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 ~~September 30, 2019~~March 31, 2020

☐ 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 ~~October 17, 2019,~~April 27, 2020, the registrant had ~~2,264,965,437~~2,261,487,090 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~~Operations - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~		4
	Consolidated Statements of Comprehensive (Loss) Income - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~		5
	Consolidated Balance Sheets - ~~September 30, 2019~~as of March 31, 2020 and December 31, ~~2018~~2019		6
	Consolidated Statements of Cash Flows - ~~Nine~~Three Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~		7
	Consolidated Statements of Stockholders’ Equity - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~		9
	Notes to Consolidated Financial Statements		10
	Note 1	General	10
	Note 2	Impairments	11
	Note 3	Debt	13
	Note 4	Stockholders’ Equity	14
	Note 5	Risk Management	15
	Note 6	Revenue Recognition	20
	Note 7	Reportable Segments	21
	Note 8	Income Taxes	22
	Note 9	Litigation, Environmental and Other Contingencies	23
	Note 10	Recent Accounting Pronouncements	28
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		4429
	Results of Operations		4531
	Overview		4531
	Consolidated Earnings Results (GAAP)		4733
	Non-GAAP ~~Performance~~Financial Measures		5034
	Segment Earnings Results		5338
	General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		6042
	Income Taxes		6243
	Liquidity and Capital Resources		6243
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		46
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		6547

Item 4.	Controls and Procedures		6647

	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		6648

Item 1A.	Risk Factors		6648

Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		6652

Item 3.	Defaults Upon Senior Securities		6652

Item 4.	Mine Safety Disclosures		6652

Item 5.	Other Information		6652

Item 6.	Exhibits		6753

	Signature		6854

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

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

Common Industry and Other Terms
~~2017 Tax Reform~~/d	=	~~The Tax Cuts & Jobs Act of 2017~~per day	EPA	=	U.S. Environmental Protection Agency
BBtu	=	billion British Thermal Units	FASB	=	Financial Accounting Standards Board
/dBcf	=	~~per day~~billion cubic feet	FERC	=	Federal Energy Regulatory Commission
~~BBtu~~	=	~~billion British Thermal Units~~	~~GAAP~~	=	~~U.S. Generally Accepted Accounting Principles~~
~~Bcf~~	=	~~billion cubic feet~~	~~LLC~~	=	~~limited liability company~~
CERCLA	=	Comprehensive Environmental Response, Compensation and Liability Act	~~MBbl~~GAAP	=	~~thousand barrels~~U.S. Generally Accepted Accounting Principles
CERCLA	=		~~MMBbl~~LLC	=	~~million barrels~~
C$	=	~~Canadian dollars~~	~~MMtons~~	=	~~million tons~~limited liability company
CO₂	=	carbon dioxide or our CO₂ business segment	~~NGL~~LIBOR	=	~~natural gas liquids~~London Interbank Offered Rate
COVID-19	=	Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn	MBbl	=	thousand barrels
COVID-19	=		MMBbl	=	million barrels
DCF	=	distributable cash flow	~~NYMEX~~MMtons	=	~~New York Mercantile Exchange~~million tons
DD&A	=	depreciation, depletion and amortization	~~OTC~~NGL	=	~~over-the-counter~~natural gas liquids
EBDA	=	earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	~~ROU~~NYMEX	=	~~right of use~~New York Mercantile Exchange
EBDA	=		~~U.S.~~OTC	=	~~United States of America~~over-the-counter
EBITDA	=	earnings before interest, income taxes, depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments	ROU	=	Right-of-Use
EBITDA	=		U.S.	=	United States of America
			WTI	=	West Texas Intermediate


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

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.

Forward-looking statements in this report include statements, express or implied, concerning, without limitation: the long-term demand for our assets and services, the future impact on our business of the global economic consequences of the COVID-19 pandemic, our expected 2020 outlook including, our expected DCF, Adjusted EBITDA, expected Net Debt-to-Adjusted EBITDA ratio and the sensitivity to changes in commodity volume and price assumptions.

~~See~~The impacts of COVID-19 and decreases in commodity prices resulting from oversupply and demand weakness are discussed in further detail in Part I, Item 1. “Financial Statements (Unaudited)—Note 1 General—COVID-19;” Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition of Operations—General and Basis of Presentation—COVID-19” and “—2020 Outlook;” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk;” and Part II, Item 1A. “Risk Factors.” In addition to the preceding factors, “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~~2019 (2019 Form 10-K) ~~for~~contain a more detailed description of other factors that may affect the forward-looking ~~statements.~~ statements and should be referenced, except to the extent such other factors are modified or superseded by the descriptions in this report.

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~~disclaim any obligation, other than as required by applicable law, to ~~provide updates~~publicly update or revise any of our forward-looking statements to ~~projections included in this report when we believe previously disclosed projections no longer have a reasonable basis.~~reflect future events or developments.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

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

	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Revenues
Services	$	2,008		$	1,959		$	6,055		$	5,910		$	1,992		$	2,037
Natural gas sales	629			799			2,012			2,353
Product sales and other	577			759			1,790			2,100
Commodity sales													1,067			1,349
Other													47			43
Total Revenues	3,214			3,517			9,857			10,363			3,106			3,429
Operating Costs, Expenses and Other
Costs of sales	762			1,135			2,487			3,222			663			948
Operations and maintenance	668			646			1,912			1,882			620			598
Depreciation, depletion and amortization	578			569			1,750			1,710			565			593
General and administrative	154			154			456			491			153			154
Taxes, other than income taxes	103			86			324			259			92			118
(Gain) loss on divestitures and impairments, net	(3		)	(588		)	(13		)	65
Other expense (income), net	1			—			(1		)	(2		)
Loss on impairments and divestitures, net (Note 2)													971			—
Other income, net													(1		)	—
Total Operating Costs, Expenses and Other	2,263			2,002			6,915			7,627			3,063			2,411
Operating Income	951			1,515			2,942			2,736			43			1,018
Other Income (Expense)
Earnings from equity investments	173			160			526			438			192			192
Amortization of excess cost of equity investments	(21		)	(21		)	(61		)	(77		)	(32		)	(21		)
Interest, net	(447		)	(473		)	(1,359		)	(1,456		)	(436		)	(460		)
Other, net	12			20			35			90			2			10
Total Other Expense	(283		)	(314		)	(859		)	(1,005		)	(274		)	(279		)
Income Before Income Taxes	668			1,201			2,083			1,731
(Loss) Income Before Income Taxes													(231		)	739
Income Tax Expense	(151		)	(196		)	(471		)	(314		)	(60		)	(172		)
Net Income	517			1,005			1,612			1,417
Net (Loss) Income													(291		)	567
Net Income Attributable to Noncontrolling Interests	(11		)	(273		)	(32		)	(302		)	(15		)	(11		)
Net Income Attributable to Kinder Morgan, Inc.	506			732			1,580			1,115
Preferred Stock Dividends	—			(39		)	—			(117		)
Net Income Available to Common Stockholders	$	506		$	693		$	1,580		$	998
Net (Loss) Income Attributable to Kinder Morgan, Inc.													$	(306	)	$	556

Class P Shares
Basic and Diluted Earnings Per Common Share	$	0.22		$	0.31		$	0.69		$	0.45
Basic and Diluted (Loss) Earnings Per Common Share													$	(0.14	)	$	0.24
Basic and Diluted Weighted Average Common Shares Outstanding	2,264			2,205			2,263			2,205			2,264			2,262

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS) INCOME

(In Millions, Unaudited)

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
Net income $ 517
$ 1,005
$ 1,612
$ 1,417
Other comprehensive income (loss), net of tax

Change in fair value of hedge derivatives (net of tax (expense) benefit of $(6), $26, $39 and $39, respectively) 20
(87 ) (132 ) (133 )
Reclassification of change in fair value of derivatives to net income (net of tax expense of $13, $4, $11 and $23, respectively) 40
11
35
78
Foreign currency translation adjustments (net of tax benefit (expense) of $2, $(49), $(5) and $(28), respectively) (7 ) 300
16
187
Benefit plan adjustments (net of tax expense of $3, $21, $8 and $25, respectively) 8
37
23
49
Total other comprehensive income (loss) 61
261
(58 ) 181
Comprehensive income 578
1,266
1,554
1,598
Comprehensive income attributable to noncontrolling interests (8 ) (339 ) (28 ) (328 )
Comprehensive income attributable to Kinder Morgan, Inc. $ 570
$ 927
$ 1,526
$ 1,270



	Three Months Ended March 31,
	2020			2019
Net (loss) income	$	(291	)	$	567
Other comprehensive income (loss), net of tax
Change in fair value of hedge derivatives (net of tax (expense) benefit of $(67) and $64, respectively)	222			(215		)
Reclassification of change in fair value of derivatives to net income (net of tax expense of $11 and $4, respectively)	37			13
Foreign currency translation adjustments (net of tax expense of $- and $5, respectively)	1			10
Benefit plan adjustments (net of tax expense of $3 and $2, respectively)	11			8
Total other comprehensive income (loss)	271			(184		)
Comprehensive (loss) income	(20		)	383
Comprehensive income attributable to noncontrolling interests	(15		)	(5		)
Comprehensive (loss) income attributable to Kinder Morgan, Inc.	$	(35	)	$	378

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

	September 30, 2019			December 31, 2018			March 31, 2020			December 31, 2019
ASSETS
Current Assets
Cash and cash equivalents	$	241		$	3,280		$	360		$	185
Restricted deposits	27			51			582			24
Accounts receivable, net	1,273			1,498
Marketable securities at fair value							—			925
Accounts receivable							1,186			1,379
Fair value of derivative contracts	144			260			448			84
Inventories	405			385			307			371
Other current assets	275			248			213			270
Total current assets	2,365			5,722			3,096			3,238
Property, plant and equipment, net	37,934			37,897			36,041			36,419
Investments	8,387			7,481			7,886			7,759
Goodwill	21,964			21,965			20,851			21,451
Other intangibles, net	2,729			2,880			2,616			2,676
Deferred income taxes	1,324			1,566			845			857
Deferred charges and other assets	2,228			1,355			2,195			1,757
Total Assets	$	76,931		$	78,866		$	73,530		$	74,157
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	4,406		$	3,388		$	3,540		$	2,477
Accounts payable	916			1,337			752			914
Distributions payable to KML noncontrolling interests	—			876
Accrued interest	360			579			337			548
Accrued taxes	384			483			295			364
Other current liabilities	760			894			684			797
Total current liabilities	6,826			7,557			5,608			5,100
Long-term liabilities and deferred credits
Long-term debt
Outstanding	30,849			33,105			29,955			30,883
Preferred interest in general partner of KMP	100			100
Debt fair value adjustments	1,162			731			1,450			1,032
Total long-term debt	32,111			33,936			31,405			31,915
Other long-term liabilities and deferred credits	2,719			2,176			2,260			2,253
Total long-term liabilities and deferred credits	34,830			36,112			33,665			34,168
Total Liabilities	41,656			43,669			39,273			39,268
Commitments and contingencies (Notes 3, 10 and 11)
Commitments and contingencies (Notes 3 and 9)
Redeemable Noncontrolling Interest	801			666			793			803
Stockholders’ Equity
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,908,090 and 2,262,165,783 shares, respectively, issued and outstanding	23			23
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,261,425,938 and 2,264,936,054 shares, respectively, issued and outstanding							23			23
Additional paid-in capital	41,727			41,701			41,713			41,745
Retained deficit	(7,733		)	(7,716		)
Accumulated deficit							(8,568		)	(7,693		)
Accumulated other comprehensive loss	(384		)	(330		)	(62		)	(333		)
Total Kinder Morgan, Inc.’s stockholders’ equity	33,633			33,678			33,106			33,742
Noncontrolling interests	841			853			358			344
Total Stockholders’ Equity	34,474			34,531			33,464			34,086
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	76,931		$	78,866		$	73,530		$	74,157

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

	Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2020			2019
Cash Flows From Operating Activities
Net income	$	1,612		$	1,417
Adjustments to reconcile net income to net cash provided by operating activities
Net (loss) income							$	(291	)	$	567
Adjustments to reconcile net (loss) income to net cash provided by operating activities
Depreciation, depletion and amortization	1,750			1,710			565			593
Deferred income taxes	254			144			(69		)	(31		)
Amortization of excess cost of equity investments	61			77			32			21
Change in fair market value of derivative contracts	(20		)	188			(36		)	10
(Gain) loss on divestitures and impairments, net	(13		)	65
Loss on impairments and divestitures, net (Note 2)							971			—
Earnings from equity investments	(526		)	(438		)	(192		)	(192		)
Distributions from equity investment earnings	412			351			152			124
Changes in components of working capital
Accounts receivable, net	226			67
Accounts receivable							222			193
Inventories	(28		)	38			59			(52		)
Other current assets	95			(18		)	50			128
Accounts payable	(266		)	(27		)	(200		)	(189		)
Accrued interest, net of interest rate swaps	(218		)	(198		)	(202		)	(236		)
Accrued taxes	(107		)	238			(59		)	(202		)
Other current liabilities	(136		)	(284		)	(126		)	(149		)
Other, net	25			45			17			50
Net Cash Provided by Operating Activities	3,121			3,375			893			635
Cash Flows From Investing Activities
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2)	(28		)	3,003
Acquisitions of assets and investments	(3		)	(20		)
Capital expenditures	(1,719		)	(2,206		)	(440		)	(554		)
Proceeds from sales of equity investments	108			33
Proceeds from sales of assets and investments, net of working capital adjustments							907			(16		)
Contributions to investments	(1,148		)	(294		)	(151		)	(331		)
Distributions from equity investments in excess of cumulative earnings	207			197			41			81
Loans to related party	(23		)	(23		)
Other, net	(4		)	(4		)	(22		)	6
Net Cash (Used in) Provided by Investing Activities	(2,610		)	686
Net Cash Provided by (Used in) Investing Activities							335			(814		)
Cash Flows From Financing Activities
Issuances of debt	5,118			11,837			2,125			1,399
Payments of debt	(6,303		)	(11,221		)	(1,969		)	(2,990		)
Debt issue costs	(9		)	(31		)	(7		)	(2		)
Cash dividends - common shares	(1,593		)	(1,163		)
Cash dividends - preferred shares	—			(117		)
Common stock dividends							(569		)	(455		)
Repurchases of common shares	(2		)	(250		)	(50		)	(2		)
Contributions from investment partner	135			148
Contributions from noncontrolling interests	3			19
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds	(879		)	—
Contributions from investment partner and noncontrolling interests							5			38
Distributions to investment partner							(18		)	—
Distribution to noncontrolling interests - KML distribution of the TMPL sale proceeds							—			(879		)
Distributions to noncontrolling interests - other	(42		)	(58		)	(3		)	(14		)
Other, net	(28		)	(17		)	(1		)	(3		)
Net Cash Used in Financing Activities	(3,600		)	(853		)	(487		)	(2,908		)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	26			26			(8		)	26
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(3,063		)	3,234
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits							733			(3,061		)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326			209			3,331
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	268		$	3,560		$	942		$	270

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

	Nine Months Ended September 30,					Three Months Ended March 31,
	2019			2018		2020		2019
Cash and Cash Equivalents, beginning of period	$	3,280		$	264	$	185	$	3,280
Restricted Deposits, beginning of period	51			62		24		51
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	3,331			326		209		3,331
Cash and Cash Equivalents, end of period	241			3,459		360		221
Restricted Deposits, end of period	27			101		582		49
Cash, Cash Equivalents, and Restricted Deposits, end of period	268			3,560		942		270
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(3,063	)	$	3,234
Net increase (decrease) in Cash, Cash Equivalents and Restricted Deposits						$	733	$	(3,061	)

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized (Note 10)	$	764
ROU assets and operating lease obligations recognized						$	14	$	701
Increase in property, plant and equipment from both accruals and contractor retainage				$	35	41
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,584			1,593		661		690
Cash paid during the period for income taxes, net	364			37		134		345

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 June 30, 2019 2,262
$ 23
$ 41,734
$ (7,670 ) $ (448 ) $ 33,639
$ 846
$ 34,485
Restricted shares 3
(7 ) (7 ) (7 )
Net income 506
506
11
517
Distributions —
(14 ) (14 )
Contributions —
2
2
Common stock dividends (569 ) (569 ) (569 )
Other —
(1 ) (1 )
Other comprehensive income (loss) 64
64
(3 ) 61
Balance at September 30, 2019 2,265
$ 23
$ 41,727
$ (7,733 ) $ (384 ) $ 33,633
$ 841
$ 34,474



	Common stock
	Issued shares		Par value		Additional paid-in capital			Accumulated deficit			Accumulated other comprehensive loss			Stockholders’ equity attributable to KMI			Non-controlling interests			Total
Balance at December 31, 2019	2,265		$	23	$	41,745		$	(7,693	)	$	(333	)	$	33,742		$	344		$	34,086
Repurchases of common shares	(4	)			(50		)							(50		)				(50		)
Restricted shares					18									18						18
Net (loss) income								(306		)				(306		)	15			(291		)
Distributions														—			(3		)	(3		)
Contributions														—			2			2
Common stock dividends								(569		)				(569		)				(569		)
Other comprehensive income											271			271						271
Balance at March 31, 2020	2,261		$	23	$	41,713		$	(8,568	)	$	(62	)	$	33,106		$	358		$	33,464

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

~~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) (4 )

(4 ) (4 )
Balance at January 1, 2019 2,262
23
41,701
(7,720 ) (330 ) 33,674
853
34,527
Repurchase of shares
(2 ) (2 ) (2 )
Restricted shares 3
28
28
28
Net income 1,580
1,580
32
1,612
Distributions —
(42 ) (42 )
Contributions —
3
3
Common stock dividends (1,593 ) (1,593 ) (1,593 )
Other —
(1 ) (1 )
Other comprehensive loss (54 ) (54 ) (4 ) (58 )
Balance at September 30, 2019 2,265
$ 23
$ 41,727
$ (7,733 ) $ (384 ) $ 33,633
$ 841
$ 34,474

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 ASU (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 1
45
45
45
Net income 1,115
1,115
302
1,417
Distributions —
(69 ) (69 )
Contributions —
30
30
Preferred stock dividends (117 ) (117 ) (117 )
Common stock dividends (1,163 ) (1,163 ) (1,163 )
Other —
2
2
Other comprehensive income 155
155
26
181
Balance at September 30, 2018 2
$ —
2,205
$ 22
$ 41,704
$ (7,744 ) $ (495 ) $ 33,487
$ 1,779
$ 35,266



	Common stock
	Issued shares	Par value		Additional paid-in capital			Accumulated 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							(4		)				(4		)				(4		)
Balance at January 1, 2019	2,262	23		41,701			(7,720		)	(330		)	33,674			853			34,527
Repurchases of common shares				(2		)							(2		)				(2		)
Restricted shares				17									17						17
Net income							556						556			11			567
Distributions													—			(14		)	(14		)
Common stock dividends							(455		)				(455		)				(455		)
Other comprehensive loss										(178		)	(178		)	(6		)	(184		)
Balance at March 31, 2019	2,262	$	23	$	41,716		$	(7,619	)	$	(508	)	$	33,612		$	844		$	34,456

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 ~~84,300~~83,000 miles of pipelines and ~~157~~147 terminals. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO₂ and other products, and our terminals store and handle various commodities including gasoline, ~~crude oil,~~ diesel fuel, chemicals, metals and petroleum coke.

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~~2019 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 and 2018, see Notes 4, 5 and 10.~~

~~Goodwill~~COVID-19

~~We evaluate goodwill for impairment on May 31~~The COVID-19 pandemic-related reduction in energy demand and the sharp decline in commodity prices related to the combined impact of ~~each year. For this purpose,~~falling demand and recent increases in production from Organization of Petroleum Exporting Countries (OPEC) members and other international suppliers have caused significant disruptions and volatility in the global marketplace during the first quarter of 2020. In the first quarter of 2020, we ~~have 6 reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately~~were negatively affected by these events, which, among many other inputs, resulted in $950 million of losses from ~~Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v)~~impairments in our CO₂~~; and (vi) Terminals. The evaluation of goodwill for impairment involves a two-step test.~~ business segment. These non-cash impairments are further discussed in Note 2.

~~The results~~There remains a continuing significant uncertainty regarding the length and impact 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~~COVID-19 and decreased commodity prices ~~could result in a deterioration of market multiples, comparable sales transactions prices, weighted average costs of capital~~on the energy industry and potential future impacts to 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.business.

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 which include dividend equivalent payments, do not participate in excess distributions over earnings.

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Net Income Available to Common Stockholders	$	506		$	693		$	1,580		$	998
Net (Loss) Income Available to Common Stockholders													$	(306	)	$	556
Participating securities:
Less: Net Income allocated to restricted stock awards(a)	(3		)	(4		)	(9		)	(5		)	(3		)	(3		)
Net Income Allocated to Class P Stockholders	$	503		$	689		$	1,571		$	993
Net (Loss) Income Allocated to Class P Stockholders													$	(309	)	$	553

Basic Weighted Average Common Shares Outstanding	2,264			2,205			2,263			2,205			2,264			2,262
Basic Earnings Per Common Share	$	0.22		$	0.31		$	0.69		$	0.45
Basic (Loss) Earnings Per Common Share													$	(0.14	)	$	0.24

________


(a)	As of ~~September 30, 2019,~~March 31, 2020, there were approximately 12 million restricted stock awards outstanding.

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


	Three Months Ended September 30,		Nine Months Ended September 30,		Three Months Ended March 31,
	2019	2018	2019	2018	2020	2019
Unvested restricted stock awards	13	13	13	11	12	13
Convertible trust preferred securities	3	3	3	3	3	3
Mandatory convertible preferred stock(a)	—	58	—	58

2. Impairments

During the first quarter of 2020, the decrease in the worldwide demand for crude oil primarily due to COVID-19 and sharp decline in commodity prices related to the combined impact of falling demand and recent increases in production from OPEC members and other international suppliers resulted in decreases in current and expected long-term crude oil and NGL sale prices, along with reductions to the market capitalization of peer companies in the energy industry. We determined that these conditions represented a triggering event that required us to perform impairment testing of certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO₂business segment and conducted interim tests of the recoverability of goodwill for our CO₂ and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020.

Long-lived Assets

For our CO₂ assets, the long lived asset impairment test involved a Step 1 assessment as to whether each asset’s net book value is expected to be recovered from the estimated undiscounted future cash flows.

To compute estimated future cash flows for our oil and gas producing properties, we used our reserve engineer’s estimates of proved and risk adjusted probable reserves. These estimates of proved and probable reserves are based upon historical performance along with adjustments for expected crude oil and natural gas field development. In calculating future cash flows, management utilized estimates of commodity prices based on a March 31, 2020 NYMEX forward curve adjusted for the impact of our existing sales contracts to determine the applicable net crude oil and NGL pricing for each property. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

•

To compute estimated future cash flows for our CO₂ source and transportation assets, volume forecasts were developed based on projected demand for our CO₂ services based upon management’s projections of the availability of CO₂ supply and the future demand for CO₂ for use in enhanced oil recovery projects. The CO₂ pricing assumption was a function of the March 31, 2020 NYMEX forward curve adjusted for the impact of existing sales contracts to determine the applicable net CO₂ pricing. Operating expenses were determined based on estimated fixed and variable field production requirements, and capital expenditures were based on economically viable development projects.

Certain oil and gas properties failed the first step. For these assets, we used a discounted cash flow analysis to estimate fair value. We applied a 10.5% discount rate, which we believe represents the estimated weighted average cost of capital of a

theoretical market participant. Based on step two of our long lived assets impairment test, we recognized $350 million of impairments on those oil and gas producing properties where the total carrying value exceeded its total estimated fair market value as of March 31, 2020.

Goodwill

The following goodwill impairment test for our CO₂ and Natural Gas Pipelines Non-Regulated reporting units reflects our adoption of the Accounting Standards Updates (ASU) No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment” on January 1, 2020. This new accounting method simplifies the goodwill impairment test by removing Step 2 of the goodwill impairment test, which required a hypothetical purchase price allocation.

For our CO₂ and Natural Gas Pipelines Non-Regulated reporting units, we applied an income approach to evaluate the fair value of these reporting units based on the present value of cash flows these reporting units are expected to generate in the future. Due to the uncertainty and volatility in market conditions within our peer group as of the test date, we did not incorporate the market approach to estimate fair value as of March 31, 2020.

•

In determining the fair value for our CO₂ reporting unit, we applied a 9.25% discount rate to the undiscounted cash flow amounts computed in the long-lived asset impairment analyses described above. The discount rate we used represents our estimate of the weighted average cost of capital of a theoretical market participant. The result of our goodwill analysis was a partial impairment of goodwill in our CO₂ reporting unit of approximately $600 million as of March 31, 2020.

For our Natural Gas Pipelines Non-Regulated reporting unit, the income approach we used to determine fair value included an analysis of estimated discounted cash flows based on 6 years of projections and application of a year 6 exit multiple based on management’s expectations of a discount rate and exit multiple that would be applied by a theoretical market participant and for market transactions of comparable assets. The discounted cash flows included various assumptions on volumes and prices for each underlying asset within the reporting unit including, as applicable, current commodity prices. The results of our impairment analysis for our Natural Gas Pipelines Non-Regulated reporting unit did not indicate an impairment of goodwill with the reporting unit’s fair value in excess of its carrying value by less than 10% as of March 31, 2020.

We consider the inputs for our long-lived asset and goodwill impairment calculations to be Level 3 inputs in the fair value hierarchy.

We recognized the following non-cash pre-tax losses (gains) on impairments and divestitures on assets (in millions):



	Three Months Ended March 31,
	2020		2019
Products Pipelines
Impairments of long-lived and intangible assets(a)	$	21	$	—
CO₂
Impairments of long-lived assets	350		—
Impairment of goodwill	600		—
Kinder Morgan Canada
Losses on divestiture of long-lived assets	—		2
Other gains on divestitures of long-lived assets	—		(2		)
Pre-tax losses on divestitures and impairments, net	$	971	$	—

_______


(a)	~~The holder of each convertible preferred share participated in~~2020 impairment amount is associated with 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.~~Belton terminal.

~~2. Divestitures~~Economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as sustained low crude oil demand and continued low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets, which will have an adverse effect on the demand for services provided by our four business segments. Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us. In addition, the revenues, cash flows, profitability and future growth of some of our

~~Pending Sale~~businesses depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO₂ business segment (and the carrying value of ~~U.S. Portion of Cochin Pipeline~~our crude oil, NGL and ~~KML~~natural gas producing properties) and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices.

~~On August 21, 2019,~~As conditions warrant, we ~~announced an agreement~~routinely evaluate our assets for potential triggering events such as those described above that could impact the fair value of certain assets or our ability to ~~sell~~recover the ~~U.S. portion~~carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the ~~Cochin Pipeline~~asset, these evaluations require the use of significant judgments including but not limited to ~~Pembina Pipeline Corporation (Pembina)~~judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for ~~$1.546 billion in cash. Also, KML announced~~products handled or transported by our assets. In the current worldwide economic and commodity price environment and to the extent conditions further deteriorate, we may identify additional triggering events that ~~it reached an agreement with Pembina under which Pembina has agreed to acquire all~~may require future evaluations of the ~~outstanding common equity of KML, including our 70% interest, subject to the terms~~recoverability of the arrangement agreement between KML and Pembina. Subject to and upon closing, KML shareholders will receive 0.3068 shares of Pembina common stock for each share of KML common stock whereby we will receive approximately 25 million shares of Pembina common stock, with a pre-taxcarrying value of ~~approximately $927 million as of September 30, 2019, for~~ our ~~70% interest~~long-lived assets, investments and goodwill which could result in ~~KML. The closing of the two transactions~~further impairment charges. In addition, we are ~~cross-conditioned upon each other, subject~~required to ~~KML’s shareholder and applicable regulatory approvals.~~

~~Sale of Trans Mountain Pipeline System and Its Expansion Project~~

~~On August~~perform our annual goodwill impairment test on May 31 ~~2018, KML completed the sale of the TMPL, the TMEP, Puget Sound pipeline system and Kinder Morgan Canada Inc., the Canadian employer~~^st. Because certain of our ~~staff that operate the business,~~assets have been written down to fair value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, 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). Wewould be recognized ~~a pre-tax~~

gain from the TMPL Sale of $622 million within “(Gain) loss on divestitures and impairments, net” in our accompanying consolidated statements of income during both the three and nine months ended September 30, 2018. During the first quarter of 2019, KML settled an additional C$37 million (U.S.$28 million) of working capital adjustments, which amount is included in the ~~accompanying consolidated statements of cash flows within “Proceeds from~~period in which the ~~TMPL Sale, net of cash disposed and working capital adjustments” for the nine months ended September 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~~carrying value is determined 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.not be recoverable.

3. Debt

The following table provides 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~~balances (in millions):


	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
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)	532		433		—		37
KML C$500 million credit facility, due August 31, 2022(b)(c)	34		—
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		—
6.85%, due February 2020(b)					—		700
6.50%, due April 2020(c)					535		535
5.30%, due September 2020	600		—		600		600
6.50%, due September 2020	349		—		349		349
5.00%, due February 2021					750		—
3.50%, due March 2021					750		—
5.80%, due March 2021					400		—
Trust I preferred securities, 4.75%, due March 2028	111		111		111		111
Kinder Morgan G.P. Inc, $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)					—		100
Current portion of other debt	45		44		45		45
Total current portion of debt	4,406		3,388		3,540		2,477

Long-term debt (excluding current portion)
Senior notes	30,124		32,380		29,242		30,164
EPC Building, LLC, promissory note, 3.967%, due 2018 through 2035	385		395
Kinder Morgan G.P. Inc., $1,000 Liquidation Value Series A Fixed-to-Floating Rate Term Cumulative Preferred Stock, due August 2057(d)	100		100
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035					377		381
Trust I preferred securities, 4.75%, due March 2028	110		110		110		110
Other	230		220		226		228
Total long-term debt	30,949		33,205		29,955		30,883
Total debt(e)	$	35,355	$	36,593	$	33,495	$	33,360

_______


(a)	Weighted average interest ~~rates~~rate on borrowings outstanding as of ~~September 30, 2019 and~~ December 31, ~~2018 were 2.47% and 3.10%, respectively.~~2019 was 1.90%.

(b)

~~Weighted average interest rate on borrowings outstanding~~On January 9, 2020, we sold the approximate 25 million shares of Pembina Pipeline Corporation (Pembina) common equity that we received as consideration for the sale of KML. We received proceeds of approximately $907 million ($764 million after tax) for the sale of the Pembina shares, which were used to repay debt that matured in February 2020. The fair value of the Pembina common equity of$925 million as of ~~September 30,~~December 31, 2019 was ~~3.41%.~~reported as “Marketable securities at fair value” in the accompanying consolidated balance sheet.

(c)

~~Borrowings under~~As of March 31, 2020, funds for the ~~KML $500 million credit facility are denominated~~repayment of these maturing notes, and associated accrued interest, were held in C$escrow and ~~are presented above~~included in ~~U.S. dollars. At September 30, 2019,~~ the ~~exchange rate was 0.7551 U.S. dollars per C$. See~~ ~~“—Credit Facilities—KML~~accompanying consolidated balance sheet within “Restricted deposits.” ~~below.~~

(d)

~~On July 17,~~In December 2019, we ~~entered into a guarantee agreement for~~notified the ~~payment obligations~~holder of our intent to ~~the holders of~~redeem these securities. As our notification was irrevocable, the outstanding balance was classified as current in our accompanying consolidated balance sheet as of December 31, 2019. We redeemed these securities, including accrued dividends, on January 15, 2020.

(e)

Excludes our “Debt fair value adjustments” which, as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, increased our total debt balances by ~~$1,162~~$1,450 million and ~~$731~~$1,032 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.~~

On February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994 million. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit ~~Facilities~~

~~KMI~~Facility

As of ~~September 30, 2019,~~March 31, 2020, we had 0 borrowings outstanding under our ~~$4.5~~$4.0 billion credit ~~facilities (in the aggregate), $532 million~~facility, 0 borrowings outstanding under our commercial paper program and ~~$84~~$83 million in letters of credit. Our availability under ~~the~~our credit ~~facilities~~facility as of ~~September 30, 2019~~March 31, 2020 was ~~$3,884~~$3,917 million. As of ~~September 30, 2019,~~March 31, 2020, we were in compliance with all required covenants.

~~KML~~Fair Value of Financial Instruments

AsThe carrying value and estimated fair value of ~~September 30, 2019, KML had C$45 million (U.S.$34 million)~~our outstanding debt balances are disclosed below (in millions):



	March 31, 2020				December 31, 2019
	Carrying value		Estimated fair value		Carrying value		Estimated fair value
Total debt	$	34,945	$	34,198	$	34,392	$	38,016

We used Level 2 input values to measure the estimated fair value of ~~borrowings~~our outstanding ~~under its 4-year, C$500 million unsecured revolving credit facility, due August~~debt balance as of both March 31, 2022, with C$452 million (U.S.$341 million) available after further reducing the C$500 million (U.S.$378 million) capacity for C$3 million (U.S.$3 million) in letters of credit. As of September 30, 2019, KML was in compliance with all required covenants. As of2020 and December 31, ~~2018, KML had no borrowings outstanding under its credit facility.~~2019.

4. Stockholders’ Equity

~~Common Equity~~

~~As of September 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.~~Common Stock

On July 19, 2017, our board of directors approved a $2 billion common share buy-back program that began in December 2017. During the ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, we ~~settled repurchases of~~repurchased approximately ~~0.1~~3.6 million of our Class P shares for approximately ~~$2 million.~~$50 million at an average price of approximately $13.94 per share. Since December 2017, in total, we have repurchased approximately 2932 million of our Class P shares under the program at an average price of approximately ~~$18.18~~$17.71 per share for approximately ~~$525~~$575 million.

~~KMI~~ For additional information regarding our Class P common stock, see Note 11 to our consolidated financial statements included in our 2019 Form 10-K.

Common Stock Dividends

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


	Three Months Ended September 30,				Nine Months Ended September 30,				Three Months Ended March 31,
	2019		2018		2019		2018		2020		2019
Per common share cash dividend declared for the period	$	0.25	$	0.20	$	0.75	$	0.60	$	0.2625	$	0.25
Per common share cash dividend paid in the period	$	0.25	$	0.20	$	0.70	$	0.525	0.25		0.20

On ~~October 16, 2019,~~April 22, 2020, our board of directors declared a cash dividend of ~~$0.25~~$0.2625 per common share for the quarterly period ended ~~September 30, 2019,~~March 31, 2020, which is payable on ~~November~~May 15, ~~2019~~2020 to common shareholders of record as of the close of business on ~~October 31, 2019.~~May 4, 2020.

~~Noncontrolling Interests~~

~~KML~~

On August 21, 2019, KML announced that it reached an agreement with Pembina under which Pembina has agreed to acquire all the outstanding common and preferred equity of KML, including our 70% interest. See Note 2 for more information.

~~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.

During the three and nine months ended September 30, 2019, KML paid dividends to the public on its restricted voting shares of $4 million and $13 million, respectively, and on its Series 1 and Series 3 Preferred Shares of $5 million and $16 million, respectively.

~~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.~~

~~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 nine months ended September 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 September 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~~Loss

Reporting of ~~stranded tax effects in accumulated other~~Amounts Reclassified Out of Accumulated Other Comprehensive Loss

Cumulative revenues, expenses, gains and losses that under GAAP are included within our 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 amountsbut excluded from our earnings are reported 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~~within “Stockholders’ Equity” in our consolidated ~~statement~~balance sheets. Changes in the components of ~~stockholders’ equity for the nine months ended September 30, 2018.~~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, 2019	$	(7	)	$	—	$	(326	)	$	(333	)
Other comprehensive gain before reclassifications	222			1		11			234
Loss reclassified from accumulated other comprehensive loss	37			—		—			37
Net current-period change in accumulated other comprehensive (loss) income	259			1		11			271
Balance as of March 31, 2020	$	252		$	1	$	(315	)	$	(62	)



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

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.~~obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

~~On January 1, 2019,~~During the three months ended March 31, 2020, we ~~adopted ASU No. 2017-12, “Derivatives and Hedging (Topic 815): Targeted Improvements~~entered into a floating-to-fixed interest rate swap agreement with a notional principal amount of $2,500 million, which was not designated as an accounting hedge. These agreements effectively fixed our LIBOR exposure for a portion of our fixed to ~~Accounting~~floating rate interest rate swaps for ~~Hedging Activities.” The ASU better aligns an entity’s risk management activities and financial reporting for hedging relationships~~2020. As of March 31, 2020, the maximum length of time over which we have hedged a portion of our exposure to the variability in future interest payments is 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.December 31, 2020.

Energy Commodity Price Risk Management

As of ~~September 30, 2019,~~March 31, 2020, 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~~contracts
Crude oil fixed price	(~~20.0~~18.9	)	MMBbl
Crude oil basis	(~~8.8~~6.2	)	MMBbl
Natural gas fixed price	(~~46.5~~35.7	)	Bcf
Natural gas basis	(~~36.0~~31.3	)	Bcf
NGL fixed price	(~~0.9~~1.2	)	MMBbl
Derivatives not designated as hedging ~~instruments~~contracts
Crude oil fixed price	(~~0.8~~0.7	)	MMBbl
Crude oil basis	(~~5.0~~2.4	)	MMBbl
Natural gas fixed price	(~~8.3~~17.3	)	Bcf
Natural gas basis	~~(18.2~~23.4	)	Bcf
NGL fixed price	(~~2.2~~1.7	)	MMBbl

As of ~~September 30, 2019,~~March 31, 2020, 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 September 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~~We utilize 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~~derivatives 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 September 30, 2019, the principal amount of hedged senior notes consisted of $2,600 million included in “Current portion of debt” and $7,625 million included in “Long-term debt” on our accompanying consolidated balance sheets. As of September 30, 2019, the maximum length of time over which we have hedged a portion ofhedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in ~~the value of debt due~~expected future cash flows attributable to variable interest rate ~~risk is through March 15, 2035.~~

~~During the nine months ended September 30, 2019, we entered into a floating-to-fixed~~payments. The following table summarizes our outstanding interest rate ~~swap agreement with a notional principal amount~~contracts as 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 September 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.March 31, 2020 (in millions):



	Notional amount	Accounting treatment	Maximum term
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$8,025	Fair value hedge	March 2035
Variable-to-fixed interest rate contracts	$250	Cash flow hedge	January 2023
Variable-to-fixed interest rate contracts	$2,500	Mark-to-Market	December 2020

_______


(a)	The principal amount of hedged senior notes consisted of $1,300 million included in “Current portion of debt” and $6,725 million included in “Long-term debt” on our accompanying consolidated balance sheet.

Foreign Currency Risk Management

~~As of both September 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~~We utilize foreign currency ~~risk related~~derivatives to hedge 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,~~exposure 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.variability in foreign exchange rates. 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~~following table summarizes our outstanding foreign currency ~~swap agreements with a combined notional principal amount~~contracts as of ~~C$2,450 million (U.S.$1,888 million).~~March 31, 2020 (in millions):



	Notional amount	Accounting treatment	Maximum term
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$1,358	Cash flow hedge	March 2027

_______

(a) These ~~swaps resulted in our selling fixed C$ and receiving fixed U.S.$, effectively hedging~~swaps eliminate the foreign currency risk associated with ~~a substantial portion~~all of our share of the TMPL Sale proceeds which were held in Canadian dollar denominated accounts until KML’s board of directors 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.Euro-denominated debt.

~~Impact of Derivative Contracts on Our Consolidated Financial Statements~~

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
		Derivatives Asset				Derivatives Liability
		March 31, 2020		December 31, 2019		March 31, 2020			December 31, 2019
	Location	Fair value				Fair value
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	279	$	31	$	(7	)	$	(43	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	135		17		—			(8		)
Subtotal		414		48		(7		)	(51		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	126		45		(2		)	—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	666		313		(9		)	(1		)
Subtotal		792		358		(11		)	(1		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(30		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	11		46		(24		)	—
Subtotal		11		46		(54		)	(6		)
Total		1,217		452		(72		)	(58		)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	43		8		(2		)	(7		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		—			—
Subtotal		47		8		(2		)	(7		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(4		)	—
Subtotal		—		—		(4		)	—
Total		47		8		(6		)	(7		)
Total derivatives		$	1,264	$	460	$	(78	)	$	(65	)

The following two tables summarize the fair value measurements of our derivative contracts 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.

Fair Value of Derivative Contracts
Derivative Assets Derivative Liabilities
September 30,
2019 December 31,
2018 September 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) $ 73
$ 135
$ (35 ) $ (45 )
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 47
64
(1 ) —
Subtotal 120
199
(36 ) (45 )
Interest rate contracts Fair value of derivative contracts/(Other current liabilities) 53
12
(2 ) (37 )
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 421
121
(2 ) (78 )
Subtotal 474
133
(4 ) (115 )
Foreign currency contracts Fair value of derivative contracts/(Other current liabilities) —
91
(14 ) (6 )
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 20
106
—
—
Subtotal 20
197
(14 ) (6 )
Total 614
529
(54 ) (166 )

Derivatives not designated as hedging instruments

Energy commodity derivative contracts Fair value of derivative contracts/(Other current liabilities) 18
22
(4 ) (5 )
Deferred charges and other assets/(Other long-term liabilities and deferred credits) 1
—
(1 ) —
Total 19
22
(5 ) (5 )
Total derivatives $ 633
$ 551
$ (59 ) $ (171 )



	Balance sheet asset fair value measurements by level
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting			Cash collateral held(b)			Net amount
As of March 31, 2020
Energy commodity derivative contracts(a)	$	6	$	455	$	—	$	461	$	(9	)	$	(25	)	$	427
Interest rate contracts	—		792		—		792		(2		)	—			790
Foreign currency contracts	—		11		—		11		(11		)	—			—
As of December 31, 2019
Energy commodity derivative contracts(a)	$	19	$	37	$	—	$	56	$	(19	)	$	(21	)	$	16
Interest rate contracts	—		358		—		358		—			—			358
Foreign currency contracts	—		46		—		46		(6		)	—			40



	Balance sheet liability fair value measurements by level
	Level 1			Level 2			Level 3		Gross amount			Contracts available for netting		Cash collateral posted(b)		Net amount
As of March 31, 2020
Energy commodity derivative contracts(a)	$	(7	)	$	(2	)	$	—	$	(9	)	$	9	$	—	$	—
Interest rate contracts	—			(15		)	—		(15		)	2		—		(13		)
Foreign currency contracts	—			(54		)	—		(54		)	11		—		(43		)
As of December 31, 2019
Energy commodity derivative contracts(a)	$	(3	)	$	(55	)	$	—	$	(58	)	$	19	$	—	$	(39	)
Interest rate contracts	—			(1		)	—		(1		)	—		—		(1		)
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 crude oil basis swaps.


(b)	Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

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


Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item												Location	Gain/(loss) recognized in income on derivative and related hedged item
		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		2019			2018			2019			2018				2020			2019

Interest rate contracts	Interest, net	$	117		$	(72	)	$	453		$	(326	)	Interest, net	$	433		$	128

Hedged fixed rate debt(a)	Interest, net	$	(119	)	$	70		$	(468	)	$	315		Interest, net	$	(440	)	$	(138	)

_______


(a)	As of ~~September 30, 2019,~~March 31, 2020, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of ~~$475~~$799 million included in “Debt fair value adjustments” on our accompanying consolidated balance ~~sheets.~~sheet.

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 September 30, Three Months Ended September 30,
2019 2018 2019 2018
Energy commodity derivative contracts $ 96
$ (109 )
Revenues—Natural
gas sales
$ 11
$ (4 )

Revenues—Product
sales and other
(2 ) (3 )
Costs of sales (3 ) 2
Interest rate contracts (1 ) —
Earnings from equity investments(c) —
—
Foreign currency contracts (69 ) (4 ) Other, net (59 ) (10 )
Total $ 26
$ (113 ) Total $ (53 ) $ (15 )


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)						Gain/(loss) recognized in OCI on derivative(a)						Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,							Nine Months Ended September 30,						Three Months Ended March 31,							Three Months Ended March 31,
	2019			2018				2019			2018			2020			2019				2020			2019
Energy commodity derivative contracts	$	(74	)	$	(160	)	Revenues—Natural gas sales	$	16		$	(9	)	$	379		$	(245	)	Revenues—Commodity sales	$	(8	)	$	13
							Revenues—Product sales and other	(1		)	(40		)
							Costs of sales	8			3
Interest rate contracts	(2		)	3			Earnings from equity investments(c)	2			(5		)	(8		)	—			Costs of sales	(17		)	1
Foreign currency contracts	(95		)	(15		)	Other, net	(71		)	(50		)	(82		)	(34		)	Other, net	(23		)	(31		)
Total	$	(171	)	$	(172	)	Total	$	(46	)	$	(101	)	$	289		$	(279	)	Total	$	(48	)	$	(17	)

_______

(a)

We expect to reclassify an approximate ~~$69~~$257 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of ~~September 30, 2019~~March 31, 2020 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 nine months ended September 30, 2019, we recognized a $12 million gain associated with a write-down of hedged inventory. During the nine months ended September 30, 2018, we recognized a $3 million loss as a result of our equity investment’s forecasted transactions being probable of not occurring. All other amountsAmounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).


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



Derivatives in net investment hedging relationships	Gain/(loss) recognized in OCI on derivative
	Three Months Ended March 31,
	2020		2019
Foreign currency contracts	$	—	$	(8	)
Total	$	—	$	(8	)

Derivatives in net investment hedging relationships
Gain/(loss)
recognized in OCI on derivative
Location
Gain/(loss) reclassified from Accumulated OCI
into income(a)
Three Months Ended September 30, Three Months Ended September 30,
2019 2018 2019 2018
Foreign currency contracts $ —
$ (14 ) (Gain) loss on divestitures and impairments, net $ —
$ 26
Total $ —
$ (14 ) Total $ —
$ 26

Derivatives in net investment hedging relationships
Gain/(loss)
recognized in OCI on derivative
Location
Gain/(loss) reclassified from Accumulated OCI
into income(a)
Nine Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
Foreign currency contracts $ (8 ) $ (14 ) (Gain) loss on divestitures and impairments, net $ —
$ 26
Total $ (8 ) $ (14 ) Total $ —
$ 26

~~_______~~


~~(a)~~	~~During the three and nine months ended September 30, 2018, we recognized a $26 million gain as a result of the TMPL Sale. See Note 2.~~


Derivatives not designated as hedging instruments	Location	Gain/(loss) recognized in income on derivative											Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,					Nine Months Ended September 30,							Three Months Ended March 31,
		2019		2018			2019			2018				2020		2019
Energy commodity derivative contracts	Revenues—Natural gas sales	$	1	$	—		$	26		$	2		Revenues—Commodity sales	$	117	$	10
	Revenues—Product sales and other	11		(65		)	10			(111		)	Costs of sales	4		(2		)
	Costs of sales	—		—			(3		)	1
	Earnings from equity investments(b)	—		—			2			—
Total(a)		$	12	$	(65	)	$	35		$	(108	)		$	121	$	8

_______


(a)	The three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 amounts include approximate ~~losses~~gains of $4$74 million and $2$8 million, respectively, ~~and the three and nine months ended September 30, 2018 include approximate losses of $14 million and $11 million, respectively. These 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 ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we had 0 outstanding letters of credit supporting our commodity price risk management program. As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we had cash margins of $19 million and ~~$16~~$15 million, respectively, posted by our counterparties with us as collateral and reported within “Other ~~Current Liabilities”~~current liabilities” on our accompanying consolidated balance sheets. The balance at ~~September 30, 2019~~March 31, 2020 represents the net of our initial margin requirements of ~~$15~~$6 million, offset by counterparty variation margin requirements of ~~$34~~$25 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of ~~September 30, 2019,~~March 31, 2020, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches we would not be required to post additional collateral.

~~Reporting of Amounts Reclassified Out of Accumulated Other Comprehensive Loss~~

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

Net unrealized
gains/(losses)
on cash flow
hedge derivatives

Foreign
currency
translation
adjustments

Pension and
other
postretirement
liability adjustments

Total
accumulated other
comprehensive loss
Balance as of December 31, 2018 $ 164
$ (91 ) $ (403 ) $ (330 )
Other comprehensive (loss) gain before reclassifications (132 ) 20
23
(89 )
Loss reclassified from accumulated other comprehensive loss 35
—
—
35
Net current-period change in accumulated other comprehensive (loss) income (97 ) 20
23
(54 )
Balance as of September 30, 2019 $ 67
$ (71 ) $ (380 ) $ (384 )

Net unrealized
gains/(losses)
on cash flow
hedge derivatives

Foreign
currency
translation
adjustments

Pension and
other
postretirement
liability adjustments

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

~~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)
As of September 30, 2019
Energy commodity derivative contracts(a) $ 23
$ 116
$ —
$ 139
$ (19 ) $ (34 ) $ 86
Interest rate contracts —
474
—
474
(1 ) —
473
Foreign currency contracts —
20
—
20
(14 ) —
6
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 Cash collateral posted(b)
As of September 30, 2019
Energy commodity derivative contracts(a) $ (2 ) $ (39 ) $ —
$ (41 ) $ 19
$ —
$ (22 )
Interest rate contracts —
(4 ) —
(4 ) 1
—
(3 )
Foreign currency contracts —
(14 ) —
(14 ) 14
—
—
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 crude oil 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):~~

September 30, 2019 December 31, 2018

Carrying
value

Estimated
fair value

Carrying
value

Estimated
fair value
Total debt $ 36,517
$ 40,056
$ 37,324
$ 37,469

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

7. 6. 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 September 30, 2019													Three Months Ended March 31, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total		Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	882	$	89	$	256	$	1	$	(1	)	$	1,227	$	865	$	79	$	189	$	—	$	—		$	1,133
Fee-based services	182		265		132		14		—			593		193		260		121		13		—			587
Total services revenues	1,064		354		388		15		(1		)	1,820
Sales
Total services														1,058		339		310		13		—			1,720
Commodity sales
Natural gas sales	618		—		—		—		(1		)	617		501		—		—		—		(2		)	499
Product sales	162		84		9		268		(7		)	516		136		109		3		232		(13		)	467
Total sales revenues	780		84		9		268		(8		)	1,133
Total commodity sales														637		109		3		232		(15		)	966
Total revenues from contracts with customers	1,844		438		397		283		(9		)	2,953		1,695		448		313		245		(15		)	2,686
Other revenues(c)	90		46		111		15		(1		)	261		180		47		129		64		—			420
Total revenues	$	1,934	$	484	$	508	$	298	$	(10	)	$	3,214	$	1,875	$	495	$	442	$	309	$	(15	)	$	3,106

Three Months Ended September 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) $ 819
$ 95
$ 232
$ —
$ —
$ —
$ 1,146
Fee-based services 174
246
163
17
41
—
641
Total services revenues 993
341
395
17
41
—
1,787
Sales
Natural gas sales 806
—
—
—
—
(3 ) 803
Product sales 358
94
9
313
—
(11 ) 763
Total sales revenues 1,164
94
9
313
—
(14 ) 1,566
Total revenues from contracts with customers 2,157
435
404
330
41
(14 ) 3,353
Other revenues(c) 35
40
100
(14 ) 3
—
164
Total revenues $ 2,192
$ 475
$ 504
$ 316
$ 44
$ (14 ) $ 3,517

Nine Months Ended September 30, 2019
Natural Gas Pipelines Products Pipelines Terminals
CO₂
Corporate and Eliminations Total
Revenues from contracts with customers(a)
Services
Firm services(b) $ 2,701
$ 253
$ 785
$ 1
$ (3 ) $ 3,737
Fee-based services 561
752
398
45
—
1,756
Total services revenues 3,262
1,005
1,183
46
(3 ) 5,493
Sales
Natural gas sales 1,979
—
—
1
(7 ) 1,973
Product sales 599
211
16
827
(23 ) 1,630
Total sales revenues 2,578
211
16
828
(30 ) 3,603
Total revenues from contracts with customers 5,840
1,216
1,199
874
(33 ) 9,096
Other revenues(c) 263
134
325
39
—
761
Total revenues $ 6,103
$ 1,350
$ 1,524
$ 913
$ (33 ) $ 9,857


	Nine Months Ended September 30, 2018																Three Months Ended March 31, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂			Kinder Morgan Canada(d)		Corporate and Eliminations			Total		Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,490	$	286	$	751	$	1		$	—	$	(2	)	$	3,526	$	930	$	80	$	250	$	—	$	(1	)	$	1,259
Fee-based services	500		706		460		50			167		—			1,883		192		235		148		16		(1		)	590
Total services revenues	2,990		992		1,211		51			167		(2		)	5,409
Sales
Total services																	1,122		315		398		16		(2		)	1,849
Commodity sales
Natural gas sales	2,370		—		—		1			—		(6		)	2,365		754		—		—		1		(2		)	753
Product sales	904		310		16		948			—		(28		)	2,150		240		66		2		268		(6		)	570
Total sales revenues	3,274		310		16		949			—		(34		)	4,515
Total commodity sales																	994		66		2		269		(8		)	1,323
Total revenues from contracts with customers	6,264		1,302		1,227		1,000			167		(36		)	9,924		2,116		381		400		285		(10		)	3,172
Other revenues(c)	161		118		287		(130		)	3		—			439		85		43		109		20		—			257
Total revenues	$	6,425	$	1,420	$	1,514	$	870		$	170	$	(36	)	$	10,363	$	2,201	$	424	$	509	$	305	$	(10	)	$	3,429

_______


(a)	Differences between the revenue classifications presented on the consolidated statements of ~~income~~operations 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 amount 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 of $294 million and ~~derivatives.~~$218 million and derivative contracts of $104 million and $23 million for the three months ended March 31, 2020 and 2019, respectively. See ~~Notes~~ Note 5 ~~and 10~~ for additional information related to our derivative ~~contracts and lessor contracts, respectively.~~contracts.


~~(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~~As of March 31, 2020 and December 31, 2019, our contract ~~assets~~asset balances were $32 million and ~~liabilities (in millions):~~$27 million, respectively. Of the contract asset balance at December 31, 2019, $10 million was transferred to accounts receivable during the three months ended March 31, 2020. As of March 31, 2020 and December 31, 2019, our contract liability balances were $257 million and $232 million, respectively. Of the contract liability balance at December 31, 2019, $32 million was recognized as revenue during the three months ended March 31, 2020.

Nine Months Ended September 30, 2019
Contract Assets
Balance at December 31, 2018(a) $ 24
Additions 77
Transfer to Accounts receivable (27 )
Other (1 )
Balance at September 30, 2019(b) $ 73
Contract Liabilities
Balance at December 31, 2018(c) $ 292
Additions 305
Transfer to Revenues (285 )
Other(d) (15 )
Balance at September 30, 2019(e) $ 297

~~_______~~


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


~~(b)~~	~~Includes current and non-current balances of $63 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 $74 million and $223 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 ~~September 30, 2019~~March 31, 2020 that we will invoice or transfer from contract liabilities and recognize in future periods (in millions):


Year	Estimated Revenue		Estimated Revenue
Three months ended December 31, 2019	$	1,290
2020	4,631
Nine months ended December 31, 2020			$	3,309
2021	3,961		3,845
2022	3,346		3,121
2023	2,771		2,529
2024			2,206
Thereafter	15,834		13,988
Total	$	31,833	$	28,998

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedients that we elected to apply, remaining performance obligations ~~for~~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;~~and (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.~~less.

8. 7. 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 nine months ended September 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 September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,925		$	2,180		$	6,073		$	6,391		$	1,861		$	2,192
Intersegment revenues	9			12			30			34			14			9
Products Pipelines	484			475			1,350			1,420			495			424
Terminals
Revenues from external customers	507			503			1,521			1,512			441			508
Intersegment revenues	1			1			3			2			1			1
CO₂	298			316			913			870			309			305
Kinder Morgan Canada(a)	—			44			—			170
Corporate and intersegment eliminations	(10		)	(14		)	(33		)	(36		)	(15		)	(10		)
Total consolidated revenues(b)	$	3,214		$	3,517		$	9,857		$	10,363
Total consolidated revenues													$	3,106		$	3,429


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Segment EBDA~~(c)~~(a)
Natural Gas Pipelines	$	1,092		$	930		$	3,383		$	2,368		$	1,196		$	1,203
Products Pipelines	325			325			908			912			269			276
Terminals	295			301			884			872			257			299
CO₂	164			205			558			561			(755)			198
Kinder Morgan Canada~~(a)~~	—			654			(2		)	746			—			(2		)
Total Segment EBDA~~(d)~~	1,876			2,415			5,731			5,459			967			1,974
DD&A	(578		)	(569		)	(1,750		)	(1,710		)	(565		)	(593		)
Amortization of excess cost of equity investments	(21		)	(21		)	(61		)	(77		)	(32		)	(21		)
General and administrative and corporate charges	(162		)	(151		)	(478		)	(485		)	(165		)	(161		)
Interest, net	(447		)	(473		)	(1,359		)	(1,456		)	(436		)	(460		)
Income tax expense	(151		)	(196		)	(471		)	(314		)	(60		)	(172		)
Total consolidated net income	$	517		$	1,005		$	1,612		$	1,417
Total consolidated net (loss) income													$	(291	)	$	567


	September 30, 2019		December 31, 2018		March 31, 2020		December 31, 2019
Assets
Natural Gas Pipelines	$	51,164	$	50,261	$	49,393	$	50,310
Products Pipelines	9,501		9,598		9,310		9,468
Terminals	9,903		9,415		8,840		8,890
CO₂	3,757		3,928		2,926		3,523
Corporate assets~~(e)~~(b)	2,606		5,664		3,061		1,966
Total consolidated assets~~(f)~~	$	76,931	$	78,866	$	73,530	$	74,157

_______


(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 September 30, 2018 were $2,227 million, $432 million~~, ~~$502 million and $(4) million and for the nine months ended September 30, 2018 were $6,559 million, $1,273 million~~, ~~$1,508 million and $(17) 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 ~~divestitures~~impairments and ~~impairments,~~divestitures, net, and other income, net.


~~(d)~~	Segment EBDA previously reported (before reclassifications) for the three months ended September 30, 2018 were $976 million, $279 million and $301 million and for the nine months ended September 30, 2018 were $2,425 million, $857 million and $870 million for the Natural Gas Pipelines, Products Pipelines and Terminals business segments, respectively.

~~(e)~~(b)

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,~~derivative contracts, 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 Products Pipelines reporting unit.

9. 8. Income Taxes

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


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
Income tax expense	$	151		$	196		$	471		$	314		$	60		$	172
Effective tax rate	22.6		%	16.3		%	22.6		%	18.1		%	(26.0		)%	23.3		%

Total tax expense for the three months ended March 31, 2020 is approximately $60 million resulting in an effective tax rate of (26.0)%, as compared with $172 million tax expense and an effective tax rate of 23.3%, for the same period of 2019.

The effective tax rate for the three months ended March 31, 2020 is “negative” in relation to the statutory federal rate of 21% primarily due to the $600 million CO₂ reporting unit impairment of non tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit, partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus Corporation (Citrus) and Plantation Pipe Line Company (Plantation). While we would normally expect a federal income tax benefit from our loss before income taxes for the three months ended March 31, 2020, because the tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.

The effective tax rate for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2019 is higher than the statutory federal rate of 21% primarily due to state and foreign ~~income taxes,~~taxes. These increases were partially offset by dividend-received deductions from our investments in Citrus, ~~Corporation (Citrus),~~ NGPL Holdings LLC ~~(NGPL)~~ and ~~Plantation Pipe Line Company (Plantation).~~Plantation.

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

~~10. Leases~~

~~Effective January 1, 2019, we adopted ASU No. 2016-02, “~~9. ~~Leases (Topic 842)~~Litigation, Environmental and Other Contingencies” 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):~~

Nine Months Ended September 30, 2019
Operating leases $ 107
Short-term and variable leases 58
Total lease cost(a) $ 165

~~_______~~


~~(a)~~	~~Includes $29 million of capitalized lease costs.~~

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

Nine Months Ended September 30, 2019
Operating cash flows from operating leases $ (136 )
Investing cash flows from operating leases (29 )
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion 70
Amortization of ROU assets 52

Weighted average remaining lease term 16.31 years
Weighted average discount rate 5.87 %

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

Lease Activity Balance sheet location September 30, 2019
ROU assets Deferred charges and other assets $ 714
Short-term lease liability Other current liabilities 53
Long-term lease liability Other long-term liabilities and deferred credits 661
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 September 30, 2019 are as follows (in millions):~~

Three months ended December 31, 2019 $ 26
2020 90
2021 81
2022 74
2023 67
Thereafter 825
Total lease payments(a) 1,163
Less: Interest (449 )
Present value of lease liabilities $ 714

~~_______~~


~~(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 KML’s, 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 or upon modification. None of our leases allow the lessee to purchase the leased asset.

Lease income for the three and nine months ended September 30, 2019 totaled $226 million and $660 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):~~

September 30, 2019
2019 (three months ended December 31, 2019) $ 98
2020 370
2021 344
2022 329
2023 299
Thereafter 3,699
Total $ 5,139

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 and Environmental~~

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.~~business. 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, Young Gas Storage, and Bear Creek Storage Company, L.L.C. and terminated all of our remaining 501-G proceedings without taking further action. Accordingly, our 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~~sought 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. Comments were filed by industry groups, pipeline companies and shippers for review and evaluation by the FERC and there is no deadline or requirement for the FERC to take action on this matter.

SFPP FERC Proceedings

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~~(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~~(pending 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~~(pending before the FERC for ~~hearing by~~an order on the ~~FERC)~~complaint); 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,~~OR19-21/33/37, filed beginning in April 2019, in which various shippers are challenging SFPP’s index increases in 2018 ~~(currently pending~~(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~~would be entitled to seek reparations ~~(which may reach back up to~~for the two ~~years prior to~~year period preceding the filing date of their ~~complaints)~~ complaints (OR cases) and/or prospective refunds in protest cases from the date of ~~any excess rates paid,~~protest (IS cases), 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 May 2019, in the IS08-390 proceeding as ordered by the FERC based on ~~the~~its denial of an income tax allowance. With respect to the various SFPP related complaints and protest proceedings at the FERC (including IS08-390), we estimate that the shippers are seeking approximately ~~$30~~$50 million in annual rate reductions and approximately ~~$330~~$400 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 FERC Proceedings

The tariffs and rates charged by EPNG are subject to 2 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~~would 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~~appeals in the 2008 ~~rate case, EPNG’s appeal from the~~and 2010 rate ~~case, and~~cases as well as the intervenors’ delayed appeal in the 2010 ~~case. In accordance with that schedule, briefing has been completed and oral~~rate case were consolidated. Oral argument ~~is scheduled~~was heard by the U.S. Court of Appeals for ~~November 25, 2019.~~

~~Other Commercial Matters~~the D.C. Circuit on March 13, 2020.

Gulf LNG Facility ~~Arbitration~~Disputes

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~~claims 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. ~~The Delaware~~On January 10, 2020, the Court of Chancery ~~heard oral argument~~entered an Order and Final Judgment granting GLNG’s motion to enjoin arbitration of the negligent misrepresentation claim, but denying the motion to enjoin arbitration of the breach of contract claims. The parties filed cross appeals of the Final Judgment. The Delaware appeals and arbitration proceeding remain pending.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on ~~GLNG’s complaint~~substantially the same terms and ~~related motion in August 2019, and all deadlines~~conditions as set forth in the ~~Second Arbitration are stayed pending~~arbitration award pertaining to Eni USA. ALSS also seeks a declaration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the ~~Court’s decision.~~ pursuit of an LNG liquefaction export project have given rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also seeks a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest.

GLNG intends to continue to vigorously prosecute and defend all of the foregoing proceedings.

~~Price Reporting Litigation~~Continental Resources, Inc. v. Hiland Partners Holdings, LLC

~~Beginning~~On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in ~~2003,~~Garfield County, Oklahoma state court alleging that Hiland Partners Holdings, LLC (Hiland Partners) breached a Gas Purchase Agreement, dated November 12, 2010, as amended (GPA), by failing to receive and purchase all of CLR’s dedicated gas under the GPA (produced in three North Dakota counties). CLR also alleged fraud, maintaining that Hiland Partners promised the construction of several ~~lawsuits were~~additional facilities to process the gas without an intention to build the facilities. Hiland Partners denied these allegations, but the parties entered into a settlement agreement in June 2018, under which CLR agreed to release all of its claims in exchange for Hiland

Partners’ construction of 10 infrastructure projects by November 1, 2020. CLR has filed an amended petition in which it asserts that Hiland Partners’ failure to construct certain facilities 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 manipulatespecific dates nullifies 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~~release contained in the settlement ofagreement. CLR’s amended petition makes additional claims under both the ~~final Wisconsin class action lawsuit which was approved by the U.S. District Court in Nevada on August 5, 2019. The amount~~GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that ~~was paid in settlement of this matter~~Hiland Partners is not ~~material~~allowed to ~~our results~~deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of ~~operations, cash flows or dividends to shareholders.~~$225 million. Hiland Partners denies these claims and will vigorously defend against any action in which they are asserted.

Pipeline Integrity and Releases

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

General

As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, our total reserve for legal matters was ~~$188~~$243 million and ~~$207~~$203 million, respectively. In addition, as of March 31, 2020 and December 31, 2019, we have recorded a receivable of $31 million and $2 million, respectively, for expected cost recoveries that have been deemed probable.

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.~~Site (PHSS). 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 2 facilities acquired from GATX Terminals Corporation) and KMBT (in connection with its ownership or operation of 2 facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT��s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required

by the ROD. Our share of responsibility for ~~Portland Harbor Superfund Site~~the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded 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.~~PHSS. 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.~~PHSS. 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 environmental assessments 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.~~U.S. 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.~~business.

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~~8 miles of the Site. ~~The~~At that time the final cleanup plan in the ROD iswas 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 8 miles of the Site. The design work is ~~expected to~~underway. Initial expectations were that the design work would take four years to ~~complete and the~~complete. The cleanup is expected to take at least six years to ~~complete.~~complete once it begins. On June 30, 2018 and July 13, 2018, respectively, OCC filed 2 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 8 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, 1 of which is against TGP and 1 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 the 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. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We will continue to vigorously defend this case.

On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, 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. On January 30, 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. 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 2 cases against TGP, 2 cases against SNG, and 2 cases against both TGP and SNG. In these cases, the Plaintiffs allege that the 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~~The plaintiffs allege that the 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~~The 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~~The plaintiffs allege that the defendants are obligated to restore and remediate the affected property without regard to the value of the property. ~~Plaintiffs~~The 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, TGP, and another defendant that was tried in 2017 to the U.S. District Court for the Eastern District of Louisiana, ~~$80~~

$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 the 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, the 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,~~July 27, 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 ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we have accrued a total reserve for environmental liabilities in the amount of ~~$258~~$256 million and ~~$271~~$259 million, respectively. In addition, as of ~~both September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, we have recorded a receivable of ~~$13~~$12 million and $15 million, respectively, for expected cost recoveries that have been deemed probable.

~~12.~~ 10. 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~~ASU No. 2020-04

~~KMI, along with its direct subsidiary KMP, are issuers~~On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform - Facilitation of ~~certain public debt securities. KMI, KMP~~the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and ~~substantially all~~exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens 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 Issuerexpected market transition from LIBOR and other ~~subsidiaries~~interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate. Entities can elect not to apply certain modification accounting requirements to contracts affected by this reference rate reform, if certain criteria are ~~all guarantors~~met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met. The guidance is effective upon issuance and generally can be applied through December 31, 2022. We are currently reviewing the effect of ~~each series of public debt.~~

Excluding fair value adjustments, as of September 30, 2019, Parent Issuer and Guarantor, Subsidiary Issuer and Guarantor-KMP, and Subsidiary Guarantors had $15,220 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 September 30, 2019 condensed consolidating balance sheet is approximately $169 million of other financing obligations that are not subjectthis ASU to ~~the cross guarantee agreement.~~our financial statements.

Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 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 $ —
$ —
$ 2,910
$ 317
$ (13 ) $ 3,214

Operating Costs, Expenses and Other
Costs of sales —
—
734
29
(1 ) 762
Depreciation, depletion and amortization 5
—
505
68
—
578
Other operating expense 2
1
804
128
(12 ) 923
Total Operating Costs, Expenses and Other 7
1
2,043
225
(13 ) 2,263

Operating (Loss) Income (7 ) (1 ) 867
92
—
951

Other Income (Expense)
Earnings from consolidated subsidiaries 840
780
92
17
(1,729 ) —
Earnings from equity investments —
—
173
—
—
173
Interest, net (191 ) 1
(253 ) (4 ) —
(447 )
Amortization of excess cost of equity investments and other, net (4 ) —
(5 ) —
—
(9 )

Income Before Income Tax 638
780
874
105
(1,729 ) 668

Income Tax Expense (132 ) —
(16 ) (3 ) —
(151 )

Net Income 506
780
858
102
(1,729 ) 517
Net Income Attributable to Noncontrolling Interests —
—
—
—
(11 ) (11 )
Net Income Attributable to Controlling Interests $ 506
$ 780
$ 858
$ 102
$ (1,740 ) $ 506

Net Income $ 506
$ 780
$ 858
$ 102
$ (1,729 ) $ 517
Total other comprehensive income (loss) 64
83
81
(5 ) (162 ) 61
Comprehensive income 570
863
939
97
(1,891 ) 578
Comprehensive income attributable to noncontrolling interests —
—
—
—
(8 ) (8 )
Comprehensive income attributable to controlling interests $ 570
$ 863
$ 939
$ 97
$ (1,899 ) $ 570

Condensed Consolidating Statements of Income and Comprehensive Income
for the Three Months Ended September 30, 2018
(In Millions, Unaudited)
Parent
Issuer and
Guarantor Subsidiary
Issuer and
Guarantor -
KMP Subsidiary
Guarantors Subsidiary
Non-Guarantors Consolidating Adjustments Consolidated KMI
Total Revenues $ —
$ —
$ 3,159
$ 385
$ (27 ) $ 3,517

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

Operating Income 18
—
806
691
—
1,515

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

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

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

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

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

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

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

Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 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 $ —
$ —
$ 8,994
$ 941
$ (78 ) $ 9,857

Operating Costs, Expenses and Other
Costs of sales —
—
2,413
117
(43 ) 2,487
Depreciation, depletion and amortization 15
—
1,531
204
—
1,750
Other operating expense 5
1
2,312
395
(35 ) 2,678
Total Operating Costs, Expenses and Other 20
1
6,256
716
(78 ) 6,915

Operating (Loss) Income (20 ) (1 ) 2,738
225
—
2,942

Other Income (Expense)
Earnings from consolidated subsidiaries 2,579
2,438
226
53
(5,296 ) —
Earnings from equity investments —
—
526
—
—
526
Interest, net (575 ) (4 ) (761 ) (19 ) —
(1,359 )
Amortization of excess cost of equity investments and other, net (11 ) —
(13 ) (2 ) —
(26 )

Income Before Income Tax 1,973
2,433
2,716
257
(5,296 ) 2,083

Income Tax Expense (393 ) (2 ) (58 ) (18 ) —
(471 )

Net Income 1,580
2,431
2,658
239
(5,296 ) 1,612
Net Income Attributable to Noncontrolling Interests —
—
—
—
(32 ) (32 )
Net Income Attributable to Controlling Interests $ 1,580
$ 2,431
$ 2,658
$ 239
$ (5,328 ) $ 1,580

Net Income $ 1,580
$ 2,431
$ 2,658
$ 239
$ (5,296 ) $ 1,612
Total other comprehensive (loss) income (54 ) (66 ) (75 ) 30
107
(58 )
Comprehensive income 1,526
2,365
2,583
269
(5,189 ) 1,554
Comprehensive income attributable to noncontrolling interests —
—
—
—
(28 ) (28 )
Comprehensive income attributable to controlling interests $ 1,526
$ 2,365
$ 2,583
$ 269
$ (5,217 ) $ 1,526

Condensed Consolidating Statements of Income and Comprehensive Income
for the Nine Months Ended September 30, 2018
(In Millions, Unaudited)
Parent
Issuer and
Guarantor Subsidiary
Issuer and
Guarantor -
KMP Subsidiary
Guarantors Subsidiary
Non-Guarantors Consolidating Adjustments Consolidated KMI
Total Revenues $ —
$ —
$ 9,286
$ 1,170
$ (93 ) $ 10,363

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

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

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

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

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

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

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

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

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

Condensed Consolidating Balance Sheets as of September 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
$ —
$ —
$ 239
$ —
$ 241
Other current assets - affiliates 5,615
4,253
28,568
1,063
(39,499 ) —
All other current assets 121
40
1,781
201
(19 ) 2,124
Property, plant and equipment, net 236
—
30,725
6,973
—
37,934
Investments 664
—
7,625
98
—
8,387
Investments in subsidiaries 45,755
42,907
4,514
4,401
(97,577 ) —
Goodwill 13,789
22
5,165
2,988
—
21,964
Notes receivable from affiliates 920
20,334
481
1,241
(22,976 ) —
Deferred income taxes 2,757
—
—
—
(1,433 ) 1,324
Other non-current assets 686
279
3,878
469
(355 ) 4,957
Total assets $ 70,545
$ 67,835

$ 82,737

$ 17,673

$ (161,859 )
$ 76,931

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Liabilities
Current portion of debt $ 2,381
$ 1,835
$ 30
$ 160
$ —
$ 4,406
Other current liabilities - affiliates 18,152
14,212
6,101
1,034
(39,499 ) —
All other current liabilities 427
142
1,495
367
(11 ) 2,420
Long-term debt 13,259
15,197
3,009
646
—
32,111
Notes payable to affiliates 1,644
448
20,529
355
(22,976 ) —
Deferred income taxes —
—
556
877
(1,433 ) —
All other long-term liabilities and deferred credits 1,049
30
1,202
801
(363 ) 2,719
Total liabilities 36,912
31,864

32,922

4,240

(64,282 )
41,656

Redeemable noncontrolling interest —
—
801
—
—
801
Stockholders’ equity
Total KMI equity 33,633
35,971
49,014
13,433
(98,418 ) 33,633
Noncontrolling interests —
—
—
—
841
841
Total stockholders’ equity 33,633
35,971

49,014

13,433

(97,577 )
34,474
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity $ 70,545
$ 67,835

$ 82,737

$ 17,673

$ (161,859 )
$ 76,931

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 Nine Months Ended September 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 $ (2,666 ) $ 3,126
$ 10,978
$ 299
$ (8,616 ) $ 3,121

Cash flows from investing activities
Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments (Note 2) —
—
—
(28 ) —
(28 )
Acquisitions of assets and investments —
—
(3 ) —
—
(3 )
Capital expenditures (27 ) —
(1,325 ) (367 ) —
(1,719 )
Proceeds from sales of equity investments —
—
108
—
—
108
Contributions to investments (128 ) —
(1,018 ) (2 ) —
(1,148 )
Distributions from equity investments in excess of cumulative earnings 1,315
—
197
—
(1,305 ) 207
Funding to affiliates (4,604 ) (255 ) (7,583 ) (649 ) 13,091
—
Loans to related party —
—
(23 ) —
—
(23 )
Other, net 7
—
(5 ) (6 ) —
(4 )
Net cash used in investing activities (3,437 ) (255 )
(9,652 )
(1,052 )
11,786

(2,610 )

Cash flows from financing activities
Issuances of debt 5,027
—
—
91
—
5,118
Payments of debt (4,928 ) (1,300 ) (8 ) (67 ) —
(6,303 )
Debt issue costs (8 ) —
—
(1 ) —
(9 )
Cash dividends - common shares (1,593 ) —
—
—
—
(1,593 )
Repurchases of common shares (2 ) —
—
—
—
(2 )
Funding from affiliates 7,629
2,145
2,744
573
(13,091 ) —
Contributions from investment partner —
—
135
—
—
135
Contributions from parents —
—
3
—
(3 ) —
Contributions from noncontrolling interests —
—
—
—
3
3
Distributions to parents —
(3,716 ) (4,200 ) (2,931 ) 10,847
—
Distribution to noncontrolling interests - KML distribution of the TMPL Sale proceeds —
—
—
—
(879 ) (879 )
Distributions to noncontrolling interests - other —
—
—
—
(42 ) (42 )
Other, net (28 ) —
—
—
—
(28 )
Net cash provided by (used in) financing activities 6,097
(2,871 )
(1,326 )
(2,335 )
(3,165 )
(3,600 )

Effect of exchange rate changes on cash, cash equivalents and restricted deposits —
—
—
26
—
26

Net decrease in Cash, Cash Equivalents and Restricted Deposits (6 ) —

—

(3,062 )
5

(3,063 )
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
$ —

$ —

$ 266

$ —

$ 268

Condensed Consolidating Statements of Cash Flows for the Nine Months Ended September 30, 2018
(In Millions, Unaudited)
Parent
Issuer and
Guarantor Subsidiary
Issuer and
Guarantor -
KMP Subsidiary
Guarantors Subsidiary
Non-Guarantors Consolidating Adjustments Consolidated KMI
Net cash (used in) provided by operating activities $ (2,355 ) $ 2,879
$ 8,204
$ 869
$ (6,222 ) $ 3,375

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

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

(3,473 ) (853 )

Effect of exchange rate changes on cash, cash equivalents and restricted deposits —
—
—
26
—
26

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits (2 )
44

—

3,191

1
3,234
Cash, Cash Equivalents, and Restricted Deposits, beginning of period 3
1
—
323
(1 ) 326
Cash, Cash Equivalents, and Restricted Deposits, end of period $ 1

$ 45

$ —

$ 3,514

$ —
$ 3,560

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~~2019 Form 10-K.

~~Pending~~ Sale of U.S. Portion of Cochin Pipeline and KML

On ~~August 21,~~December 16, 2019, we ~~announced an agreement to sell~~closed on two cross-conditional transactions resulting in the sale of the U.S. portion of the Cochin Pipeline ~~to Pembina Pipeline Corporation (Pembina) for $1.546 billion in cash. KML also announced that it had reached an agreement with Pembina under which Pembina had agreed to acquire~~and all of the outstanding ~~common~~ equity of KML, including our 70% interest, ~~subject~~ to Pembina Pipeline Corporation (Pembina) (together, the ~~terms of the arrangement agreement between KML~~“KML and ~~Pembina. Subject to and upon closing, KML shareholders will receive 0.3068 shares of Pembina common stock for each share of KML common stock whereby we will receive~~U.S. Cochin Sale”). We received approximately 25 million shares of Pembina common ~~stock, with a pre-tax value of approximately $927 million as of September 30, 2019,~~equity for our ~~70%~~ interest in KML. ~~We expect~~On January 9, 2020, we sold our Pembina shares and received proceeds of approximately $907 million ($764 million after tax) which were used to ~~ultimately convert these shares into cash~~repay maturing debt. The assets sold were part of our Natural Gas Pipelines and ~~plan~~Terminals business segments.

COVID-19

The COVID-19 pandemic-related reduction in energy demand and the sharp decline in commodity prices related to ~~do so~~the combined impact of falling demand and recent increases in ~~an opportunistic~~production from Organization of Petroleum Exporting Countries (OPEC) members and ~~non-disruptive manner. We intend to use a portion of the proceeds from these transactions to pay down debt to maintain our leverage targets~~other international suppliers has caused significant disruptions and use the remainder to invest in attractive projects and/or opportunistically repurchase common shares under our buy-back program. The closing of the two transactions are cross-conditioned upon each other, subject to KML’s shareholder and applicable regulatory approvals, and are expected to close latevolatility in the ~~fourth quarter of 2019 or in~~global marketplace during the first quarter of ~~2020.~~

~~Sale of Trans Mountain Pipeline System and Its Expansion Project~~

~~On August 31, 2018, KML completed~~2020, which have adversely affected our business. In response to COVID-19, governments around the ~~sale~~world have implemented increasingly stringent measures to help reduce the spread of the ~~TMPL,~~virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures. These measures have adversely affected the ~~TMEP, Puget Sound pipeline system~~economies 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~~financial markets 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). We recognized a pre-tax gain from the TMPL Sale of $622 million within “(Gain) loss on divestituresU.S. and ~~impairments, net”~~many other countries, resulting in ~~our accompanying consolidated statements of income during both the three~~an economic downturn that has negatively impacted global demand and nine months ended September 30, 2018. 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 “Proceeds from the TMPL Sale, net of cash disposed and working capital adjustments”prices for the ~~nine months ended September 30, 2019~~products handled by our pipelines, terminals, shipping vessels and ~~for which we had substantially accrued for as of December 31, 2018.~~

~~On January 3, 2019, KML distributed~~other facilities. There is significant uncertainty regarding 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),length and ~~most of our approximate 70% portion~~impact of the ~~net proceeds of $1.9 billion (C$2.5 billion) (after Canadian tax) were used~~virus on the energy industry and potential impacts 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.~~

~~2019 Outlook~~business. For further discussion, see Part II, Item 1A. “Risk Factors.”

WeEvents as described above resulted in decreases of current and expected long-term crude oil and NGL sale prices we expect ~~DCF for 2019~~ to ~~be slightly below our $5.0 billion budget primarily due~~realize along with significant reductions to the ~~delay in ELC’s in-service date (the first~~market capitalization of ~~ten liquefaction units went into commercial service in late September 2019), lower commodity prices~~many oil and ~~volumes impacting~~gas producing companies. These events triggered us to review the carrying value of our long-lived assets of our CO₂ business segment and conduct interim tests of the ~~impact~~recoverability of ~~501-G settlements, partially offset by the strong performance in the West Region of~~goodwill for our CO₂ and Natural Gas Pipelines ~~business segment and lower interest expense. For 2019, we also budgeted to invest $3.1 billion~~Non-Regulated reporting units as of March 31, 2020. Our evaluation resulted in ~~growth projects and contributions to joint ventures. We now expect to be slightly below this amount primarily due to lower capital expenditures~~the recognition of a $350 million impairment for long-lived assets in our CO₂ business ~~segment.~~segment and a goodwill impairment of $600 million. For a further discussion of these impairments and our risk for future impairments, see Note 2, “Impairments.”

2020 Outlook

In December 2019, we announced our 2020 budget guidance in which we expected to declare dividends of $1.25 per share, a 25% increase from the 2019 declared dividends of $1.00 per share, and to generate approximately $5.1 billion of DCF, or $2.24 of DCF per share, and $7.6 billion of Adjusted EBITDA. On April 22, 2020, we announced an update to our outlook for 2020 to include estimated impacts of the economic downturn resulting from COVID-19 and unfavorable commodity demand and prices. Because of the current environment, we now expect DCF to be below budget by approximately 10% and Adjusted EBITDA to be below budget by approximately 8%. As a result, we now expect to end 2020 with a Net Debt-to-Adjusted EBITDA ratio of approximately 4.6 times, consistent with our long-term objective of around 4.5 times.

In addition, market conditions have resulted in a number of planned expansion projects no longer meeting our internal return thresholds, and we therefore reduced our budget of $2.4 billion by approximately $700 million. With this reduction, DCF less expansion capital expenditures is improved by approximately $200 million compared to budget, helping to keep our balance sheet strong. In addition, to help preserve flexibility and maintain balance sheet strength, our board of directors declared a dividend of $0.2625 per share, or $1.05 per share annualized. This represents a 5% increase over last quarter rather than the previously budgeted dividend of $0.3125, which would have been a 25% increase. We expect that our 2020 dividend payments as well as our 2020 discretionary spending will be funded with internally generated cash flow.

Considerable uncertainty exists with respect to the future pace and extent of a global economic recovery from the effects of the COVID-19 pandemic. In addition to the below discussions included in “—Results of Operations—Consolidated Earnings

Results” and “—Segment Earnings Results,” the following table provides assumptions and sensitivities for impacts on our business that may be affected by that uncertainty.



Remaining 9 Months Commodity Volume and Price Assumptions	Sensitivity Range	Potential Impact to 2020 Adjusted EBITDA and DCF (in millions, by segment)
		Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Total
Natural Gas Gathering and Processing Volumes
3,325 Bbtu/d	+/- 5%	$	23							$	23
Refined Products Volumes (gasoline, diesel and jet fuel)
1,452 MBbl/d for Products Pipelines (the following apply to both the Products Pipelines and Terminals segments)(a)	+/- 5%			$	26	$	12			$	38
Qtr 2: 40% - 45% reduction from budgeted quarter amount
Qtr 3: 10% - 12% reduction from budgeted quarter amount
Qtr 4: 5% - 6% reduction from budgeted quarter amount
Crude Oil & Condensate Pipeline Volumes
587 MBbl/d	+/- 5%			$	11					$	11
Crude Oil Production Volumes
46 MBbl/d, gross (33 MBbl/d, net)	+/- 5%							$	12	$	12
Crude Oil Price
$30/bbl	+/- $1/bbl WTI	$	0.2	$	0.9			$	0.5	$	1.6
NGL to Crude Oil Price Ratio
Natural Gas Pipelines 49% and CO₂ 25%	+/- 1%	$	0.1					$	0.4	$	0.5
								Potential Impact to 2020 DCF (in millions)
3-Month LIBOR Interest Rate(b)								Total
0.64%	+/- 10-bp							$	2.4

Purpose of Outlook Assumptions and Sensitivity:
The above table provides key assumptions used in our 2020 forecast for the remaining 9 months of 2020 to incorporate the estimated impact of COVID-19 and oil price decline. It also provides estimated financial impacts to 2020 Adjusted EBITDA and DCF for potential changes in those assumptions. These sensitivities are general estimates of anticipated impacts on our business segments and overall business of changes relative to our assumptions; the impact of actual changes may vary significantly depending on the affected asset, product and contract.

Notes:


(a)	Potential impact to 2020 Adjusted EBITDA for Terminals includes sensitivity to changes in petroleum coke volume.

(b)

As of March 31, 2020, we had approximately $8.0 billion of fixed-to-floating interest rate swaps on our long-term debt. In March 2020, we fixed the LIBOR component on $2.5 billion of these swaps through the end of 2020 only. As a result, approximately 17% of the principal amount of our debt balance as of March 31, 2020 was 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.

We do not provide budgeted net income attributable to common stockholders or budgeted net income, the GAAP financial measures most directly comparable to the non-GAAP financial measures of DCF and Adjusted EBITDA, respectively, due to the impracticality of quantifying certain components required by GAAP such as: unrealized gains and losses on derivatives marked-to-market and potential changes in estimates for certain contingent liabilities. See “—Results of Operations—Overview—Non-GAAP Financial Measures” below.

Our updated expectations for 2020 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statements. Please read Part II, Item 1A. “Risk Factors” below and “Information Regarding Forward-Looking Statements” at the beginning of this report for more information. Furthermore, we disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA ~~Net Income~~(as presented in Note 7, “Reportable Segments”), net (loss) income and ~~Net Income Available~~net (loss) income attributable to ~~Common Stockholders,~~Kinder Morgan, Inc., along with the non-GAAP financial measures of Adjusted Earnings and DCF, both in the aggregate and per share for each, ~~and~~ Adjusted Segment EBDA, Adjusted EBITDA, Net Debt and Net Debt to Adjusted EBITDA.

GAAP ~~Performance~~Financial Measures

The Consolidated Earnings Results for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2020 and 2019 ~~and 2018~~ present Segment EBDA, ~~Net Income~~net (loss) income and ~~Net Income Available~~net (loss) income attributable to ~~Common Stockholders~~Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. 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 and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges 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.

Non-GAAP ~~Performance~~Financial Measures

Our non-GAAP ~~performance~~financial measures described below should not be considered alternatives to GAAP net (loss) income or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP ~~performance~~financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP ~~performance~~financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP ~~performance~~financial 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.

The format of the reconciliations between our non-GAAP and comparable GAAP financial measures has been modified to provide further transparency and information on our business performance. The modified reconciliations also include the non-GAAP financial measures of Adjusted Earnings, both in aggregate and per share, and Adjusted EBITDA. The amounts and key components of our non-GAAP financial measures remain unchanged from prior periods.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP ~~performance~~financial measures, are items that are required by GAAP to be reflected in net (loss) 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). See tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP ~~Performance~~Financial Measures—Reconciliation of Net (Loss) Income (GAAP) to Adjusted EBITDA” and “—Non-GAAP ~~Performance~~Financial Measures—Supplemental Information” below. In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting ~~Net Income Available~~net (loss) income attributable to ~~Common stockholders~~Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of the Company’s ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is net (loss) income ~~available~~attributable to ~~common stockholders.~~Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per common share. See “—Non-GAAP ~~Performance~~Financial Measures—Reconciliation of Net (Loss) Income ~~Available~~Attributable to ~~Common Stockholders~~Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting ~~Net Income Available~~net (loss) income attributable to ~~Common Stockholders~~Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, 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. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is ~~Net Income Available~~net (loss) income attributable to ~~Common Stockholders.~~Kinder Morgan, Inc. DCF per common share is DCF divided by average outstanding common shares, including restricted stock awards that participate in common share dividends. See “—Non-GAAP ~~Performance~~Financial Measures—Reconciliation of Net (Loss) Income ~~Available~~Attributable to ~~Common Stockholders~~Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” and “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a a useful performance metric because it provides management 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 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 Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items, our share of unconsolidated joint venture DD&A and income tax expense (net of our partners’ share of consolidating joint venture DD&A and income tax expense), and net income attributable to noncontrolling interests that is further adjusted for KML noncontrolling interests (net of its applicable Certain Items). for the periods presented through KML’s sale on December 15, 2019. Adjusted EBITDA is used by management and external users, ~~as an additional performance measure.~~in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is ~~Net Income. (See~~net (loss) income. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP ~~Performance~~Financial Measures—Reconciliation of Net (Loss) Income (GAAP) to Adjusted EBITDA” ~~below)~~below.

~~For segment reporting purposes, effective January~~Net Debt

Net Debt is a non-GAAP financial measure that is useful to investors and other users of our financial information in evaluating our leverage. Net Debt is calculated by subtracting from debt (i) cash and cash equivalents (which, as of March 31, 2020, the cash and cash equivalents component of Net Debt includes “Restricted deposits” held in escrow that were used on April 1, ~~2019, certain assets were transferred among our business segments. As a result, individual segment results~~2020 for the ~~three and nine months ended September 30, 2018 have been reclassified to conform to~~repayment of senior notes plus associated accrued interest); (ii) the ~~current presentation~~preferred interest in the ~~following MD&A tables. The reclassified amounts were not material.~~general partner of KMP (which was redeemed in January 2020); (iii) debt fair value adjustments; and (iv) the foreign exchange impact on Euro-denominated bonds for which we have entered into currency swaps. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents. Our Net Debt-to-Adjusted EBITDA ratio was 4.3 as of March 31, 2020.

Consolidated Earnings Results (GAAP)

The following tables summarize the key components of our consolidated earnings results.

Three Months Ended September 30,
2019 2018 Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines $ 1,092
$ 930
$ 162
17 %
Products Pipelines 325
325
—
— %
Terminals 295
301
(6 ) (2 )%
CO₂
164
205
(41 ) (20 )%
Kinder Morgan Canada(b) —
654
(654 ) (100 )%
Total Segment EBDA 1,876
2,415
(539 ) (22 )%
DD&A (578 ) (569 ) (9 ) (2 )%
Amortization of excess cost of equity investments (21 ) (21 ) —
— %
General and administrative and corporate charges (162 ) (151 ) (11 ) (7 )%
Interest, net (447 ) (473 ) 26
5 %
Income before income taxes 668
1,201
(533 ) (44 )%
Income tax expense (151 ) (196 ) 45
23 %
Net income 517
1,005
(488 ) (49 )%
Net income attributable to noncontrolling interests (11 ) (273 ) 262
96 %
Net income attributable to Kinder Morgan, Inc. 506
732
(226 ) (31 )%
Preferred stock dividends —
(39 ) 39
100 %
Net income available to common stockholders $ 506
$ 693
$ (187 ) (27 )%


	Nine Months Ended September 30,											Three Months Ended March 31,
	2019			2018			Earnings increase/(decrease)					2020			2019			Earnings increase/(decrease)
	(In millions, except percentages)											(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines	$	3,383		$	2,368		$	1,015		43	%	$	1,196		$	1,203		$	(7	)	(1	)%
Products Pipelines	908			912			(4		)	—	%	269			276			(7		)	(3	)%
Terminals	884			872			12			1	%	257			299			(42		)	(14	)%
CO₂	558			561			(3		)	(1	)%	(755		)	198			(953		)	(481	)%
Kinder Morgan Canada(b)	(2		)	746			(748		)	(100	)%	—			(2		)	2			100	%
Total Segment EBDA	5,731			5,459			272			5	%	967			1,974			(1,007		)	(51	)%
DD&A	(1,750		)	(1,710		)	(40		)	(2	)%	(565		)	(593		)	28			5	%
Amortization of excess cost of equity investments	(61		)	(77		)	16			21	%	(32		)	(21		)	(11		)	(52	)%
General and administrative and corporate charges	(478		)	(485		)	7			1	%	(165		)	(161		)	(4		)	(2	)%
Interest, net	(1,359		)	(1,456		)	97			7	%	(436		)	(460		)	24			5	%
Income before income taxes	2,083			1,731			352			20	%
(Loss) income before income taxes												(231		)	739			(970		)	(131	)%
Income tax expense	(471		)	(314		)	(157		)	(50	)%	(60		)	(172		)	112			65	%
Net income	1,612			1,417			195			14	%
Net (loss) income												(291		)	567			(858		)	(151	)%
Net income attributable to noncontrolling interests	(32		)	(302		)	270			89	%	(15		)	(11		)	(4		)	(36	)%
Net income attributable to Kinder Morgan, Inc.	1,580			1,115			465			42	%
Preferred stock dividends	—			(117		)	117			100	%
Net income available to common stockholders	$	1,580		$	998		$	582		58	%
Net (loss) income attributable to Kinder Morgan, Inc.												(306		)	556			(862		)	(155	)%

_______


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


(b)	As2019 amount represents a ~~result of~~final working capital adjustment on the TMPL ~~Sale on August 31, 2018, this segment does not have results of operations on a prospective basis.~~sale.

In(Loss) income before income taxes decreased $970 million in 2020 compared to 2019. The decrease was due primarily to a non-cash impairment of goodwill associated with our ~~discussions~~CO₂ reporting unit and non-cash impairments of certain oil and gas producing assets in our CO₂business segment, and to a much lesser extent, assets in our Products Pipelines business segment. The decrease was further impacted by lower earnings from all of our business segments primarily attributable to the impact of of the ~~operating results~~KML and U.S. Cochin Sale in the fourth quarter of ~~individual businesses that follow, we generally identify~~2019 as well as sharp declines in commodity prices impacting the ~~important fluctuations between periods that are attributable to dispositions~~Products Pipelines business segment, partially offset by the benefit of expansion projects in our Natural Gas Pipelines business segment and ~~acquisitions separately from those that are attributable to businesses owned in both periods.~~by lower interest expense and DD&A expense.

Certain Items Affecting Consolidated Earnings Results

Three Months Ended September 30,
2019 2018
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts
increase/(decrease)
(In millions)
Segment EBDA
Natural Gas Pipelines $ 1,092
$ (2 ) $ 1,090
$ 930
$ 75
$ 1,005
$ 85
Products Pipelines 325
11
336
325
(12 ) 313
23
Terminals 295
—
295
301
(2 ) 299
(4 )
CO₂
164
(15 ) 149
205
28
233
(84 )
Kinder Morgan Canada —
—
—
654
(622 ) 32
(32 )
Total Segment EBDA(a) 1,876
(6 ) 1,870
2,415
(533 ) 1,882
(12 )
DD&A and amortization of excess cost of equity investments (599 ) —
(599 ) (590 ) —
(590 ) (9 )
General and administrative and corporate charges(a) (162 ) 5
(157 ) (151 ) 8
(143 ) (14 )
Interest, net(a) (447 ) (5 ) (452 ) (473 ) —
(473 ) 21
Income before income taxes 668
(6 ) 662
1,201
(525 ) 676
(14 )
Income tax expense(b) (151 ) 8
(143 ) (196 ) 45
(151 ) 8
Net income 517
2
519
1,005
(480 ) 525
(6 )
Net income attributable to noncontrolling interests(a) (11 ) —
(11 ) (273 ) 256
(17 ) 6
Preferred stock dividends —
—
—
(39 ) —
(39 ) 39
Net income available to common stockholders $ 506
$ 2
$ 508
$ 693
$ (224 ) $ 469
$ 39


	Nine Months Ended September 30,																					Three Months Ended March 31,
	2019									2018												2020									2019
	GAAP			Certain Items			Adjusted			GAAP			Certain Items			Adjusted			Adjusted amounts increase/(decrease)			GAAP			Certain Items			Adjusted			GAAP			Certain Items			Adjusted			Adjusted amounts increase/(decrease) to earnings
	(In millions)																					(In millions)
Segment EBDA
Natural Gas Pipelines	$	3,383		$	(21	)	$	3,362		$	2,368		$	709		$	3,077		$	285		$	1,196		$	(17	)	$	1,179		$	1,203		$	(2	)	$	1,201		$	(22	)
Products Pipelines	908			28			936			912			18			930			6			269			4			273			276			17			293			(20		)
Terminals	884			—			884			872			33			905			(21		)	257			—			257			299			—			299			(42		)
CO₂	558			(36		)	522			561			130			691			(169		)	(755		)	930			175			198			(9		)	189			(14		)
Kinder Morgan Canada	(2		)	2			—			746			(622		)	124			(124		)	—			—			—			(2		)	2			—			—
Total Segment EBDA(a)	5,731			(27		)	5,704			5,459			268			5,727			(23		)	967			917			1,884			1,974			8			1,982			(98		)
DD&A and amortization of excess cost of equity investments	(1,811		)	—			(1,811		)	(1,787		)	—			(1,787		)	(24		)	(597		)	—			(597		)	(614		)	—			(614		)	17
General and administrative and corporate charges(a)	(478		)	11			(467		)	(485		)	18			(467		)	—			(165		)	25			(140		)	(161		)	3			(158		)	18
Interest, net(a)	(1,359		)	(6		)	(1,365		)	(1,456		)	34			(1,422		)	57			(436		)	1			(435		)	(460		)	2			(458		)	23
Income before income taxes	2,083			(22		)	2,061			1,731			320			2,051			10
(Loss) income before income taxes																						(231		)	943			712			739			13			752			(40		)
Income tax expense(b)	(471		)	15			(456		)	(314		)	(149		)	(463		)	7			(60		)	(96		)	(156		)	(172		)	2			(170		)	14
Net income	1,612			(7		)	1,605			1,417			171			1,588			17
Net (loss) income																						(291		)	847			556			567			15			582			(26		)
Net income attributable to noncontrolling interests(a)	(32		)	(1		)	(33		)	(302		)	248			(54		)	21			(15		)	—			(15		)	(11		)	—			(11		)	(4		)
Preferred stock dividends	—			—			—			(117		)	—			(117		)	117
Net income available to common stockholders	$	1,580		$	(8	)	$	1,572		$	998		$	419		$	1,417		$	155
Net (loss) income attributable to Kinder Morgan, Inc.																						$	(306	)	$	847		$	541		$	556		$	15		$	571		$	(30	)

_______


(a)	For a more ~~detail~~detailed discussion of these Certain Items, see the footnotes to the tables within “—Segment Earnings Results” and “—General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests” below.


(b)	The combined net effect of the Certain Items represents the income tax provision on Certain Items plus discrete income tax items.

~~After giving effect~~Net (loss) income attributable to Kinder Morgan, Inc. adjusted for Certain Items ~~which are discussed~~(Adjusted Earnings) decreased by $30 million in ~~more detail~~2020 compared to 2019. Adjusted Segment EBDA was negatively impacted by the KML and U.S. Cochin Sale and sharp declines in commodity prices impacting our Products Pipelines business segment, partially offset by earnings from expansion projects in our Natural Gas Pipelines business segment. Reduced DD&A, general and administrative and corporate charges, interest and income tax expense partially offset the ~~discussions that follow, the remaining~~ decrease in income before income taxes from the prior year quarter was $14 million and the remaining increase in income before income taxes from the prior year-to-date period was $10 million. The third quarter decrease from 2018 is primarily attributable to lower earnings from our CO₂~~business segment, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale, and increased~~Adjusted Segment EBDA. Reduced general and administrative and corporate charges and ~~DD&A expense, partially offset by increased performance from our Natural Gas Pipelines and Products Pipelines business segments and decreased~~ interest expense ~~net. The year-to-date increase from 2018 is~~were primarily ~~attributable~~due to ~~increased performance from our Natural Gas Pipelines business segment~~the KML and ~~decreased interest expense, net partially offset by lower earnings from our CO~~₂~~and Terminals business segments, lower earnings from our Kinder Morgan Canada business segment as a result of the TMPL Sale and increased DD&A expense.~~Cochin Sale.

Non-GAAP ~~Performance~~Financial Measures

Reconciliation of Net (Loss) Income ~~Available~~Attributable to ~~Common Stockholders~~Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions)												(In millions)
Net income available to common stockholders (GAAP)	$	506		$	693		$	1,580		$	998
Net (loss) income attributable to Kinder Morgan, Inc. (GAAP)													$	(306	)	$	556
Total Certain Items	2			(224		)	(8		)	419			847			15
Adjusted Earnings(a)	508			469			1,572			1,417			541			571
DD&A and amortization of excess cost of equity investments for DCF(b)	694			682			2,093			2,056			691			708
Income tax expense for DCF(a)(b)	164			169			521			512			181			195
Cash taxes(c)	(12		)	(14		)	(76		)	(60		)	(3		)	(13		)
Sustaining capital expenditures(c)	(173		)	(194		)	(477		)	(471		)	(141		)	(115		)
Other items(d)	(41		)	(19		)	6			3			(8		)	25
DCF	$	1,140		$	1,093		$	3,639		$	3,457		$	1,261		$	1,371

Adjusted Segment EBDA to Adjusted EBITDA to DCF


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions, except per share amounts)												(In millions, except per share amounts)
Natural Gas Pipelines	$	1,090		$	1,005		$	3,362		$	3,077		$	1,179		$	1,201
Products Pipelines	336			313			936			930			273			293
Terminals	295			299			884			905			257			299
CO₂	149			233			522			691			175			189
Kinder Morgan Canada	—			32			—			124
Adjusted Segment EBDA(a)	1,870			1,882			5,704			5,727			1,884			1,982
General and administrative and corporate charges(a)	(157		)	(143		)	(467		)	(467		)	(140		)	(158		)
KMI’s share of joint venture DD&A and income tax expense(a)(e)	123			120			368			355			119			126
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)(a)	(2		)	(2		)	(7		)	(9		)	(15		)	(3		)
Adjusted EBITDA	1,834			1,857			5,598			5,606			1,848			1,947
Interest, net(a)	(452		)	(473		)	(1,365		)	(1,422		)	(435		)	(458		)
Cash taxes(c)	(12		)	(14		)	(76		)	(60		)	(3		)	(13		)
Sustaining capital expenditures(c)	(173		)	(194		)	(477		)	(471		)	(141		)	(115		)
KML noncontrolling interests DCF adjustments(f)	(16		)	(25		)	(47		)	(82		)	—			(15		)
Preferred stock dividends	—			(39		)	—			(117		)
Other items(d)	(41		)	(19		)	6			3			(8		)	25
DCF	$	1,140		$	1,093		$	3,639		$	3,457		$	1,261		$	1,371

Adjusted Earnings per common share	$	0.22		$	0.21		$	0.69		$	0.64		$	0.24		$	0.25
Weighted average common shares outstanding for dividends(g)	2,277			2,218			2,276			2,217			2,277			2,275
DCF per common share	$	0.50		$	0.49		$	1.60		$	1.56		$	0.55		$	0.60
Declared dividends per common share	$	0.25		$	0.20		$	0.75		$	0.60		$	0.2625		$	0.25

_______


(a)	Amounts are adjusted for Certain Items.


(b)	Includes KMI’s share of DD&A or income tax expense from joint ventures as applicable. 2019 amounts are also net of DD&A or income tax expense attributable to KML noncontrolling ~~interests, as applicable.~~interests. See tables included in “—Supplemental Information” below.


(c)	Includes KMI’s share of cash taxes or sustaining capital expenditures from joint ventures, as applicable. See tables included in “—Supplemental Information” below.


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


(e)	KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.


(f)	~~The~~2019 amount represents the combined net income, DD&A and income tax expense adjusted for Certain Items, as applicable, attributable to KML noncontrolling interests. See table included in “—Supplemental Information” below.


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

Reconciliation of Net (Loss) Income (GAAP) to Adjusted EBITDA

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
(In millions)
Net income (GAAP) $ 517
$ 1,005
$ 1,612
$ 1,417
Certain Items:
Fair value amortization (7 ) (7 ) (22 ) (27 )
Legal and environmental reserves 11
16
11
53
Change in fair market value of derivative contracts(a) (14 ) 47
(22 ) 190
(Gain) loss on divestitures and impairments, net —
(582 ) (5 ) 208
Hurricane recoveries, net —
(1 ) —
(25 )
Refund and reserve adjustment of taxes, other than income taxes —
(12 ) 17
(51 )
Income tax Certain Items 8
45
15
(149 )
Noncontrolling interests associated with Certain Items —
256
(1 ) 248
Other 4
14
(1 ) (28 )
Total Certain Items 2
(224 ) (8 ) 419
DD&A and amortization of excess cost of equity investments 599
590
1,811
1,787
Income tax expense(b) 143
151
456
463
KMI’s share of joint venture DD&A and income tax expense(b)(c) 123
120
368
355
Interest, net(b) 452
473
1,365
1,422
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(b)) (2 ) (258 ) (6 ) (257 )
Adjusted EBITDA $ 1,834
$ 1,857
$ 5,598
$ 5,606



	Three Months Ended March 31,
	2020			2019
	(In millions)
Net (loss) income (GAAP)	$	(291	)	$	567
Certain Items:
Fair value amortization	(8		)	(8		)
Legal, environmental and taxes other than income tax reserves	(8		)	17
Change in fair value of derivative contracts(a)	(36		)	10
Loss on impairments and divestitures, net(b)	371			2
Loss on impairment of goodwill(c)	600			—
Income tax Certain Items	(96		)	2
Other	24			(8		)
Total Certain Items	847			15
DD&A and amortization of excess cost of equity investments	597			614
Income tax expense(d)	156			170
KMI’s share of joint venture DD&A and income tax expense(d)(e)	119			126
Interest, net(d)	435			458
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(d))	(15		)	(3		)
Adjusted EBITDA	$	1,848		$	1,947

______


(a)	Gains or losses are reflected in our DCF when realized.

(b)

2020 amount primarily includes: (i) pre-tax non-cash losses of $350 million and $21 million for asset impairments related to oil and gas producing assets in our CO₂ business segment driven by low oil price and assets in our Products Pipelines business segment, respectively, and are reported within “Loss on impairments and divestitures, net” on our Consolidated Earnings Results (GAAP) table above.


(c)	2020 amount represents a non-cash impairment of goodwill associated with our CO₂reporting unit.


(d)	Amounts are adjusted for Certain Items. See tables included in “—Supplemental Information” and “—General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.


~~(c)~~(e)	KMI’s share of unconsolidated joint venture DD&A and income tax expense, net of consolidating joint venture partners’ share of DD&A.

Supplemental Information


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions)												(In millions)
DD&A (GAAP)	$	578		$	569		$	1,750		$	1,710		$	565		$	593
Amortization of excess cost of equity investments (GAAP)	21			21			61			77			32			21
DD&A and amortization of excess cost of equity investments	599			590			1,811			1,787			597			614
Our share of joint venture DD&A	100			98			297			293			94			99
DD&A attributable to KML noncontrolling interests	(5		)	(6		)	(15		)	(24		)	—			(5		)
DD&A and amortization of excess cost of equity investments for DCF	$	694		$	682		$	2,093		$	2,056		$	691		$	708

Income tax expense (GAAP)	$	151		$	196		$	471		$	314		$	60		$	172
Certain Items	(8		)	(45		)	(15		)	149			96			(2		)
Income tax expense(a)	143			151			456			463			156			170
Our share of taxable joint venture income tax expense(a)	23			22			71			62			25			27
Income tax expense attributable to KML noncontrolling interests(a)	(2		)	(4		)	(6		)	(13		)	—			(2		)
Income tax expense for DCF(a)	$	164		$	169		$	521		$	512		$	181		$	195

Net income attributable to KML noncontrolling interests	$	9		$	270		$	25		$	291		$	—		$	8
KML noncontrolling interests associated with Certain Items	—			(255		)	1			(246		)	—			—
KML noncontrolling interests(a)	9			15			26			45			—			8
DD&A attributable to KML noncontrolling interests	5			6			15			24			—			5
Income tax expense attributable to KML noncontrolling interests(a)	2			4			6			13			—			2
KML noncontrolling interests DCF adjustments(a)	$	16		$	25		$	47		$	82		$	—		$	15

Net income attributable to noncontrolling interests (GAAP)	$	11		$	273		$	32		$	302		$	15		$	11
Less: KML noncontrolling interests(a)	9			15			26			45			—			8
Net income attributable to noncontrolling interests (net of KML noncontrolling interests(a))	2			258			6			257			15			3
Noncontrolling interests associated with Certain Items	—			(256		)	1			(248		)	—			—
Net income attributable to noncontrolling interests (net of KML noncontrolling interests and Certain Items)	$	2		$	2		$	7		$	9		$	15		$	3

Additional joint venture information:
Our share of joint venture DD&A	$	100		$	98		$	297		$	293		$	94		$	99
Our share of joint venture income tax expense(a)	23			22			71			62			25			27
Our share of joint venture DD&A and income tax expense(a)	$	123		$	120		$	368		$	355		$	119		$	126

Our share of taxable joint venture cash taxes	$	(16	)	$	(12	)	$	(50	)	$	(50	)	$	(4	)	$	—

Our share of joint venture sustaining capital expenditures	$	(35	)	$	(37	)	$	(85	)	$	(77	)	$	(26	)	$	(19	)

______


(a)	Amounts are adjusted for Certain Items.

Segment Earnings Results

Natural Gas Pipelines


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	1,934		$	2,192		$	6,103		$	6,425		$	1,875		$	2,201
Operating expenses	(993		)	(1,357		)	(3,190		)	(3,803		)	(848		)	(1,167		)
(Loss) gain on divestitures and impairments, net	—			(35		)	10			(634		)
Other income	—			—			2			1			1			1
Earnings from equity investments	141			130			431			346			164			159
Other, net	10			—			27			33			4			9
Segment EBDA	1,092			930			3,383			2,368			1,196			1,203
Certain Items(a)(b)	(2		)	75			(21)			709			(17)			(2		)
Adjusted Segment EBDA	$	1,090		$	1,005		$	3,362		$	3,077		$	1,179		$	1,201

Change from prior period	Increase/(Decrease)												Increase/(Decrease)
Adjusted revenues	$	(277	)	(13		)%	$	(332	)	(5		)%	$	(358	)	(16		)%
Adjusted Segment EBDA	85			8		%	285			9		%	(22		)	(2		)%

Volumetric data
Transport volumes (BBtu/d)(c)	37,029			32,879			35,958			32,238
Sales volumes (BBtu/d)(c)	2,647			2,615			2,435			2,517
Gathering volumes (BBtu/d)(c)	3,380			3,025			3,335			2,877
NGLs (MBbl/d)(c)	129			117			126			118
Volumetric data(c)
Transport volumes (BBtu/d)													39,095			36,044
Sales volumes (BBtu/d)													2,495			2,332
Gathering volumes (BBtu/d)													3,361			3,301
NGLs (MBbl/d)													30			32

_______

Certain Items affecting Segment EBDA

(a)

Includes revenue Certain Item amounts of ~~$(1)~~$(24) million and $8 million for ~~both three~~2020 and ~~nine months ended September 30,~~ 2019, ~~and $18 million and $9 million for the three and nine months ended September 30, 2018,~~ respectively. These Certain Item amounts are primarily related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas ~~NGL~~ and ~~crude oil~~NGL sales in the 2020 and 2019 ~~and 2018 periods, and additionally in the 2018 nine month period, to a transportation contract refund and the early termination of a long-term natural gas transportation contract.~~periods.

(b)

Includes non-revenue Certain Item amounts of ~~$(1)~~$7 million and ~~$(20)~~$(10) million for ~~the three~~2020 and ~~nine months ended September 30,~~ 2019, ~~respectively, and $57 million and $700 million for the three and nine months ended September 30, 2018,~~ respectively. ~~Three and nine month 2019 amounts are~~2020 amount is primarily related to ~~increases~~increase in expense associated with a certain EPNG litigation matter. 2019 amount is primarily related to an increase in earnings for our share of certain equity investees’ amortization of regulatory liabilities. Three and nine month 2018 amounts include a decrease in earnings of $35 million for both periods associated with a project write-off on the Utica Marcellus Texas pipeline and a decrease in earnings of $15 million for both periods associated with certain litigation matters. Nine month 2018 amount also includes (i) a $600 million non-cash loss on impairment of certain gathering and processing assets in Oklahoma; (ii) a net loss of $89 million in our equity investment in Gulf LNG Holdings Group, LLC (Gulf LNG), due to a ruling by an arbitration panel affecting a customer contract, which resulted in a non-cash impairment of our investment partially offset by our share of earnings recognized by Gulf LNG on the respective customer contract; and (iii) an increase in earnings of $41 million 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. Volumes for assets sold are excluded for all periods presented.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

Three Months Ended ~~September 30, 2019~~March 31, 2020 versus Three Months Ended ~~September 30, 2018~~March 31, 2019

Adjusted Segment EBDA
increase/(decrease)

Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Midstream $ 37
13 % $ (347 ) (24 )%
West Region 26
11 % 26
9 %
North Region 23
7 % 39
10 %
South Region (3 ) (2 )% 3
4 %
Other 2
200 % 2
200 %
Total Natural Gas Pipelines $ 85
8 % $ (277 ) (13 )%

~~Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018~~


	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)					Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Midstream	$	89		10	%	$	(552	)	(14	)%	$	(43	)	(12	)%	$	(449	)	(33	)%
East Region											20			4	%	45			8	%
West Region	90			13	%	87			9	%	1			—	%	10			3	%
North Region	106			11	%	123			10	%
South Region	(6		)	(1	)%	10			4	%
Other	6			150	%	6			150	%
Intrasegment eliminations	—			—	%	(6		)	(33	)%	—			—	%	36			95	%
Total Natural Gas Pipelines	$	285		9	%	$	(332	)	(5	)%	$	(22	)	(2	)%	$	(358	)	(16	)%

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

Midstream’s ~~increases~~decrease of ~~$37~~$43 million ~~(13%~~(12%) ~~and $89 million (10%), respectively, were~~was primarily due to ~~increased earnings from Texas intrastate natural gas pipeline operations, Gulf Coast Express,~~the sale of the Cochin ~~pipeline,~~Pipeline on December 16, 2019 to Pembina, lower volumes on KinderHawk Field Services ~~LLC~~ and ~~South~~Oklahoma assets, lower rates on our North Texas ~~Midstream~~assets and lower sales margins on our Texas intrastate operations. These decreases were partially offset by ~~decreased earnings from~~higher volumes on

the Hiland ~~Midstream. Texas intrastate natural gas operations were favorably impacted by~~Midstream assets and higher ~~sales margins. Gulf Coast Express increased earnings were driven by~~ equity earnings ~~from~~due to the Gulf Coast Express ~~pipeline project that was~~Pipeline being placed in service in September 2019. Cochin pipeline’s increased earnings were primarily driven by higher volumes and higher tariff rates. KinderHawk Field Services LLC and South Texas Midstream benefited from increased drilling and production in the Haynesville and Eagle Ford basins, respectively. Hiland Midstream’s decreased earnings were 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;

~~West~~East Region’s ~~increases~~increase of ~~$26~~$20 million ~~(11%~~(4%) ~~and $90 million (13%), respectively, were~~was primarily due to increases in earnings from ~~EPNG~~ELC and CIG. The increase on EPNG was the result of capacity sales due to increased activity in the Permian Basin, partially offset by the negative impact of EPNG’s 501-G rate settlement. Increased earnings on CIG were due to capacity salesSouthern LNG Company, L.L.C. resulting from ~~increased activity in~~five of ten liquefaction units (part of the ~~Denver Julesburg basin; and~~

North Region’s increases of $23 million (7%) and $106 million (11%), 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 projectsElba Liquefaction project) being placed into service in ~~2018~~the later part of 2019 and first quarter 2020 partially offset by ~~higher operations~~reduced contributions from TGP due to historically mild weather in the Northeast 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.~~impact of the FERC 501-G rate settlement; and


•	West Region’s increase of $1 million (—%) was primarily due to increases in earnings from EPNG and CIG driven by increased revenues due to expansion in the Permian Basin and the Denver Julesburg basin, respectively, partially offset by decreased equity earnings from Ruby Pipeline Company due to lower transportation revenues.

Products Pipelines


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	484		$	475		$	1,350		$	1,420		$	495		$	424
Operating expenses	(177		)	(167		)	(500		)	(559		)	(221		)	(166		)
Other income	—			—			—			2
Loss on impairments and divestitures, net													(21		)	—
Earnings from equity investments	17			16			52			48			15			18
Other, net	1			1			6			1			1			—
Segment EBDA	325			325			908			912			269			276
Certain Items(a)	11			(12		)	28			18			4			17
Adjusted Segment EBDA	$	336		$	313		$	936		$	930		$	273		$	293

Change from prior period	Increase/(Decrease)												Increase/(Decrease)
Adjusted revenues	$	9		2		%	$	(70	)	(5		)%	$	71		17		%
Adjusted Segment EBDA	23			7		%	6			1		%	(20		)	(7		)%

Volumetric data(b)
Gasoline~~(b)~~(c)	1,066			1,066			1,045			1,043			961			980
Diesel fuel	393			386			370			370			358			337
Jet fuel	318			312			305			302			293			294
Total refined product volumes~~(c)~~	1,777			1,764			1,720			1,715			1,612			1,611
Crude and condensate~~(c)~~	639			617			644			617			702			643
Total delivery volumes (MBbl/d)	2,416			2,381			2,364			2,332			2,314			2,254

_______

Certain Items affecting Segment EBDA

(a)

Includes non-revenue Certain Item amounts of ~~$11~~$4 million and ~~$28~~$17 million for ~~the three~~2020 and ~~nine months ended September 30,~~ 2019, ~~respectively, and $(12)~~respectively. 2020 amount includes a non-cash loss on impairment of our Belton Terminal of $21 million and ~~$18~~a $17 million favorable adjustment for ~~the three and nine months ended September 30, 2018, respectively, primarily~~tax reserves, other than income taxes. 2019 amount is related to ~~(i) an unfavorable adjustment of an environmental reserve (three and nine month 2019 periods); (ii)~~ an unfavorable adjustment of tax reserves, other than income taxes (nine month 2019 period); (iii) an increase in earnings of $12 million as a result of property tax refunds (both three and nine month 2018 periods); and (iv) an increase in expense of $31 million associated with a Pacific operations litigation matter (nine month 2018 period).taxes.

Other


(b)	~~Volumes include ethanol pipeline volumes.~~


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


(c)	Volumes include ethanol pipeline volumes.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019.

Three Months Ended ~~September 30, 2019~~March 31, 2020 versus Three Months Ended ~~September 30, 2018~~March 31, 2019

Adjusted Segment EBDA
increase/(decrease)

Adjusted revenues
increase/(decrease)
(In millions, except percentages)
West Coast Refined Products $ 17
13 % $ 4
2 %
Southeast Refined Products 5
8 % 7
7 %
Crude and Condensate 1
1 % (2 ) (1 )%
Total Products Pipelines $ 23
7 % $ 9
2 %

~~Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018~~


	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)					Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Crude and Condensate											$	(17	)	(15	)%	$	54	34	%
Southeast Refined Products											(13		)	(20	)%	10		10	%
West Coast Refined Products	$	10		3	%	$	11		2	%	10			9	%	7		4	%
Southeast Refined Products	13			7	%	(12		)	(4	)%
Crude and Condensate	(17		)	(5	)%	(69		)	(12	)%
Total Products Pipelines	$	6		1	%	$	(70	)	(5	)%	$	(20	)	(7	)%	$	71	17	%

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

~~West Coast Refined Products’ increases~~Crude and Condensate’s decrease of $17 million ~~(13%~~(15%) and $10 million (3%), respectively, were primarily due to increased earnings on Pacific operations driven by a decrease in operating expenses associated with environmental reserves and higher margins primarily due to an increase in tariff rates in 2019;

Southeast Refined Products’ increases of $5 million (8%) and $13 million (7%), respectively, were primarily due to increased earnings from Central Florida Pipeline due to higher volumes and higher transportation and terminaling rates and increased earnings from our Transmix processing operations primarily due to increased volumes and higher processing rates. The year-to-date increase was also impacted by increased earnings from South East Terminals driven primarily by a gain recognized from an exchange of joint venture interests, and to a lesser extent increased equity earnings from Plantation Pipe Line as a result of increased transportation revenues driven by higher volumes and average tariff rate. The year-to date decrease in revenues was primarily due to ~~lower sales volumes as a result of a Transmix facility temporary shutdown in second quarter 2019 which was largely offset by a corresponding decrease in costs of sales; and~~

Crude and Condensate’s increase of $1 million (1%) and decrease of $17 million (5%), respectively, were impacted by increased earnings in the third quarter from the Bakken Crude assets primarily due to higher crude oil gathering and delivery volumes and increased tariff rates, largely offset by a decrease ofdecreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets as a result of unfavorable inventory adjustments driven by declines in commodity prices during the first quarter of 2020. KMCC’s decreased earnings were also impacted by lower contracted rates partially offset by higher volumes. These decreases were partially offset by increased earnings from KMCC - Splitter primarily due to ~~lower~~higher volumes driven by the Desalter project which was placed into service in May 2019 and associated processing fees. Overall Crude and Condensate revenues increased primarily due to increased volumes which were largely offset by a corresponding increase in costs of sales;

Southeast Refined Products’ decrease of $13 million (20%) was primarily due to decreased earnings from our Transmix processing operations driven by unfavorable inventory adjustments driven by commodity price declines during the first quarter 2020. The increase in revenues was primarily due to higher commodity sales revenues driven by a new customer contract which was offset by a corresponding increase in costs of sales; and

West Coast Refined Products’ increase of $10 million (9%) was primarily due to increased earnings on Pacific (SFPP) operations driven by an increase in services revenues as a result of unfavorable rates on contract renewals and a decrease in recognition of deficiency revenue. Similar factors contributed to the year-to-date change; however, the year-to-date decrease was primarily driven by the decrease in earnings on Kinder Morgan Crude & Condensate Pipeline and partially offset by the increased earnings from the Bakken Crude.higher tariff rates.

Terminals


	Three Months Ended September 30,						Nine Months Ended September 30,						Three Months Ended March 31,
	2019			2018			2019			2018			2020			2019
	(In millions, except operating statistics)												(In millions, except operating statistics)
Revenues	$	508		$	504		$	1,524		$	1,514		$	442		$	509
Operating expenses	(223		)	(210		)	(660		)	(608		)	(192		)	(216		)
Gain (loss) on divestitures and impairments, net	3			1			3			(53		)
Earnings from equity investments	6			5			15			17			5			5
Other, net	1			1			2			2			2			1
Segment EBDA	295			301			884			872			257			299
Certain Items(a)(b)	—			(2		)	—			33
Certain Items													—			—
Adjusted Segment EBDA	$	295		$	299		$	884		$	905		$	257		$	299

Change from prior period	Increase/(Decrease)												Increase/(Decrease)
Adjusted revenues	$	4		1		%	$	12		1		%	$	(67	)	(13		)%
Adjusted Segment EBDA	(4		)	(1		)%	(21		)	(2		)%	(42		)	(14		)%

Volumetric data
Volumetric data(a)
Liquids tankage capacity available for service (MMBbl)	89.1			88.7			89.1			88.7			79.5			79.3
Liquids utilization %(c)	94.5		%	93.5		%	94.5		%	93.5		%
Liquids utilization %(b)													93.7		%	94.0		%
Bulk transload tonnage (MMtons)	15.4			16.3			45.2			47.6			13.0			13.6

_______

Other


(a)	Volumes for assets sold are excluded for all periods presented.


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

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable three-month periods ended March 31, 2020 and 2019.

Three Months Ended March 31, 2020 versus Three Months Ended March 31, 2019



	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)
Alberta Canada	$	(33	)	(100	)%	$	(49	)	(100	)%
West Coast	(6		)	(100	)%	(16		)	(100	)%
All others (including intrasegment eliminations)	(3		)	(1	)%	(2		)	—	%
Total Terminals	$	(42	)	(14	)%	$	(67	)	(13	)%

The changes in Segment EBDA for our Terminals business segment during the three-month periods ended March 31, 2020 and 2019 are explained by the sale of KML assets to Pembina on December 16, 2019, which accounted for the decrease on our Alberta Canada terminals and on our West Coast terminals.

CO2



	Three Months Ended March 31,
	2020			2019
	(In millions, except operating statistics)
Revenues	$	309		$	305
Operating expenses	(122		)	(117		)
Loss on impairments and divestitures, net	(950		)	—
Earnings from equity investments	8			10
Segment EBDA	(755		)	198
Certain Items(a)(b)	930			(9		)
Adjusted Segment EBDA	$	175		$	189

Change from prior period	Increase/(Decrease)
Adjusted revenues	$	(7	)	(2		)%
Adjusted Segment EBDA	(14		)	(7		)%

Volumetric data
SACROC oil production	23.2			24.4
Yates oil production	7.0			7.3
Katz and Goldsmith oil production	3.4			4.1
Tall Cotton oil production	2.4			2.6
Total oil production, net (MBbl/d)(c)	36.0			38.4
NGL sales volumes, net (MBbl/d)(c)	9.8			10.1
CO₂ production, net (Bcf/d)	0.5			0.6
Realized weighted-average oil price per Bbl	$	54.61		$	48.67
Realized weighted-average NGL price per Bbl	$	19.74		$	25.98

_______

Certain Items affecting Segment EBDA


(a)	Includes revenue Certain Item amounts of ~~$(2)~~$(20) million and $(9) million for ~~the nine months ended September 30, 2018.~~


~~(b)~~	~~Includes non-revenue Certain Item amounts of $(2) million~~2020 and $35 million for the three and nine months ended September 30, 2018, respectively, primarily related to losses on divestitures and impairments, 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 Adjusted Segment EBDA and adjusted revenues, in the comparable three and nine month periods ended September 30,~~ 2019, ~~and 2018.~~

~~Three Months Ended September 30, 2019 versus Three Months Ended September 30, 2018~~

Adjusted Segment EBDA
increase/(decrease)

Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Alberta Canada $ (4 ) (11 )% $ 3
7 %
Mid Atlantic (4 ) (29 )% (3 ) (12 )%
Gulf Central (1 ) (7 )% (1 ) (4 )%
Gulf Liquids (1 ) (1 )% 5
5 %
Southeast 4
33 % —
— %
All others (including intrasegment eliminations) 2
1 % —
— %
Total Terminals $ (4 ) (1 )% $ 4
1 %

~~Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018~~

Adjusted Segment EBDA
increase/(decrease)

Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Alberta Canada $ (15 ) (14 )% $ 12
9 %
Mid Atlantic (6 ) (13 )% (6 ) (7 )%
Gulf Central (8 ) (16 )% (8 ) (11 )%
Gulf Liquids 9
4 % 16
5 %
Southeast 2
5 % 3
3 %
All others (including intrasegment eliminations) (3 ) (1 )% (5 ) (1 )%
Total Terminals $ (21 ) (2 )% $ 12
1 %

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

decreases of $4 million (11%) and $15 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 $4 million (29%) and $6 million (13%), respectively, from our Mid Atlantic terminals primarily due to lower coal volumes at our Pier IX facility;~~

decreases of $1 million (7%) and $8 million (16%), respectively, from our Gulf Central terminals primarily related to the termination of a customer contract in August 2018 at our Deer Park Rail Terminal and an unfavorable impact resulting from certain tanks being temporarily out of service for scheduled inspections and repairs at Battleground Oil Specialty Terminal Company LLC;

decrease of $1 million (1%) and increase of $9 million (4%), respectively, from our Gulf Liquids terminals. The year-to-date increase was primarily driven by higher volumes and associated ancillary fees, annual rate escalations on existing storage contracts and a customer rebate adversely impacting revenue recognized in the prior comparable period; and

~~increases of $4 million (33%) and $2 million (5%), respectively, from our Southeast terminals primarily related to gains on the sales of non-core assets.~~

CO2

Three Months Ended September 30, Nine Months Ended September 30,
2019 2018 2019 2018
(In millions, except operating statistics)
Revenues $ 298
$ 316
$ 913
$ 870
Operating expenses (143 ) (120 ) (383 ) (336 )
Earnings from equity investments 9
9
28
27
Segment EBDA 164
205
558
561
Certain Items(a)(b) (15 ) 28
(36 ) 130
Adjusted Segment EBDA $ 149
$ 233
$ 522
$ 691

Change from prior period Increase/(Decrease)
Adjusted revenues $ (61 ) (18 )% $ (144 ) (14 )%
Adjusted Segment EBDA (84 ) (36 )% (169 ) (24 )%

Volumetric data
SACROC oil production 23.2
23.9
24.0
24.3
Yates oil production 6.8
7.5
7.1
7.5
Katz and Goldsmith oil production 3.6
4.3
3.8
4.7
Tall Cotton oil production 2.1
2.5
2.4
2.3
Total oil production, net (MBbl/d)(c) 35.7
38.2
37.3
38.8
NGL sales volumes, net (MBbl/d)(c) 10.2
10.4
10.2
10.2
CO₂ production, net (Bcf/d)
0.6
0.6
0.6
0.6
Realized weighted-average oil price per Bbl $ 49.45
$ 57.96
$ 49.36
$ 58.59
Realized weighted-average NGL price per Bbl $ 21.12
$ 36.46
$ 23.54
$ 33.30

~~_______~~

~~Certain Items affecting Segment EBDA~~


~~(a)~~	Includes revenue Certain Item amounts of $(15) million and $(36) million for the three and nine months ended September 30, 2019, respectively, and $28 million and $151 million for the three and nine months ended September 30, 2018, respectively, related to unrealized gains ~~and losses~~ associated with derivative contracts used to hedge forecasted commodity sales.


(b)	Includes non-revenue Certain Item amount of ~~$(21)~~$950 million for ~~the nine months ended September 30, 2018 as~~2020 resulting from a ~~result~~$600 million goodwill impairment on our CO₂ reporting unit and non-cash impairments of ~~a severance tax refund.~~$350 million on most of our oil and gas producing assets.

Other


(c)	Net of royalties and outside working interests.

Below are the changes in both Adjusted Segment EBDA and adjusted revenues, in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018.~~2019.

Three Months Ended ~~September 30, 2019~~March 31, 2020 versus Three Months Ended ~~September 30, 2018~~March 31, 2019

Adjusted Segment EBDA
increase/(decrease)

Adjusted revenues
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing Activities $ (78 ) (50 )% $ (60 ) (24 )%
Source and Transportation Activities (6 ) (8 )% (5 ) (5 )%
Intrasegment eliminations —
— % 4
44 %
Total CO2
$ (84 ) (36 )% $ (61 ) (18 )%

~~Nine Months Ended September 30, 2019 versus Nine Months Ended September 30, 2018~~


	Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)					Adjusted Segment EBDA increase/(decrease)					Adjusted revenues increase/(decrease)
	(In millions, except percentages)										(In millions, except percentages)
Oil and Gas Producing Activities	$	(169	)	(36	)%	$	(155	)	(20	)%
Source and Transportation Activities	—			—	%	4			1	%
Source and Transportation activities											$	(14	)	(18	)%	$	(16	)	(16	)%
Oil and Gas Producing activities											—			—	%	5			2	%
Intrasegment eliminations	—			—	%	7			28	%	—			—	%	4			57	%
Total CO2	$	(169	)	(24	)%	$	(144	)	(14	)%	$	(14	)	(7	)%	$	(7	)	(2	)%

The changes in Segment EBDA for our CO₂ business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable ~~three and nine month~~three-month periods ended ~~September 30, 2019~~March 31, 2020 and ~~2018:~~2019:

decreases of $78 million (50%) and $169 million (36%), respectively, from our Oil and Gas Producing activities primarily due to decreased revenues of $60 million and $155 million, respectively, driven by lower crude oil and NGL prices which reduced revenues by $48 million and $133 million, respectively, and lower volumes which reduced revenues by $12 million and $22 million, respectively, higher operating expenses of $16 million and $11 million, respectively, and higher severance tax expense of $2 million and $3 million; and


•	decrease of $6$14 million ~~(8%~~(18%) ~~and flat, respectively,~~ from our Source and Transportation activities primarily due to a decrease of $19 million related to lower CO₂ sales volumes partially offset by higher CO₂sales driven by higher contract sales prices and lower operating expenses; and

•

flat (—%) from our Oil and Gas Producing activities due to increased revenues of $5 million ~~and higher CO~~₂ ~~sales of $3 million, respectively,~~ driven by ~~lower contract sales~~higher realized crude oil prices ~~of $7~~which increased revenues by $13 million and ~~$10 million, respectively, partially~~was offset by ~~higher~~lower volumes ~~of $2~~which reduced revenues by $8 million, ~~and $13 million, respectively,~~ and higher operating expenses of ~~$1 million and $4 million, respectively. Year-to-date was also impacted by $1 million increased earnings from an equity investee.~~$5 million.

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

Three Months Ended September 30, Earnings
2019 2018 Increase/(decrease)
(In millions, except percentages)
General and administrative (GAAP) $ (154 ) $ (154 ) $ —
— %
Corporate (benefit) charges (8 ) 3
(11 ) (367 )%
Certain Items(a) 5
8
(3 ) (38 )%
General and administrative and corporate charges(b) $ (157 ) $ (143 ) $ (14 ) (10 )%

Interest, net (GAAP) $ (447 ) $ (473 ) $ 26
5 %
Certain Items(c) (5 ) —
(5 ) n/a
Interest, net(b) $ (452 ) $ (473 ) $ 21
4 %

Net loss attributable to noncontrolling interests (GAAP) $ (11 ) $ (273 ) $ 262
96 %
Certain Items(d) —
256
(256 ) (100 )%
Net loss attributable to noncontrolling interests(b) $ (11 ) $ (17 ) $ 6
35 %

Nine Months Ended September 30, Earnings
2019 2018 Increase/(decrease)
(In millions, except percentages)
General and administrative (GAAP) $ (456 ) $ (491 ) $ 35
7 %
Corporate (benefit) charges (22 ) 6
(28 ) (467 )%
Certain Items(a) 11
18
(7 ) (39 )%
General and administrative and corporate charges(b) $ (467 ) $ (467 ) $ —
— %

Interest, net (GAAP) $ (1,359 ) $ (1,456 ) $ 97
7 %
Certain Items(c) (6 ) 34
(40 ) (118 )%
Interest, net(b) $ (1,365 ) $ (1,422 ) $ 57
4 %

Net loss attributable to noncontrolling interests (GAAP) $ (32 ) $ (302 ) $ 270
89 %
Certain Items(d) (1 ) 248
(249 ) (100 )%
Net loss attributable to noncontrolling interests(b) $ (33 ) $ (54 ) $ 21
39 %

~~_______~~

~~n/a - not applicable~~



	Three Months Ended March 31,						Earnings increase/(decrease)
	2020			2019			Earnings increase/(decrease)
	(In millions, except percentages)
General and administrative (GAAP)	$	(153	)	$	(154	)	$	1		1	%
Corporate charges	(12		)	(7		)	(5		)	(71	)%
Certain Items(a)	25			3			22			733	%
General and administrative and corporate charges(b)	$	(140	)	$	(158	)	$	18		11	%

Interest, net (GAAP)	$	(436	)	$	(460	)	$	24		5	%
Certain Items(c)	1			2			(1		)	(50	)%
Interest, net(b)	$	(435	)	$	(458	)	$	23		5	%

Net income attributable to noncontrolling interests (GAAP)	$	(15	)	$	(11	)	$	(4	)	(36	)%

Certain items

(a)

Three and nine month 2018 amounts include increases in expense of (i) $5 million and $7 million, respectively, of asset sale related costs; and (ii) $1 million and $8 million, respectively, related to certain corporate litigation matters. Nine month 20182020 amount ~~also~~ includes ~~a decrease in expense of $12 million related to an adjustment of tax reserves, other than income taxes and~~ an increase in expense of ~~$10~~$23 million associated with ~~an environmental reserve adjustment.~~the non-cash fair value adjustment and the dividend accrual on the Pembina common stock.


(b)	Amounts are adjusted for Certain Items.

(c)

~~Three~~2020 and ~~nine month~~ 2019 amounts include (i) decreases in interest expense of $7$8 million ~~and $22 million, respectively,~~for each period related to non-cash debt fair value adjustments associated with ~~previous acquisitions;~~acquisitions and (ii) increases in expense of $2 million and $15 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and hedged debt. Three and nine month 2018 amounts include (i) decreases in interest expense of $7 million and $25 million, respectively, related to non-cash debt fair value adjustments associated with historical acquisitions; (ii) increases in interest expense of $2$11 million and $10 million, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged ~~debt; and (iii) increases in interest expense of $1 million and $47 million, respectively, related to the write-off of capitalized KML credit facility fees.~~


~~(d)~~	~~Three and nine month 2018 amounts are primarily associated with the noncontrolling interests portion of the $622 million gain on the TMPL Sale.~~debt.

General and administrative expenses and corporate charges adjusted for Certain Items ~~increased $14~~decreased $18 million ~~and was flat for the three and nine months ended September 30, 2019, respectively,~~in 2020 when compared ~~with the respective prior year periods. The third quarter increase was~~to 2019 primarily due to ~~higher~~lower expenses of $14 million due to the sale of KML, lower pension costs of $12 million, a $4 million project write-off in 2019 and lower benefit-related costs ~~of $9 million and~~in our Terminals segment, partially offset by lower capitalized costs of $6$15 million ~~as a result of the winding down of certain pipeline projects, partially offset by lower expenses of $3 million~~primarily due to ~~the TMPL Sale. Year-to-date comprised~~our Gulf Coast project being placed in service in September 2019 and our Elba Liquefaction project which was partially placed in service in later part of ~~the following offsetting charges: (i) higher pension~~2019 and ~~benefit-related costs of $41 million; (ii) higher capitalized costs of $24 million driven by our large Permian basin pipeline projects; and (iii) lower expenses of $17 million due to the TMPL Sale.~~during first quarter 2020.

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 adjusted for Certain Items, ~~for the three and nine months ended September 30, 2019~~decreased $23 million in 2020 when compared ~~with the respective prior year periods decreased $21 million and $57 million, respectively. The decreases in interest expense were~~to 2019 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 balances and lower LIBOR rates partially offset by lower capitalized interest ~~rates.~~and interest income.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, approximately ~~31%~~17% and 27% 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 ~~adjusted~~ for ~~Certain Items for the three and nine months ended September 30, 2019~~2020 when compared ~~with the respective prior year periods decreased $6 million and $21 million, respectively, primarily due~~ to ~~the TMPL Sale.~~2019 increased $4 million.

Income Taxes

Our tax expense for the three months ended ~~September 30, 2019~~March 31, 2020 was approximately ~~$151~~$60 million as compared with ~~$196~~$172 million for the same period of ~~2018.~~2019. The ~~$45~~$112 million decrease in tax expense was due primarily ~~due~~ to ~~a decrease~~(i) lower pre-tax book income in ~~pre-tax earnings primarily~~2020 as a result of the ~~gain from our 2018 TMPL Sale, partially offset by a reduction in 2018~~impairment of ~~our~~certain CO₂ business segment assets, (ii) lower foreign income ~~tax reserve for uncertain tax positions~~taxes as a result of the ~~settlement~~KML and U.S. Cochin Sale in 2019, and (iii) the refund of ~~state income~~alternative minimum tax ~~audits.~~

~~Our tax expense for the nine months ended September 30, 2019 was approximately $471 million as compared with $314 million for the same period of 2018. The $157 million increase~~sequestration credits in tax expense was primarily due to an increase in pre-tax earnings as a result of 2018 midstream asset impairments and a reduction in 2018 of our income tax reserve for uncertain tax positions as a result of the settlement of federal and state income tax audits, partially offset by the gain from our 2018 TMPL Sale.2020.

Liquidity and Capital Resources

General

As of ~~September 30, 2019,~~March 31, 2020, we had ~~$241~~$360 million of “Cash and cash equivalents,” ~~a decrease~~an increase of ~~$3,039~~$175 million ~~(93%~~(95%) from December 31, ~~2018~~2019. ~~The 2018 TMPL Sale mentioned above~~As of March 31, 2020, our “Restricted deposits” includes $535 million held in “~~—General and Basis of Presentation—Sale of Trans Mountain Pipeline System and Its Expansion Project” was the primary source of cash~~escrow for maturing senior notes that matured on ~~hand~~April 1, 2020. Additionally, as of ~~December~~March 31, ~~2018. We~~2020, we had borrowing capacity of approximately $3.9 billion under our $4 billion revolving credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit ~~facilities (discussed below in “—Short-term Liquidity”), and cash flows from operating activities~~facility are more than adequate to allow us to manage our day-to-day cash requirements and anticipated ~~obligations as discussed further below.~~obligations.

We have consistently generated substantial cash flow from operations, providing a source of funds of ~~$3,121~~$893 million and ~~$3,375~~$635 million in the first ~~nine~~three months of ~~2019~~2020 and ~~2018,~~2019, respectively. The period-to-period ~~decrease~~increase is discussed below in “—Cash Flows—Operating Activities.” ~~Generally, we~~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 the negative impact of the decline in commodity prices and refined product demand to continue in the near term, which will negatively affect our operating cash flows; however, we continue to 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,~~

Due to the significant uncertainty regarding the length and impact of the virus on the energy industry and potential impacts to our business, and to preserve flexibility and to continue strengthening our cash position, on April 22, 2020, we announced a 5% increase in our dividend for the first quarter of 2020 over the fourth quarter of 2019, a reduction in our planned 25% growth, and a reduction of approximately $700 million in our estimated capital expansion for 2020 as a ~~result~~number of planned expansion projects no longer meet our ~~current common stock dividend policy and our continued focus on disciplined capital allocation,~~internal return thresholds. As a result, we do not expect the need to access the ~~equity~~ capital markets to fund our growth projects for 2020. At some point we would expect to access the ~~foreseeable future.~~debt capital markets to refinance maturing long-term debt, but given our revolver availability relative to debt maturing in the next eighteen months, we have significant flexibility on that timing.

To refinance construction costs of its recent expansions, on February 24, 2020, TGP, a wholly owned subsidiary, issued in a private placement $1,000 million aggregate principal amount of its 2.90% senior notes due 2030 and received net proceeds of $994 million. We used the proceeds to repay maturing debt. Additionally, during the first quarter of 2020, we opportunistically repurchased approximately 3.6 million of our Class P shares for approximately $50 million at an average price including commissions of $13.94 per share.

Short-term Liquidity

As of ~~September 30, 2019,~~March 31, 2020, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our ~~$4.5~~$4.0 billion revolving credit ~~facilities~~facility and associated commercial paper ~~program; and (iii) KML’s 4-year, C$500 million unsecured revolving credit facility (for KML’s working capital needs).~~program. The loan commitments under our revolving credit ~~facilities~~facility 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~~borrowings reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit ~~facilities~~facility and, as previously discussed, have consistently generated strong cash flows from operations. We do not anticipate any significant limitations from the impacts of COVID-19 with respect to our ability to access funding through our credit facility.

As of ~~September 30, 2019,~~March 31, 2020, our ~~$4,406~~$3,540 million of short-term debt consisted primarily ~~of (i) $3,684 million~~ of senior notes that mature in the next twelve ~~months; (ii) $532~~months, including $535 million ~~outstanding under our commercial paper program;~~that was repaid on April 1, 2020 with cash held in escrow as of March 31, 2020 and ~~(iii) $34 million outstanding borrowings under KML’s C$500 million revolving credit facility. We intend to use~~reported within “Restricted deposits” in the accompanying consolidated balance sheet. During 2020, we used the proceeds from the ~~pending~~ sale of the ~~U.S. portion~~Pembina common equity that we received for the sale of ~~the Cochin Pipeline~~KML to reduce ~~debt to maintain our leverage target, and use the remainder to invest in attractive projects and/or opportunistically repurchase common shares.~~debt. Otherwise, as our debt becomes due, we intend to fund our short-term debt primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt balance as of December 31, ~~2018~~2019 was ~~$3,388~~$2,477 million.

We had working capital (defined as current assets less current liabilities) deficits of ~~$4,461~~$2,512 million and ~~$1,835~~$1,862 million as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018,~~2019, 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 ~~$2,626~~$650 million ~~(143%~~(35%) unfavorable change from year-end ~~2018~~2019 was primarily due to (i) ~~a decrease~~an increase of approximately $1,100 million in senior notes that mature in the next twelve months; and (ii) $925 million related to the sale of Pembina common equity in January 2020; partially offset by (i) an increase in restricted deposits primarily related to cash held in escrow of $535 million for debt that matured on April 1, 2020 discussed above; (ii) an increase in cash and cash equivalents of ~~$3,039~~$175 million; (iii) a favorable fair value adjustment of $364 million ~~and (ii) increase~~on derivative contracts in 2020; (iv) net repayments of short-term debt of ~~$1,018 million partially offset by (i) a decrease in distributions payable of $876 million~~$37 million; and ~~(ii)~~(v) a net decrease in accounts payable, 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. As

Counterparty Creditworthiness

Some of ~~December 31, 2018, KML’s cash~~our customers or other counterparties may experience severe financial problems that may have a significant impact on their creditworthiness. These financial problems may arise from our current global economic conditions, continued volatility of commodity prices or otherwise. In such situations, we utilize, to the extent allowable under applicable contracts, tariffs and ~~cash equivalents included approximately U.S. $2.8 billion return~~regulations, prepayments and other security requirements, such as letters of ~~capital payment~~credit, to enhance our credit position relating to amounts owed from these counterparties. While we believe we have taken reasonable measures to protect against counterparty credit risk, we cannot provide assurance that one or more of our customers or other counterparties will not become financially distressed and will not default on their obligations to us ~~($1.9 billion) and KML’s public owners~~or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of ~~its restricted voting shares ($0.9 billion)~~operations, or future cash flows. See “Part II, Item 1A. Risk Factors —Financial distress experienced by our customers or other counterparties could have an adverse impact on ~~January 3, 2019, which was accrued~~us in the event they are unable to pay us for ~~as of December 31, 2018.~~the products or services we provide or otherwise fulfill their obligations to us.”

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—Overview—Non-GAAP ~~Performance~~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 ~~nine~~three months ended ~~September 30, 2019,~~March 31, 2020, and the amount we expect to spend for the remainder of ~~2019~~2020 to sustain and grow our businesses are as follows:

Nine Months Ended September 30, 2019 2019 Remaining Total 2019
(In millions)
Sustaining capital expenditures(a)(b) $ 477
$ 218
$ 695
KMI Discretionary capital investments(b)(c)(d) $ 2,168
$ 587
$ 2,755
KML Discretionary capital investments(b) $ 15
$ 12
$ 27



	Three Months Ended March 31, 2020		2020 Remaining		Total 2020(a)
	(In millions)
Sustaining capital expenditures(b)(c)	$	141	$	524	$	665
Discretionary capital investments(c)(d)(e)	542		1,151		1,693

_______


(a)	~~Nine~~Amounts include reductions due to revised outlook, as discussed above in “—General.”


(b)	Three months ended ~~September 30, 2019, 2019~~March 31, 2020, 2020 Remaining, and Total ~~2019~~2020 amounts include ~~$85~~$26 million, ~~$38~~$89 million, and ~~$123~~$115 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)~~(c)	~~Nine~~Three months ended ~~September 30, 2019 amounts exclude $106~~March 31, 2020 amount include $43 million of net changes from accrued capital expenditures, contractor retainage, and other.


~~(c)~~(d)	~~Nine~~Three months ended ~~September 30, 2019~~March 31, 2020 amount includes ~~$962~~$174 million of our contributions to certain unconsolidated joint ventures for capital investments.


~~(d)~~(e)	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~~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~~2019 in our ~~2018~~2019 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2019 and December 31, 2018 were $473 million and $304 million, respectively. The increase of $169 million was primarily driven by capital commitments related to our Natural Gas Pipelines business segment.

Cash Flows

Operating Activities

~~The net decrease of $254 million in cash~~Cash provided by operating activities ~~for~~increased $258 million in the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 compared to the respective ~~2018~~2019 period ~~was~~ primarily ~~attributable~~due to:

a ~~$327~~$211 million increase in cash resulting from $134 million of net income tax payments in the 2020 period compared to $345 million of net income tax payments in the 2019 period, both primarily for foreign income ~~tax~~taxes mostly associated with the TMPL ~~Sale; partially offset by,~~sale. The income tax payment for the 2020 period also included a $20 million refund received related to alternative minimum tax sequestration credits; and

a ~~$73~~$47 million increase ~~in cash driven by a reduction in litigation payments resulting from rate case refunds made to EPNG shippers in 2018, offset partially by a decrease~~ in cash from other operating activities in the ~~2019~~2020 period compared to the ~~2018~~2019 period.

Investing Activities

~~The $3,296 million net increase in cash used in~~Cash provided by investing activities increased $1,149 million for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 compared to the respective ~~2018~~2019 period ~~was~~ primarily attributable to:

a ~~$3,031~~$923 million ~~decrease~~increase in cash ~~reflecting~~primarily due to $907 million of proceeds received from the sale of the Pembina shares in the ~~2018 period from the TMPL Sale, net of cash disposed, and~~ 2020 period;

a ~~final working capital payment made in the 2019 period; and~~

~~an $854~~$180 million ~~increase~~decrease in cash used for contributions to equity investments driven by contributions made in 2019 to Midcontinent Express Pipeline LLC, Citrus Corporation and Fayetteville Express Pipeline LLC to fund our proportionate share of these equity investees’ 2019 maturing debt obligations, and higherlower contributions to Gulf Coast Express Pipeline LLC and Permian Highway Pipeline LLC in the ~~2019~~2020 period compared with the ~~2018 period;~~2019 period, partially offset by contributions made to SNG in the 2020 period; and

a ~~$487~~$114 million decrease in capital expenditures in the ~~2019~~2020 period over the comparative ~~2018~~2019 period primarily due to ~~no expenditures in 2019 for the TMEP, and to a lesser extent~~ lower expenditures ~~in our Natural Gas Pipelines and Terminals business segments; and~~

~~a $75 million increase in cash from proceeds from sales of interests in equity investments in~~on the ~~2019 period compared to the 2018 period.~~Elba Liquefaction expansion.

Financing Activities

~~The net increase of $2,747 million in cash~~Cash used inby financing activities decreased $2,421 million for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 compared to the respective ~~2018~~2019 period ~~was~~ primarily attributable to:

•

a $1,779 million net increase in cash used related to debt activity as a result of $1,194 million of net debt payments in the 2019 period compared to $585 million of net debt issuances in the 2018 period. See Note 3 ~~“Debt”~~

a $1,742 million net decrease in cash used related to debt activity as a result of $149 million of net debt issuances in the 2020 period compared to $1,593 million of net debt payments in the 2019 period. See Note 3 “Debt” for further information regarding our debt activity;

an $879 million increase in cash reflecting distribution of the TMPL ~~Sale~~sale proceeds to the owners of KML restricted voting shares in the 2019 period; ~~and~~partially offset by,

a ~~$430~~$114 million increase in dividend payments to our common shareholders; ~~partially offset by,~~and

a ~~$248~~$48 million ~~decrease~~increase in cash used due to ~~fewer~~an increase in common shares repurchased under our common share buy-back program in the ~~2019~~2020 period compared to the ~~2018 period; and~~

~~a $117 million decrease in cash used reflecting dividends paid to our mandatory convertible preferred shareholders in the 2018~~2019 period.

~~Dividends~~

~~KMI~~ Common Stock Dividends

We expect to declare common stock dividends of ~~$1.00~~$1.05 per share on our common stock for ~~2019.~~2020. The table below reflects our 2020 common stock dividends declared:

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
September 30, 2019 0.25
October 16, 2019 October 31, 2019 November 15, 2019



Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
December 31, 2019	$	0.25	January 22, 2020	February 3, 2020	February 18, 2020
March 31, 2020	0.2625		April 22, 2020	May 4, 2020	May 15, 2020

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~~2019 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~~

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

~~KML Distributions~~KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), 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 issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or subsidiary issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

~~KML has a dividend policy pursuant to which it may pay a quarterly dividend on its restricted voting shares in an amount~~In lieu of providing separate financial statements for subsidiary issuers and guarantors, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on ~~a portion~~Rule 13-01 of the SEC’s Regulation S-X that we early adopted effective January 1, 2020. Also, see Exhibit 10.1 to

this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain 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 recordsubsidiaries, with schedules updated as of ~~the close of business on or about the last business day of the month following the end of each calendar quarter.~~March 31, 2020.”

~~On October 15, 2019, KML’s board of directors declared a dividend~~All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the ~~quarterly period ended September 30, 2019 of C$0.1625 per restricted voting share, payable on November 15, 2019~~Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to ~~KML restricted voting shareholders of record~~as “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of March 31, 2020 and December 31, 2019, the ~~close~~Obligated Group had $32,649 million and $32,409 million, respectively, of ~~business on October 31, 2019.~~Guaranteed Notes outstanding.

~~KML Dividends on its Series 1 Preferred Shares~~Summarized combined Balance Sheet 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,Income Statement information for the ~~initial fixed rate period to but excluding November 15, 2022 and February 15, 2023, respectively.~~Obligated Group follows (in millions):



Summarized Combined Balance Sheet Information	March 31, 2020		December 31, 2019
ASSETS
Current assets	$	2,762	$	1,918
Current assets - affiliates	1,288		1,146
Noncurrent assets	63,206		63,298
Noncurrent assets - affiliates	449		441
Total Assets	$	67,705	$	66,803
LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
Current liabilities	$	5,210	$	4,569
Current liabilities - affiliates	1,175		1,139
Noncurrent liabilities	33,105		33,612
Noncurrent liabilities - affiliates	1,429		1,325
Total Liabilities	40,919		40,645
Redeemable Noncontrolling Interest	793		803
Kinder Morgan, Inc.’s stockholders’ equity	25,993		25,355
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity	$	67,705	$	66,803



Summarized Combined Income Statement Information	Three Months Ended March 31, 2020
Revenues	$	2,856
Operating income	462
Net income	147

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

~~There have been no material~~For a discussion of changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, ~~2018~~2019, in Item 7A in our ~~2018~~2019 Form ~~10-K. For more information on our risk management activities,~~10-K, see Item 2, “Management's Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook”and Item 1, Note 5 “Risk Management” to our consolidated financial ~~statements.~~

~~LIBOR is used as a reference rate~~statements for ~~certain~~more information on our risk management activities, both 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. Wewhich are ~~currently reviewing how the LIBOR phase-out will affect the Company, but we do not expect the impact to be material.~~incorporated in this item by reference.

Item 4. Controls and Procedures.

As of ~~September 30, 2019,~~March 31, 2020, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures.

Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended ~~September 30, 2019~~March 31, 2020 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 119 to our consolidated financial statements entitled ~~“Litigation~~“Litigation, Environmental and ~~Environmental,”~~Other Contingencies” which is incorporated in this item by reference.

Item 1A. Risk Factors.

~~There~~Other than the following risk factors regarding COVID-19 and the following updated risk factors, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our ~~2018~~2019 Form 10-K.

The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.

The ongoing pandemic involving COVID-19, a highly transmissible and pathogenic coronavirus, has negatively impacted the global economy and in turn reduced demand and pricing for crude oil, natural gas, NGL, refined petroleum products, CO₂, steel, chemicals and other products that we handle, which has adversely affected our business. In response to COVID-19, governments around the world have implemented increasingly stringent measures to help reduce the spread of the virus, including stay-at-home and shelter-in-place orders, travel restrictions and other measures. These measures have adversely affected the economies and financial markets of the U.S. and many other countries, resulting in an economic downturn that has negatively impacted global demand and prices for the products handled by our pipelines, terminals, shipping vessels and other facilities. Continuing uncertainty regarding the global impact of COVID-19 is likely to result in continued weakness in demand and prices for the products on which our business depends.

If the COVID-19 outbreak should worsen, we may also experience further disruptions to commodities markets, supply chains and the availability and efficiency of our workforce, which could adversely affect our ability to conduct our business and operations and limit our ability to execute on our business plan. In addition, measures taken by regulatory authorities attempting to mitigate the economic consequences of COVID-19 may not be effective or may have unintended harmful consequences. For example, the Texas Railroad Commission recently held a hearing to consider the possibility of requiring Texas producers to cut crude oil production to balance supply and demand for crude oil. Although no action was taken, we cannot predict whether regulatory authorities will decide to implement crude oil production cuts or other measures, or how such measures will affect our business. There are still too many variables and uncertainties regarding COVID-19 — including the ultimate geographic spread of the virus, the duration and severity of the outbreak and the extent of travel restrictions and business closures imposed in affected countries — to reasonably predict the potential impact of COVID-19 on our business and operations. COVID-19 may materially adversely affect our business, results of operations, financial condition and cash flows. Even after the COVID-19 pandemic has subsided, we may experience materially adverse impacts to our business due to the global economic recession that is likely to result from the measures taken to combat the virus.

Our businesses are dependent on the supply of and demand for the products that we handle.

Our pipelines, terminals and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil and other products in the geographic areas that they serve. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO₂, steel, chemicals and other products in the geographic areas to which our pipelines, terminals, shipping vessels and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. For example, without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers may reduce or shut down production during times of lower product prices or higher production costs to the extent they become uneconomic. Producers in areas served by us may not be successful in exploring for and developing additional reserves, and our pipelines and related facilities may not be able to maintain existing volumes of throughput.

Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves or renew transportation contracts as they expire. Additionally, demand for such products can decline due to situations over which we have no control, such as the COVID-19 pandemic and various measures that federal, state and local authorities have implemented in order to prevent further spread of COVID-19, including stay-at-home orders, or to respond to the economic consequences of COVID-19. See “—The COVID-19 pandemic has adversely affected, and could continue to adversely affect, our business.”

In addition to economic disruptions resulting from events such as COVID-19, conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable governmental policies, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. In recent years, a number of initiatives and regulatory changes relating to reducing greenhouse gas emissions have been undertaken by federal, state and municipal governments and crude oil and gas industry participants. In addition, public sentiment surrounding the potential risks posed by climate change and emerging technologies have resulted in an increased demand for energy efficiency and a transition to energy provided from renewable energy sources, rather than fossil fuels, and fuel-efficient alternatives such as hybrid and electric vehicles. These factors could result in not only increased costs for producers of hydrocarbons but also an overall decrease in the demand for hydrocarbons. Each of the foregoing could negatively impact our business directly as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. Furthermore, such unfavorable conditions may compound the adverse effects of larger disruptions such as COVID-19. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the productsor services we provide or otherwise fulfill their obligations to us” below.

We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle. In addition, irrespective of supply of or demand for products we handle, implementation of new regulations or changes to existing regulations affecting the energy industry could have a material adverse effect on us.

The volatility of crude oil, NGL and natural gas prices could adversely affect our CO₂ business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.

The revenues, cash flows, profitability and future growth of some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing crude oil, NGL and natural gas prices. Our CO₂ business segment and certain midstream businesses within our Natural Gas Pipelines business segment depend to a large degree, and certain businesses within our Product Pipelines business segment depend to a lesser degree, on prevailing crude oil, NGL and natural gas prices. For the estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”

Prices for crude oil, NGL and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil; (iv) governmental regulation; (v) political instability in crude oil producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. We are also subject, indirectly, to volatility of commodity prices, through many of our customers’ direct exposure to such volatility. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.”

As COVID-19 spread internationally and global economic activity slowed, future economic activity was forecasted to slow with a resulting forecast of a decline in crude oil and gas demand. In an attempt to stabilize the market, OPEC proposed production cuts in early March 2020; however, member producers failed to agree and some producers instead announced planned production increases, after which crude oil prices declined sharply. By mid-March 2020, crude oil prices had declined to less than $25 per barrel, the lowest price since April 1999. Member producers reached agreement on production cuts by

mid-April; however, crude oil prices continued to decline following announcement of the agreement. Producers in the U.S. and globally have not reduced crude oil production at a rate sufficient to match the sharp slowdown in economic activity caused by measures to control the spread of COVID-19, resulting in an oversupply of crude oil that recently caused crude oil prices per barrel to fall below zero. Sharp declines in the prices of crude oil, NGL or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO₂ business segment’s proved reserves, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment. If prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

In recent decades, there have been periods worldwide of both overproduction and underproduction of hydrocarbons, and periods of both increased and relaxed energy conservation efforts. Such conditions have resulted in periods of excess supply of, and reduced demand for, crude oil on a worldwide basis and for natural gas on a domestic basis. These periods have been followed by periods of short supply of, and increased demand for, crude oil and natural gas. The cycles of excess or short supply of crude oil or natural gas have placed pressures on prices and resulted in dramatic price fluctuations even during relatively short periods of seasonal market demand. These fluctuations impact the accuracy of assumptions used in our budgeting process. For more information about our energy and commodity market risk, see Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk.” For estimated impacts from sensitivities to changes in commodity prices to Adjusted EBITDA and DCF for the remainder of 2020, please refer to Part I, Item 2.“Management’s Discussion and Analysis of Financial Condition and Results of Operations—General and Basis of Presentation—2020 Outlook.”

Our operating results may be adversely affected by unfavorable economic and market conditions.

As described above, COVID-19’s global spread and the measures that governments have implemented to control the spread of the virus have resulted in a downturn of economic activity on a global scale. Such slowdowns are affecting numerous industries, including the crude oil and gas industry, the steel industry and in specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. In addition, uncertain or changing economic conditions within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets for a given commodity might also have a negative impact on many of our customers, which could impair their ability to meet their obligations to us. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” In addition, decreases in the prices of crude oil, NGL and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of crude oil, NGL and natural gas prices could adversely affect our CO₂ business segment and businesses within our Natural Gas Pipelines and Products Pipelines business segments.”

If economic and market conditions (including volatility in commodity markets) globally, in the U.S. or in other key markets become more volatile or continue to deteriorate, we may experience material impacts on our business, financial condition and results of operations.

Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. The global economic slowdown caused by COVID-19’s spread, combined with the recent extreme drop in crude oil prices, has significantly impacted the financial condition of many companies, particularly exploration and production companies, including some of our customers or counterparties. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and may not be able to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial and regulatory risks, and some are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Crude oil, NGL and natural gas prices were all lower on average in 2019 compared to 2018, and natural gas prices have continued to decline so far in 2020. Further deterioration in crude oil prices, or a continuation of the existing low natural gas or NGL price environment, would likely cause severe financial distress to some of our customers with direct commodity price exposure and may result in additional customer bankruptcies. Further, the security that is permitted to be obtained from such customers may be limited by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.

We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one of such customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion, of amounts owed to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations or cash flows.

Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.

We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products that we handle.”

The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them with new hedging arrangements. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions.

The accounting standards regarding hedge accounting are very complex, and even when we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect some volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Part II, Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Policies and Estimates—Hedging Activities” of our 2019 Form 10-K and Note 5 “Risk Management” to our consolidated financial statements included in Part I of this Form 10-Q.

A breach of information security or failure of one or more key information technology or operational (IT) systems, or those of third parties, may adversely affect our business, results of operations or business reputation.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these IT systems, networks and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processing necessary to manage our business.

While we have implemented and maintain a cybersecurity program designed to protect our IT and data systems from such attacks, we can provide no assurance that our cybersecurity program will be effective. In compliance with state and local stay-at-home orders issued in connection with COVID-19, a number of our employees have transitioned to working from home. As a result, more of our employees are working from locations where our cybersecurity program may be less effective and IT security may be less robust. We have experienced an increase in the number of attempts by external parties to access our networks or our company data without authorization. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, through an act of terrorism or cyber sabotage event has increased as attempted attacks have advanced in sophistication and number around the world.

If any of our systems are damaged, fail to function properly or otherwise become unavailable, we may incur substantial costs to repair or replace them and may experience loss or corruption of critical data and interruptions or delays in our ability to

perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events from occurring, and any network and information systems-related events could require us to expend significant resources to remedy such event. In the future, we may be required to expend additional resources to continue to enhance our information security measures and/or to investigate and remediate information security vulnerabilities.

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

~~None.~~

Our Purchases of Our Class P Shares

Period	Total number of securities purchased(a)	Average price paid per security(b)		Total number of securities purchased as part of publicly announced plans(a)	Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs
January 1 to January 31, 2020	—	$	—	—	$	1,474,909,370
February 1 to February 29, 2020	—	$	—	—	$	1,474,909,370
March 1 to March 31, 2020	3,588,486	$	13.93	3,588,486	$	1,424,909,386

Total	3,588,486	$	13.93	3,588,486	$	1,424,909,386

_______


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


(b)	Amount excludes any commission or other costs to repurchase shares.

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 ~~September 30, 2019.~~March 31, 2020.

Item 5. Other Information.

None.

Item 6. Exhibits.

Exhibit Number Description

10.1			Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of ~~September 30, 2019.~~March 31, 2020.

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~~Operations for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018;~~2019; (ii) our Consolidated Statements of Comprehensive (Loss) Income for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018;~~2019; (iii) our Consolidated Balance Sheets as of ~~September 30, 2019~~March 31, 2020 and December 31, ~~2018;~~2019; (iv) our Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30, 2019~~March 31, 2020 and ~~2018;~~2019; (v) our Consolidated Statements of Stockholders’ Equity for the three ~~and nine~~ months ended ~~September 30, 2019~~March 31, 2020 and ~~2018;~~2019; and (vi) the notes to our Consolidated Financial Statements.

104			Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

~~_______~~

*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:	~~October 18, 2019~~April 28, 2020	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

6854



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



Fair Value of Derivative Contracts
		Derivative Assets				Derivative Liabilities
		September 30, 2019		December 31, 2018		September 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)	$	73	$	135	$	(35	)	$	(45	)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	47		64		(1		)	—
Subtotal		120		199		(36		)	(45		)
Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	53		12		(2		)	(37		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	421		121		(2		)	(78		)
Subtotal		474		133		(4		)	(115		)
Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		91		(14		)	(6		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		106		—			—
Subtotal		20		197		(14		)	(6		)
Total		614		529		(54		)	(166		)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	18		22		(4		)	(5		)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		(1		)	—
Total		19		22		(5		)	(5		)
Total derivatives		$	633	$	551	$	(59	)	$	(171	)



	Three Months Ended September 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)	$	819	$	95	$	232	$	—		$	—	$	—		$	1,146
Fee-based services	174		246		163		17			41		—			641
Total services revenues	993		341		395		17			41		—			1,787
Sales
Natural gas sales	806		—		—		—			—		(3		)	803
Product sales	358		94		9		313			—		(11		)	763
Total sales revenues	1,164		94		9		313			—		(14		)	1,566
Total revenues from contracts with customers	2,157		435		404		330			41		(14		)	3,353
Other revenues(c)	35		40		100		(14		)	3		—			164
Total revenues	$	2,192	$	475	$	504	$	316		$	44	$	(14	)	$	3,517



	Nine Months Ended September 30, 2019
	Natural Gas Pipelines		Products Pipelines		Terminals		CO₂		Corporate and Eliminations			Total
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,701	$	253	$	785	$	1	$	(3	)	$	3,737
Fee-based services	561		752		398		45		—			1,756
Total services revenues	3,262		1,005		1,183		46		(3		)	5,493
Sales
Natural gas sales	1,979		—		—		1		(7		)	1,973
Product sales	599		211		16		827		(23		)	1,630
Total sales revenues	2,578		211		16		828		(30		)	3,603
Total revenues from contracts with customers	5,840		1,216		1,199		874		(33		)	9,096
Other revenues(c)	263		134		325		39		—			761
Total revenues	$	6,103	$	1,350	$	1,524	$	913	$	(33	)	$	9,857



	Nine Months Ended September 30, 2019
Contract Assets
Balance at December 31, 2018(a)	$	24
Additions	77
Transfer to Accounts receivable	(27		)
Other	(1		)
Balance at September 30, 2019(b)	$	73
Contract Liabilities
Balance at December 31, 2018(c)	$	292
Additions	305
Transfer to Revenues	(285		)
Other(d)	(15		)
Balance at September 30, 2019(e)	$	297



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



	Nine Months Ended September 30, 2019
Operating leases	$	107
Short-term and variable leases	58
Total lease cost(a)	$	165



	Nine Months Ended September 30, 2019
Operating cash flows from operating leases	$	(136	)
Investing cash flows from operating leases	(29		)
ROU assets obtained in exchange for operating lease obligations, net of retirements adjusted for currency conversion	70
Amortization of ROU assets	52

Weighted average remaining lease term	16.31 years
Weighted average discount rate	5.87		%



Lease Activity	Balance sheet location	September 30, 2019
ROU assets	Deferred charges and other assets	$	714
Short-term lease liability	Other current liabilities	53
Long-term lease liability	Other long-term liabilities and deferred credits	661
Finance lease assets	Property, plant and equipment, net	2
Finance lease liabilities	Long-term debt—Outstanding	2



	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



	September 30, 2019
2019 (three months ended December 31, 2019)	$	98
2020	370
2021	344
2022	329
2023	299
Thereafter	3,699
Total	$	5,139

Condensed Consolidating Statements of Income and Comprehensive Income for the Three Months Ended September 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	$	—		$	—		$	2,910		$	317		$	(13	)	$	3,214

Operating Costs, Expenses and Other
Costs of sales	—			—			734			29			(1		)	762
Depreciation, depletion and amortization	5			—			505			68			—			578
Other operating expense	2			1			804			128			(12		)	923
Total Operating Costs, Expenses and Other	7			1			2,043			225			(13		)	2,263

Operating (Loss) Income	(7		)	(1		)	867			92			—			951

Other Income (Expense)
Earnings from consolidated subsidiaries	840			780			92			17			(1,729		)	—
Earnings from equity investments	—			—			173			—			—			173
Interest, net	(191		)	1			(253		)	(4		)	—			(447		)
Amortization of excess cost of equity investments and other, net	(4		)	—			(5		)	—			—			(9		)

Income Before Income Tax	638			780			874			105			(1,729		)	668

Income Tax Expense	(132		)	—			(16		)	(3		)	—			(151		)

Net Income	506			780			858			102			(1,729		)	517
Net Income Attributable to Noncontrolling Interests	—			—			—			—			(11		)	(11		)
Net Income Attributable to Controlling Interests	$	506		$	780		$	858		$	102		$	(1,740	)	$	506

Net Income	$	506		$	780		$	858		$	102		$	(1,729	)	$	517
Total other comprehensive income (loss)	64			83			81			(5		)	(162		)	61
Comprehensive income	570			863			939			97			(1,891		)	578
Comprehensive income attributable to noncontrolling interests	—			—			—			—			(8		)	(8		)
Comprehensive income attributable to controlling interests	$	570		$	863		$	939		$	97		$	(1,899	)	$	570



	Three Months Ended September 30,						Earnings
	2019			2018			Increase/(decrease)
	(In millions, except percentages)
General and administrative (GAAP)	$	(154	)	$	(154	)	$	—		—	%
Corporate (benefit) charges	(8		)	3			(11		)	(367	)%
Certain Items(a)	5			8			(3		)	(38	)%
General and administrative and corporate charges(b)	$	(157	)	$	(143	)	$	(14	)	(10	)%

Interest, net (GAAP)	$	(447	)	$	(473	)	$	26		5	%
Certain Items(c)	(5		)	—			(5		)	n/a
Interest, net(b)	$	(452	)	$	(473	)	$	21		4	%

Net loss attributable to noncontrolling interests (GAAP)	$	(11	)	$	(273	)	$	262		96	%
Certain Items(d)	—			256			(256		)	(100	)%
Net loss attributable to noncontrolling interests(b)	$	(11	)	$	(17	)	$	6		35	%



	Nine Months Ended September 30, 2019		2019 Remaining		Total 2019
	(In millions)
Sustaining capital expenditures(a)(b)	$	477	$	218	$	695
KMI Discretionary capital investments(b)(c)(d)	$	2,168	$	587	$	2,755
KML Discretionary capital investments(b)	$	15	$	12	$	27