12	%	$	29		10	%
North Region	26			8	%	42			11	%
Midstream	18			6	%	(220		)	(17	)%
South Region	(1		)	(1	)%	3			4	%
Other	2			200	%	2			200	%
Total Natural Gas Pipelines	$	73		7	%	$	(144	)	(7	)%

Six Months Ended June 30, 2019 versus Six Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
West Region	$	64		13	%	$	61		10	%
North Region	83			13	%	84			10	%
Midstream	52			9	%	(205		)	(8	)%
South Region	(3		)	(1	)%	7			4	%
Other	4			133	%	4			133	%
Intrasegment eliminations	—			—	%	(6		)	(43	)%
Total Natural Gas Pipelines	$	200		10	%	$	(55	)	(1	)%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2019 and 2018:

•

West Region’s increases of $28 million (12%) and $64 million (13%), respectively, were primarily due to increases in earnings from EPNG and CIG. The increase on EPNG was the result of capacity sales and usage due to increased activity in the Permian Basin as well as an increase in utilization of storage facilities, partially offset by the negative impact of EPNG’s 501-G rate settlement. Increased earnings on CIG were due to capacity sales and usage resulting from increased activity in the Denver Julesburg basin;

•

North Region’s increases of $26 million (8%) and $83 million (13%), respectively, were the result of an increase in earnings from TGP and Kinder Morgan Louisiana Pipeline LLC (KMLP). The increase on TGP was driven by expansion projects placed into service in 2018 and higher capacity sales in 2019, slightly offset by lower usage revenues and higher operations and maintenance expense. Increased earnings at KMLP were driven by revenues from the Sabine Pass expansion project that was placed into service in December 2018; and

•

Midstream’s increases of $18 million (6%) and $52 million (9%), respectively, were primarily due to increased earnings from KinderHawk Field Services LLC, South Texas Midstream, Cochin pipeline and Texas intrastate natural gas pipeline operations partially offset by decreased earnings from Hiland Midstream. KinderHawk Field Services LLC and South Texas Midstream benefited from increased drilling and production in the Haynesville and Eagle Ford basins, respectively. Cochin pipeline’s increased earnings was primarily driven by higher volumes and higher tariff rates. Texas intrastate natural gas operations were favorably impacted by higher sales margins partially offset by lower storage margins. Hiland Midstream’s decreased earnings was primarily due to lower commodity prices and higher operations and maintenance expense. Overall Midstream’s revenues decreased primarily due to lower commodity prices which was largely offset by corresponding decreases in costs of sales.

Products Pipelines



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	442		$	503		$	866		$	945
Operating expenses	(157		)	(199		)	(323		)	(392		)
Other income	—			2			—			2
Earnings from equity investments	17			16			35			32
Other, net	5			(1		)	5			—
Segment EBDA	307			321			583			587
Certain items(a)	—			(1		)	17			30
Segment EBDA before certain items	$	307		$	320		$	600		$	617

Change from prior period	Increase/(Decrease)
Revenues	$	(61	)	(12		)%	$	(79	)	(8		)%
Segment EBDA before certain items	$	(13	)	(4		)%	$	(17	)	(3		)%

Volumetric data
Gasoline(b)	1,090			1,083			1,035			1,031
Diesel fuel	379			384			358			363
Jet fuel	303			305			298			297
Total refined product volumes(c)	1,772			1,772			1,691			1,691
Crude and condensate(c)	651			639			647			616
Total delivery volumes (MBbl/d)	2,423			2,411			2,338			2,307

_______

Certain items affecting Segment EBDA


(a)	Includes non-revenue certain item amounts of $17 million for the six months ended June 30, 2019 and $(1) million and $30 million for the three and six months ended June 30, 2018, respectively, primarily related to an adjustment of tax reserves, other than income taxes (six month 2019 period) and a Pacific operations litigation matter (six month 2018 period).

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 and six month periods ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019 versus Three Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Crude & Condensate	$	(10	)	(8	)%	$	(44	)	(20	)%
West Coast Refined Products	(7		)	(5	)%	1			1	%
Southeast Refined Products	4			6	%	(18		)	(17	)%
Total Products Pipelines	$	(13	)	(4	)%	$	(61	)	(12	)%

Six Months Ended June 30, 2019 versus Six Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Crude & Condensate	$	(18	)	(7	)%	$	(67	)	(17	)%
West Coast Refined Products	(7		)	(3	)%	7			2	%
Southeast Refined Products	8			6	%	(19		)	(9	)%
Total Products Pipelines	$	(17	)	(3	)%	$	(79	)	(8	)%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2019 and 2018:

•

Crude & Condensate’s decreases of $10 million (8%) and $18 million (7%), respectively, were 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 and a decrease in recognition of deficiency revenue, and to a lesser extent contributions from Kinder Morgan Condensate Processing Facility and Double Eagle Pipeline;


•	West Coast Refined Products’ decreases of $7 million (5%) and $7 million (3%), respectively, were primarily due to an increase in environmental reserves on Pacific operations; and

•

Southeast Refined Products’ increases of $4 million (6%) and $8 million (6%), respectively, were primarily due to increased earnings from South East Terminals driven primarily by a gain recognized from an exchange of joint venture interests, and to a lesser extent, contributions from Central Florida Pipeline. The year-to-date increase was also impacted by increased equity earnings from Plantation Pipe Line as a result of increased transportation revenues driven by higher volumes and average tariff rate. Overall Southeast Refined Products’ revenues decreased primarily due to lower sales volumes as a result of a Transmix facility temporary shutdown in second quarter 2019 which was largely offset by corresponding decreases in costs of sales.

Terminals



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	507		$	515		$	1,016		$	1,010
Operating expenses	(221		)	(191		)	(437		)	(398		)
Loss on impairments and divestitures, net	—			(54		)	—			(54		)
Earnings from equity investments	4			5			9			12
Other, net	—			—			1			1
Segment EBDA	290			275			589			571
Certain items(a)(b)	—			34			—			35
Segment EBDA before certain items	$	290		$	309		$	589		$	606

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(7	)	(1		)%	$	8		1		%
Segment EBDA before certain items	$	(19	)	(6		)%	$	(17	)	(3		)%

Volumetric data
Liquids tankage capacity available for service (MMBbl)	88.9			87.7			88.9			87.7
Liquids utilization %(c)	93.3		%	93.0		%	93.3		%	93.0		%
Bulk transload tonnage (MMtons)	15.1			16.9			29.8			31.3

_______

Certain items affecting Segment EBDA


(a)	Includes revenue certain item amounts of $(1) million and $(2) million for the three and six months ended June 30, 2018, respectively.


(b)	Includes non-revenue certain item amounts of $35 million and $37 million for the three and six months ended June 30, 2018, respectively, primarily related to losses on impairments and divestitures, net and hurricane damage insurance recoveries, net of 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 and six month periods ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019 versus Three Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(6	)	(16	)%	$	3		7	%
Marine Operations	(6		)	(12	)%	(3		)	(3	)%
Gulf Central	(4		)	(24	)%	(5		)	(19	)%
Midwest	(4		)	(17	)%	(3		)	(7	)%
Gulf Liquids	4			5	%	4			4	%
All others (including intrasegment eliminations)	(3		)	(3	)%	(3		)	(1	)%
Total Terminals	$	(19	)	(6	)%	$	(7	)	(1	)%

Six Months Ended June 30, 2019 versus Six Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(11	)	(14	)%	$	9		10	%
Marine Operations	(3		)	(3	)%	—			—	%
Gulf Central	(7		)	(21	)%	(7		)	(13	)%
Midwest	(2		)	(5	)%	1			1	%
Gulf Liquids	10			7	%	11			5	%
All others (including intrasegment eliminations)	(4		)	(2	)%	(6		)	(1	)%
Total Terminals	$	(17	)	(3	)%	$	8		1	%

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2019 and 2018:


•	decreases of $6 million (16%) and $11 million (14%), respectively, 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;


•	decreases of $6 million (12%) and $3 million (3%), respectively, from our Marine Operations primarily due to scheduled dry dock days and unscheduled off-hire time for and repairs to certain of our Jones Act tankers due to historically high water levels on the Mississippi River, partially offset by higher charter rates;


•	decreases of $4 million (24%) and $7 million (21%), respectively, from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018 and an unfavorable impact resulting from certain tanks being temporarily out of service for scheduled inspections and repairs;


•	decreases of $4 million (17%) and $2 million (5%), respectively, from our Midwest terminals primarily related to the historically high water levels on the Mississippi River which resulted in reduced volumes from service disruptions in the second quarter of 2019; and


•	increases of $4 million (5%) and $10 million (7%), respectively, from our Gulf Liquids terminals primarily driven by higher volumes and associated ancillary fees as well as annual rate escalations on existing storage contracts. The year-to-date increase was also impacted by a customer rebate adversely impacting revenue recognized in the prior comparable period.

CO2



	Three Months Ended June 30,						Six Months Ended June 30,
	2019			2018			2019			2018
	(In millions, except operating statistics)
Revenues	$	310		$	250		$	615		$	554
Operating expenses	(123		)	(101		)	(240		)	(216		)
Earnings from equity investments	9			8			19			18
Segment EBDA	196			157			394			356
Certain items(a)(b)	(12		)	64			(21		)	102
Segment EBDA before certain items	$	184		$	221		$	373		$	458

Change from prior period	Increase/(Decrease)
Revenues before certain items	$	(37	)	(11		)%	$	(83	)	(12		)%
Segment EBDA before certain items	$	(37	)	(17		)%	$	(85	)	(19		)%

Volumetric data
SACROC oil production	24.4			24.3			24.4			24.4
Yates oil production	7.3			7.4			7.3			7.6
Katz and Goldsmith oil production	3.8			4.7			4.0			5.0
Tall Cotton oil production	2.4			2.2			2.5			2.1
Total oil production, net (MBbl/d)(c)	37.9			38.6			38.2			39.1
NGL sales volumes, net (MBbl/d)(c)	10.4			10.1			10.2			10.1
CO₂ production, net (Bcf/d)	0.6			0.6			0.6			0.6
Realized weighted-average oil price per Bbl(d)	$	49.95		$	58.08		$	49.31		$	58.90
Realized weighted-average NGL price per Bbl(e)	$	23.58		$	32.88		$	24.75		$	31.64

_______

Certain items affecting Segment EBDA


(a)	Includes revenue certain item amounts of $(12) million and $(21) million for the three and six months ended June 30, 2019, respectively, and $85 million and $123 million for the three and six months ended June 30, 2018, respectively. Certain item amounts are primarily related to unrealized gains and losses associated with derivative contracts used to hedge forecasted commodity sales.


(b)	Includes non-revenue certain item amounts of $(21) million for both the three and six months ended June 30, 2018 as a result of a severance tax refund.

Other


(c)	Net after royalties and outside working interests.


(d)	Includes all crude oil production properties.


(e)	Includes all NGL sales.

Below are the changes in both Segment EBDA before certain items and revenues before certain items, in the comparable three and six month periods ended June 30, 2019 and 2018.

Three Months Ended June 30, 2019 versus Three Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	(40	)	(27	)%	$	(44	)	(18	)%
Source and Transportation Activities	3			4	%	6			6	%
Intrasegment eliminations	—			—	%	1			14	%
Total CO2	$	(37	)	(17	)%	$	(37	)	(11	)%

Six Months Ended June 30, 2019 versus Six Months Ended June 30, 2018



	Segment EBDA before certain items increase/(decrease)					Revenues before certain items increase/(decrease)
	(In millions, except percentages)
Oil and Gas Producing Activities	$	(91	)	(29	)%	$	(95	)	(19	)%
Source and Transportation Activities	6			4	%	9			5	%
Intrasegment eliminations	—			—	%	3			19	%
Total CO2	$	(85	)	(19	)%	$	(83	)	(12	)%

The changes in Segment EBDA for our CO₂ business segment are further explained by the following discussion of the significant factors driving Segment EBDA before certain items in the comparable three and six month periods ended June 30, 2019 and 2018:

•

decreases of $40 million (27%) and $91 million (29%), respectively, from our Oil and Gas Producing activities primarily due to decreased revenues of $44 million and $95 million, respectively, driven by lower realized crude oil and NGL prices which reduced revenues by $41 million and $85 million, respectively, and lower volumes which reduced revenues by $3 million and $10 million, respectively and higher severance tax expense for both periods of $1 million partially offset by lower operating expenses of $5 million for both periods; and

•

increases of $3 million (4%) and $6 million (4%), respectively, from our Source and Transportation activities primarily due to higher CO₂sales of $5 million and $8 million, respectively, driven by higher volumes of $8 million and $11 million, respectively, partially offset by lower contract sales prices of $3 million for both periods and $1 million increased earnings from an equity investee for both periods partially offset by higher operating expenses and Ad Valorem tax expense of $3 million for both periods.

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



	Three Months Ended June 30,
	2019			2018			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	155		$	174		$	(19	)	(11	)%
Certain items(a)	(3		)	(14		)	11			79	%
General and administrative and corporate charges before certain items(a)	$	152		$	160		$	(8	)	(5	)%

Interest, net(b)	$	452		$	516		$	(64	)	(12	)%
Certain items(b)	3			(39		)	42			108	%
Interest, net, before certain items(b)	$	455		$	477		$	(22	)	(5	)%

Net income attributable to noncontrolling interests	$	10		$	11		$	(1	)	(9	)%
Noncontrolling interests associated with certain items	1			8			(7		)	(88	)%
Net income attributable to noncontrolling interests before certain items	$	11		$	19		$	(8	)	(42	)%



	Six Months Ended June 30,
	2019			2018			Increase/(decrease)
	(In millions, except percentages)
General and administrative and corporate charges(a)	$	316		$	334		$	(18	)	(5	)%
Certain items(a)	(6		)	(10		)	4			40	%
General and administrative and corporate charges before certain items(a)	$	310		$	324		$	(14	)	(4	)%

Interest, net(b)	$	912		$	983		$	(71	)	(7	)%
Certain items(b)	1			(34		)	35			103	%
Interest, net, before certain items(b)	$	913		$	949		$	(36	)	(4	)%

Net income attributable to noncontrolling interests	$	21		$	29		$	(8	)	(28	)%
Noncontrolling interests associated with certain items	1			8			(7		)	(88	)%
Net income attributable to noncontrolling interests before certain items	$	22		$	37		$	(15	)	(41	)%

Certain items

(a)

Three and six month 2018 amounts include increases in expense of (i) $10 million for both periods associated with an environmental reserve adjustment; (ii) $1 million and $7 million, respectively, related to certain corporate litigation matters; and (iii) $2 million for both periods of asset sale related costs. Six month 2018 amount also includes a decrease in expense of $12 million related to an adjustment of tax reserves, other than income taxes.

(b)

Three and six month 2019 amounts include (i) decreases in interest expense of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with historical acquisitions; and (ii) increases in expense of $3 million and $13 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and hedged debt. Three and six month 2018 amounts include (i) decreases in interest expense of $8 million and $18 million, respectively, related to non-cash debt fair value adjustments associated with historical acquisitions; (ii) increases in expense of $3 million and $8 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and hedged debt; and (iii) increases in interest expense of $46 million for both periods related to the write-off of capitalized KML credit facility fees.

The decreases in general and administrative expenses and corporate charges before certain items of $8 million and $14 million for the three and six months ended June 30, 2019, respectively, when compared with the respective prior year periods were primarily due to higher capitalized costs of $13 million and $31 million, respectively, driven by our large Permian basin pipeline projects and lower expenses of $7 million and $14 million, respectively, due to the sale of TMPL, partially offset by higher pension and benefit-related costs of $15 million and $32 million, respectively.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense net of interest income before certain items for the three and six months ended June 30, 2019 when compared with the respective prior year periods decreased $22 million and $36 million, respectively. The decreases in interest expense were primarily due to lower average debt balances, partially offset by higher LIBOR rates which impacted our interest rate swap agreements. The year-to-date decrease in interest expense was also impacted by lower weighted average long-term debt interest rates.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of June 30, 2019 and December 31, 2018, approximately 30% and 31%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us. Net income attributable to noncontrolling interests before certain items for the three and six months ended June 30, 2019 when compared with the respective prior year periods decreased $8 million and $15 million, respectively, primarily due to the TMPL Sale.

Income Taxes

Our tax expense (benefit) for the three months ended June 30, 2019 was approximately $148 million as compared with $(46) million for the same period of 2018. The $194 million increase in tax expense was primarily due to an increase in pre-tax earnings.

Our tax expense for the six months ended June 30, 2019 was approximately $320 million as compared with $118 million for the same period of 2018. The $202 million increase in tax expense was primarily due to an increase in pre-tax earnings.

Liquidity and Capital Resources

General

As of June 30, 2019, we had $213 million of “Cash and cash equivalents,” a decrease of $3,067 million (94%) 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 $2,098 million and $2,468 million in the first six 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 growth projects for the foreseeable future.

Short-term Liquidity

As of June 30, 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 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 facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of June 30, 2019, our $3,054 million of short-term debt consisted primarily of (i) $2,735 million of senior notes that mature in the next twelve months; (ii) $136 million outstanding under our $4.0 billion commercial paper program; and (iii) $27 million outstanding borrowings under KML’s C$500 million revolving credit facility. As it becomes due, we intend to fund our short-term debt primarily through credit facility borrowings, commercial paper borrowings, and/or issuing new long-term debt. 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 $3,359 million and $1,835 million as of June 30, 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 cash from operations. The overall $1,524 million (83%) unfavorable change from year-end 2018 was primarily due to a decrease in cash and cash equivalents of $3,067 million partially offset by a decrease in short-term debt and distributions payable of $1,210 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 six months ended June 30, 2019, and the amount we expect to spend for the remainder of 2019 to sustain and grow our businesses are as follows:



	Six Months Ended June 30, 2019		2019 Remaining		Total 2019
	(In millions)
Sustaining capital expenditures(a)(b)	$	304	$	403	$	707
KMI Discretionary capital investments(b)(c)(d)	$	1,380	$	1,453	$	2,833
KML Discretionary capital investments(b)	$	8	$	19	$	27

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(a)	Six months ended June 30, 2019, 2019 Remaining, and Total 2019 amounts include $50 million, $75 million, and $125 million, respectively, for our proportionate share of (i) certain equity investees’; (ii) KML’s; and (iii) certain consolidating joint venture subsidiaries’ sustaining capital expenditures.


(b)	Six months ended June 30, 2019 amounts exclude $184 million of net changes from accrued capital expenditures, contractor retainage, and other.


(c)	Six months ended June 30, 2019 amount includes $648 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 below, there have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2018 in our 2018 Form 10-K.

Commitments for the purchase of property, plant and equipment as of June 30, 2019 and December 31, 2018 were $452 million and $304 million, respectively. The increase of $148 million was primarily driven by capital commitments related to our Natural Gas Pipelines business segment.

Cash Flows

Operating Activities

The net decrease of $370 million in cash provided by operating activities for the six months ended June 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	$370 million of income tax payments made in the 2019 period primarily for foreign income tax associated with the TMPL Sale.

Investing Activities

The $363 million net increase in cash used in investing activities for the six months ended June 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	a $701 million increase in cash used for contributions to equity investments driven by higher contributions we made to Gulf Coast Express Pipeline LLC, Permian Highway Pipeline LLC, Citrus Corporation and Fayetteville Express Pipeline LLC in the 2019 period compared with the 2018 period; partially offset by,


•	a $295 million decrease in capital expenditures in the 2019 period over the comparative 2018 period primarily due to no expenditures in 2019 for our Kinder Morgan Canada business segment due to the TMPL Sale and lower expenditures in our Terminals and CO₂ business segments.

Financing Activities

The net increase of $2,403 million in cash used in financing activities for the six months ended June 30, 2019 compared to the respective 2018 period was primarily attributable to:


•	a $1,545 million net increase in cash used related to debt activity as a result of higher net debt payments in the 2019 period compared to 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; and


•	a $305 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 $78 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.

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
June 30, 2019	0.25		July 17, 2019	July 31, 2019	August 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 July 16, 2019, KML’s board of directors declared a dividend for the quarterly period ended June 30, 2019 of C$0.1625 per restricted voting share, payable on August 15, 2019 to KML restricted voting shareholders of record as of the close of business on July 31, 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.

LIBOR is used as a reference rate for certain of our financial instruments, such as our revolving credit facilities and the interest rate swap agreements that we use to hedge our interest rate exposure. LIBOR is set to be phased out at the end of 2021. We are currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.

Item 4. Controls and Procedures.

As of June 30, 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 June 30, 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.

None.

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 June 30, 2019.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number Description

10.1			Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2019.

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 formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the three and six months ended June 30, 2019 and 2018; (ii) our Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2019 and 2018; (iii) our Consolidated Balance Sheets as of June 30, 2019 and December 31, 2018; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2019 and 2018; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 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.

SIGNATURE

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



	KINDER MORGAN, INC.
		Registrant



Date:	July 19, 2019	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

Kinder Morgan - 10-Q quarterly report FY2019 Q2

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