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 March 31, ~~2021~~2022

☐ 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 ☐

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 ☐

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,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer ☐ Non-accelerated filer ☐ 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. ☐

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 April ~~22, 2021,~~21, 2022, the registrant had ~~2,264,582,583~~2,267,472,525 shares of Class P ~~shares~~common stock 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 ~~Operations~~Income - Three Months Ended March 31 , 202 2 and 2021		4
	Consolidated Statements of Comprehensive Income - Three Months Ended March 31, ~~2021~~2022 and ~~2020~~		42021
	~~Consolidated Statements of Comprehensive Income (Loss) - Three Months Ended March 31, 2021 and 2020~~		5
	Consolidated Balance Sheets - as of March 31 ~~2021~~, 202 2 and December 31, ~~2020~~2021		6
	Consolidated Statements of Cash Flows - Three Months Ended March ~~31, 2021~~ 3 1 , 202 2 and ~~2020~~2021		7
	Consolidated Statements of Stockholders’ Equity - Three Months Ended March 31 ~~2021~~, 202 2 and ~~2020~~2021		9
	Notes to Consolidated Financial Statements		10
	Note 1 .	General	10
	Note 22.	~~Gains and Losses on Divestitures, Impairments and Other Write-downs~~Investments	11
	Note 33.	Debt	12
	Note 44.	~~Stockholders’~~Stockholders’ Equity	13
	Note 55.	Risk Management	1415
	Note 66.	Revenue Recognition	19
	~~Note 7~~	~~Reportable Segments~~	21
	Note 87.	Reportable Segments	23
	Note 8.	Income Taxes	2224
	Note 99.	Litigation and Environmental	2325
	Note 1010.	Recent Accounting Pronouncements	2729
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		2931
	Results of Operations		2931
	Overview		2931
	Consolidated Earnings Results (GAAP)		3233
	Non-GAAP Financial Measures		3435
	Segment Earnings Results		3738
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		4244
	Income Taxes		4345
	Liquidity and Capital Resources		4345
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		4749
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		4850
Item 4.	Controls and Procedures		4850
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		4850
Item 1A.	Risk Factors		4850
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		4850
Item 3.	Defaults Upon Senior Securities		4850
Item 4.	Mine Safety Disclosures		4851
Item 5.	Other Information		4851
Item 6.	Exhibits		4952
	Signature		5053

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

~~CIG~~EPNG

~~Colorado Interstate~~El Paso Natural Gas ~~Company, L.L.C.~~

~~KMLT~~

~~Kinder Morgan Liquid Terminals, LLC~~

~~ELC~~

~~Elba Liquefaction~~ Company, L.L.C.

Ruby

Ruby Pipeline Holding Company, L.L.C.

~~EPNG~~

~~El Paso Natural Gas Company, L.L.C.~~

~~SFPP~~

~~SFPP, L.P.~~

KMBT

Kinder Morgan Bulk Terminals, Inc.

~~SNG~~SFPP

~~Southern Natural Gas Company, L.L.C.~~SFPP, L.P.

KMI

Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries

SNG

Southern Natural Gas Company, L.L.C.

TGP

Tennessee Gas Pipeline Company, L.L.C.

KMLT

Kinder Morgan Liquid Terminals, LLC

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

Common Industry and Other Terms

per day

~~EPA~~

~~U.S. Environmental Protection Agency~~

~~Bbl~~

~~barrel~~

FASB

Financial Accounting Standards Board

Bbl

barrels

FERC

Federal Energy Regulatory Commission

BBtu

billion British Thermal Units

~~FERC~~GAAP

~~Federal Energy Regulatory Commission~~U.S. Generally Accepted Accounting Principles

Bcf

billion cubic feet

~~GAAP~~LLC

~~U.S. Generally Accepted Accounting Principles~~limited liability company

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

~~LLC~~

~~limited liability company~~

LIBOR

London Interbank Offered Rate

MBbl

thousand barrels

CO2

carbon dioxide or our CO2 business segment

~~MBbl~~

~~thousand barrels~~

~~COVID-19~~

~~Coronavirus Disease 2019, a widespread contagious disease, or the related pandemic declared and resulting worldwide economic downturn~~

MMBbl

million barrels

~~MMtons~~

~~million tons~~

DCF

distributable cash flow

~~NGL~~MMtons

~~natural gas liquids~~million tons

DD&A

depreciation, depletion and amortization

~~NYMEX~~NGL

~~New York Mercantile Exchange~~natural gas liquids

EBDA

earnings before depreciation, depletion and amortization expenses, including amortization of excess cost of equity investments

NYMEX

New York Mercantile Exchange

OTC

over-the-counter

~~ROU~~

~~Right-of-Use~~

EBITDA

earnings before interest, income taxes, depreciation, depletion and amortization expenses, and amortization of excess cost of equity investments

ROU

Right-of-Use

U.S.

United States of America

EPA

U.S. Environmental Protection Agency

WTI

West Texas Intermediate

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,” “outlook,” “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, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: 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, including the timing and extent of any economic recovery, and~~ our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.

Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the ~~impacts of the COVID-19 pandemic and the pace and extent of economic recovery; the~~ timing and extent of changes in the supply of and demand for the products we transport and handle; commodity prices; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” in this report, as well as “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, ~~2020~~2021 (except to the extent such information is modified or superseded by information in subsequent reports).

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 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.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF ~~OPERATIONS~~INCOME

(In millions, except per share amounts, unaudited)


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
Revenues	Revenues						Revenues
Services	Services		$	1,917	$	1,992	Services		$	2,050	$	1,917
Commodity sales	Commodity sales		3,229		1,067		Commodity sales		2,208		3,229
Other	Other		65		47		Other		35		65
Total Revenues	Total Revenues		5,211		3,106		Total Revenues		4,293		5,211

Operating Costs, Expenses and Other	Operating Costs, Expenses and Other						Operating Costs, Expenses and Other
Costs of sales	Costs of sales		2,009		663		Costs of sales		1,894		2,009
Operations and maintenance	Operations and maintenance		514		620		Operations and maintenance		585		514
Depreciation, depletion and amortization	Depreciation, depletion and amortization		541		565		Depreciation, depletion and amortization		538		541
General and administrative	General and administrative		156		153		General and administrative		156		156
Taxes, other than income taxes	Taxes, other than income taxes		110		92		Taxes, other than income taxes		111		110

(Gain) loss on divestitures and impairments, net (Note 2)			(4)		971
Gain on divestitures and impairments, net							Gain on divestitures and impairments, net		(10)		(4)
Other income, net	Other income, net		(1)		(1)		Other income, net		(5)		(1)
Total Operating Costs, Expenses and Other	Total Operating Costs, Expenses and Other		3,325		3,063		Total Operating Costs, Expenses and Other		3,269		3,325

Operating Income	Operating Income		1,886		43		Operating Income		1,024		1,886

Other Income (Expense)	Other Income (Expense)						Other Income (Expense)
Earnings from equity investments	Earnings from equity investments		66		192		Earnings from equity investments		187		66

Amortization of excess cost of equity investments	Amortization of excess cost of equity investments		(22)		(32)		Amortization of excess cost of equity investments		(19)		(22)
Interest, net	Interest, net		(377)		(436)		Interest, net		(333)		(377)
Other, net (Note 2)	Other, net (Note 2)		223		2		Other, net (Note 2)		19		223
Total Other Expense	Total Other Expense		(110)		(274)		Total Other Expense		(146)		(110)

Income (Loss) Before Income Taxes			1,776		(231)
Income Before Income Taxes							Income Before Income Taxes		878		1,776

Income Tax Expense	Income Tax Expense		(351)		(60)		Income Tax Expense		(194)		(351)

Net Income (Loss)			1,425		(291)
Net Income							Net Income		684		1,425

Net Income Attributable to Noncontrolling Interests	Net Income Attributable to Noncontrolling Interests		(16)		(15)		Net Income Attributable to Noncontrolling Interests		(17)		(16)

Net Income (Loss) Attributable to Kinder Morgan, Inc.			$	1,409	$	(306)
Net Income Attributable to Kinder Morgan, Inc.							Net Income Attributable to Kinder Morgan, Inc.		$	667	$	1,409

Class P Shares	Class P Shares						Class P Shares
Basic and Diluted Earnings (Loss) Per Share			$	0.62	$	(0.14)
Basic and Diluted Earnings Per Share							Basic and Diluted Earnings Per Share		$	0.29	$	0.62

Basic and Diluted Weighted Average Shares Outstanding	Basic and Diluted Weighted Average Shares Outstanding		2,264		2,264		Basic and Diluted Weighted Average Shares Outstanding		2,267		2,264

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME ~~(LOSS)~~

(In millions, unaudited)

Three Months Ended March 31,
2021 2020
Net income (loss) $ 1,425 $ (291)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit (expense) of $47 and $(67), respectively) (156) 222
Reclassification of change in fair value of derivatives to net income (net of tax expense of $18 and $11, respectively) 59 37
Foreign currency translation adjustments (net of tax expense of $0 and $0, respectively) 0 1
Benefit plan adjustments (net of tax expense of $4 and $3, respectively) 17 11
Total other comprehensive (loss) income (80) 271
Comprehensive income (loss) 1,345 (20)
Comprehensive income attributable to noncontrolling interests (16) (15)
Comprehensive income (loss) attributable to Kinder Morgan, Inc. $ 1,329 $ (35)


	Three Months Ended March 31,
		2022		2021
Net income		$	684	$	1,425
Other comprehensive loss, net of tax
Net unrealized loss from derivative instruments (net of taxes of $125 and $47, respectively)		(411)		(156)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(41) and $(18), respectively)		135		59

Benefit plan adjustments (net of taxes of $(4) and $(4), respectively)		13		17
Total other comprehensive loss		(263)		(80)

Comprehensive income		421		1,345
Comprehensive income attributable to noncontrolling interests		(17)		(16)
Comprehensive income attributable to KMI		$	404	$	1,329

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except per share amounts, unaudited)


		March 31, 2021		December 31, 2020			March 31, 2022		December 31, 2021
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	1,377	$	1,184	Cash and cash equivalents	$	84	$	1,140
Restricted deposits	Restricted deposits	46		25		Restricted deposits	264		7
Accounts receivable	Accounts receivable	1,425		1,293		Accounts receivable	1,661		1,611
Fair value of derivative contracts	Fair value of derivative contracts	218		185		Fair value of derivative contracts	147		220
Inventories	Inventories	389		348		Inventories	591		562

Other current assets	Other current assets	279		168		Other current assets	286		289
Total current assets	Total current assets	3,734		3,203		Total current assets	3,033		3,829

Property, plant and equipment, net	Property, plant and equipment, net	35,605		35,836		Property, plant and equipment, net	35,557		35,653
Investments	Investments	7,693		7,917		Investments	7,545		7,578
Goodwill	Goodwill	19,851		19,851		Goodwill	19,914		19,914
Other intangibles, net	Other intangibles, net	2,396		2,453		Other intangibles, net	1,618		1,678
Deferred income taxes	Deferred income taxes	213		536		Deferred income taxes	8		115

Deferred charges and other assets	Deferred charges and other assets	1,716		2,177		Deferred charges and other assets	1,460		1,649
Total Assets	Total Assets	$	71,208	$	71,973	Total Assets	$	69,135	$	70,416

LIABILITIES, REDEEMABLE NONCONTROLLING INTEREST AND STOCKHOLDERS’ EQUITY
LIABILITIES AND STOCKHOLDERS’ EQUITY						LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities	Current Liabilities					Current Liabilities
Current portion of debt	Current portion of debt	$	2,173	$	2,558	Current portion of debt	$	3,324	$	2,646
Accounts payable	Accounts payable	968		837		Accounts payable	1,204		1,259

Accrued interest	Accrued interest	304		525		Accrued interest	302		504
Accrued taxes	Accrued taxes	205		267		Accrued taxes	211		270
Accrued contingencies		157		307
Fair value of derivative contracts						Fair value of derivative contracts	535		178

Other current liabilities	Other current liabilities	811		580		Other current liabilities	874		964
Total current liabilities	Total current liabilities	4,618		5,074		Total current liabilities	6,450		5,821

Long-term liabilities and deferred credits	Long-term liabilities and deferred credits					Long-term liabilities and deferred credits
Long-term debt	Long-term debt					Long-term debt
Outstanding	Outstanding	30,007		30,838		Outstanding	28,175		29,772

Debt fair value adjustments	Debt fair value adjustments	1,054		1,293		Debt fair value adjustments	584		902
Total long-term debt	Total long-term debt	31,061		32,131		Total long-term debt	28,759		30,674

Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits	2,221		2,202		Other long-term liabilities and deferred credits	2,219		2,000

Total long-term liabilities and deferred credits	Total long-term liabilities and deferred credits	33,282		34,333		Total long-term liabilities and deferred credits	30,978		32,674
Total Liabilities	Total Liabilities	37,900		39,407		Total Liabilities	37,428		38,495

Commitments and contingencies (Notes 3 and 9)	Commitments and contingencies (Notes 3 and 9)	0		0		Commitments and contingencies (Notes 3 and 9)	0		0
Redeemable Noncontrolling Interest		705		728
Stockholders’ Equity	Stockholders’ Equity					Stockholders’ Equity

Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,264,470,730 and 2,264,257,336 shares, respectively, issued and outstanding		23		23
Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,382,723 and 2,267,391,527 shares, respectively, issued and outstanding						Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,382,723 and 2,267,391,527 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	Additional paid-in capital	41,775		41,756		Additional paid-in capital	41,813		41,806
Accumulated deficit	Accumulated deficit	(9,124)		(9,936)		Accumulated deficit	(10,544)		(10,595)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(487)		(407)		Accumulated other comprehensive loss	(674)		(411)
Total Kinder Morgan, Inc.’s stockholders’ equity	Total Kinder Morgan, Inc.’s stockholders’ equity	32,187		31,436		Total Kinder Morgan, Inc.’s stockholders’ equity	30,618		30,823
Noncontrolling interests	Noncontrolling interests	416		402		Noncontrolling interests	1,089		1,098
Total Stockholders’ Equity	Total Stockholders’ Equity	32,603		31,838		Total Stockholders’ Equity	31,707		31,921
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity		$	71,208	$	71,973
Total Liabilities and Stockholders’ Equity						Total Liabilities and Stockholders’ Equity	$	69,135	$	70,416

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


KINDER MORGAN, INC. AND SUBSIDIARIES	KINDER MORGAN, INC. AND SUBSIDIARIES					KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS	CONSOLIDATED STATEMENTS OF CASH FLOWS					CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)	(In millions, unaudited)					(In millions, unaudited)

		Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020			2022		2021
Cash Flows From Operating Activities	Cash Flows From Operating Activities					Cash Flows From Operating Activities
Net income (loss)		$	1,425	$	(291)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Net income						Net income	$	684	$	1,425
Adjustments to reconcile net income to net cash provided by operating activities						Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	Depreciation, depletion and amortization	541		565		Depreciation, depletion and amortization	538		541
Deferred income taxes	Deferred income taxes	347		(69)		Deferred income taxes	190		347
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	22		32		Amortization of excess cost of equity investments	19		22

(Gain) loss on divestitures and impairments, net (Note 2)		(4)		971
Gain from sale of interest in equity investment (Note 2)		(206)		0
Change in fair market value of derivative contracts						Change in fair market value of derivative contracts	77		14
Gain on divestitures and impairments, net						Gain on divestitures and impairments, net	(10)		(4)
Gain on sale of interest in equity investment (Note 2)						Gain on sale of interest in equity investment (Note 2)	—		(206)
Earnings from equity investments	Earnings from equity investments	(66)		(192)		Earnings from equity investments	(187)		(66)
Distributions from equity investment earnings	Distributions from equity investment earnings	184		152		Distributions from equity investment earnings	165		184
Changes in components of working capital	Changes in components of working capital					Changes in components of working capital
Accounts receivable	Accounts receivable	(122)		222		Accounts receivable	(51)		(122)
Inventories	Inventories	(47)		59		Inventories	(34)		(47)
Other current assets	Other current assets	4		50		Other current assets	(14)		4
Accounts payable	Accounts payable	26		(200)		Accounts payable	55		26
Accrued interest, net of interest rate swaps	Accrued interest, net of interest rate swaps	(204)		(202)		Accrued interest, net of interest rate swaps	(188)		(204)
Accrued taxes	Accrued taxes	(63)		(59)		Accrued taxes	(59)		(63)
Other current liabilities	Other current liabilities	157		(131)		Other current liabilities	(39)		157
Rate reparations, refunds and other litigation reserve adjustments	Rate reparations, refunds and other litigation reserve adjustments	(144)		10		Rate reparations, refunds and other litigation reserve adjustments	(68)		(144)
Other, net	Other, net	23		(24)		Other, net	6		9
Net Cash Provided by Operating Activities	Net Cash Provided by Operating Activities	1,873		893		Net Cash Provided by Operating Activities	1,084		1,873
Cash Flows From Investing Activities	Cash Flows From Investing Activities					Cash Flows From Investing Activities

Capital expenditures	Capital expenditures	(267)		(440)		Capital expenditures	(407)		(267)
Proceeds from sales of investments	Proceeds from sales of investments	413		907		Proceeds from sales of investments	—		413
Contributions to investments	Contributions to investments	(22)		(151)		Contributions to investments	(11)		(22)
Distributions from equity investments in excess of cumulative earnings	Distributions from equity investments in excess of cumulative earnings	18		41		Distributions from equity investments in excess of cumulative earnings	50		18

Other, net	Other, net	(12)		(22)		Other, net	(3)		(12)
Net Cash Provided by Investing Activities		130		335
Net Cash (Used in) Provided by Investing Activities						Net Cash (Used in) Provided by Investing Activities	(371)		130
Cash Flows From Financing Activities	Cash Flows From Financing Activities					Cash Flows From Financing Activities
Issuances of debt	Issuances of debt	3,110		2,125		Issuances of debt	1,588		3,110
Payments of debt	Payments of debt	(4,268)		(1,969)		Payments of debt	(2,453)		(4,268)
Debt issue costs	Debt issue costs	(10)		(7)		Debt issue costs	(4)		(10)
Dividends	Dividends	(597)		(569)		Dividends	(616)		(597)

Repurchases of shares	Repurchases of shares	0		(50)		Repurchases of shares	(1)		—

Contributions from investment partner and noncontrolling interests		3		5
Contributions from noncontrolling interests						Contributions from noncontrolling interests	—		3
Distributions to investment partner	Distributions to investment partner	(23)		(18)		Distributions to investment partner	—		(23)

Distributions to noncontrolling interests	Distributions to noncontrolling interests	(2)		(3)		Distributions to noncontrolling interests	(26)		(2)
Other, net	Other, net	(2)		(1)		Other, net	—		(2)
Net Cash Used in Financing Activities	Net Cash Used in Financing Activities	(1,789)		(487)		Net Cash Used in Financing Activities	(1,512)		(1,789)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits		0		(8)
Net Increase in Cash, Cash Equivalents and Restricted Deposits		214		733

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits						Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(799)		214
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209		Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,147		1,209
Cash, Cash Equivalents, and Restricted Deposits, end of period	Cash, Cash Equivalents, and Restricted Deposits, end of period	$	1,423	$	942	Cash, Cash Equivalents, and Restricted Deposits, end of period	$	348	$	1,423


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

		Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020			2022		2021
Cash and Cash Equivalents, beginning of period	Cash and Cash Equivalents, beginning of period	$	1,184	$	185	Cash and Cash Equivalents, beginning of period	$	1,140	$	1,184
Restricted Deposits, beginning of period	Restricted Deposits, beginning of period	25		24		Restricted Deposits, beginning of period	7		25
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,209		209		Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,147		1,209
Cash and Cash Equivalents, end of period	Cash and Cash Equivalents, end of period	1,377		360		Cash and Cash Equivalents, end of period	84		1,377
Restricted Deposits, end of period	Restricted Deposits, end of period	46		582		Restricted Deposits, end of period	264		46
Cash, Cash Equivalents, and Restricted Deposits, end of period	Cash, Cash Equivalents, and Restricted Deposits, end of period	1,423		942		Cash, Cash Equivalents, and Restricted Deposits, end of period	348		1,423
Net Increase in Cash, Cash Equivalents and Restricted Deposits		$	214	$	733
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits						Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(799)	$	214

Non-cash Investing and Financing Activities	Non-cash Investing and Financing Activities					Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized	ROU assets and operating lease obligations recognized	$	7	$	14	ROU assets and operating lease obligations recognized	$	3	$	7
Increase in property, plant and equipment from both accruals and contractor retainage				41

Supplemental Disclosures of Cash Flow Information	Supplemental Disclosures of Cash Flow Information					Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	Cash paid during the period for interest (net of capitalized interest)	589		661		Cash paid during the period for interest (net of capitalized interest)	561		589
Cash paid during the period for income taxes, net	Cash paid during the period for income taxes, net	1		134		Cash paid during the period for income taxes, net	1		1

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																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			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, 2020		2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838
Balance at December 31, 2021																	Balance at December 31, 2021	2,267	$	23	$	41,806	$	(10,595)	$	(411)	$	30,823	$	1,098	$	31,921
Impact of adoption of ASU 2020-06 (Note 4)																	Impact of adoption of ASU 2020-06 (Note 4)				(11)						(11)				(11)
Balance at January 1, 2022																	Balance at January 1, 2022	2,267	23		41,795		(10,595)		(411)		30,812		1,098		31,910

Repurchases of shares																	Repurchases of shares				(1)						(1)				(1)
EP Trust I Preferred security conversions																	EP Trust I Preferred security conversions				1						1				1
Restricted shares	Restricted shares				19						19				19		Restricted shares				18						18				18
Net income	Net income						1,409				1,409		16		1,425		Net income						667				667		17		684
Distributions	Distributions										0		(3)		(3)		Distributions										—		(26)		(26)
Contributions											0		2		2

Dividends	Dividends						(597)				(597)				(597)		Dividends						(616)				(616)				(616)
Other											0		(1)		(1)

Other comprehensive loss	Other comprehensive loss								(80)		(80)				(80)		Other comprehensive loss								(263)		(263)				(263)
Balance at March 31, 2021		2,264	$	23	$	41,775	$	(9,124)	$	(487)	$	32,187	$	416	$	32,603
Balance at March 31, 2022																	Balance at March 31, 2022	2,267	$	23	$	41,813	$	(10,544)	$	(674)	$	30,618	$	1,089	$	31,707

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 shares (4) (50) (50) (50)
Restricted shares 18 18 18
Net (loss) income (306) (306) 15 (291)
Distributions 0 (3) (3)
Contributions 0 2 2
Dividends (569) (569) (569)
Other comprehensive income 271 271 0 271
Balance at March 31, 2020 2,261 $ 23 $ 41,713 $ (8,568) $ (62) $ 33,106 $ 358 $ 33,464


	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, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838





Restricted shares				19						19				19
Net income						1,409				1,409		16		1,425


Distributions										—		(3)		(3)
Contributions										—		2		2
Dividends						(597)				(597)				(597)


Other										—		(1)		(1)
Other comprehensive loss								(80)		(80)				(80)
Balance at March 31, 2021	2,264	$	23	$	41,775	$	(9,124)	$	(487)	$	32,187	$	416	$	32,603

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 83,000 miles of pipelines, 141 terminals, and ~~144 terminals.~~700 billion cubic feet of working natural gas storage capacity. Our pipelines transport natural gas, renewable fuels, refined petroleum products, crude oil, condensate, CO2 and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, chemicals, biodiesel, renewable fuels, metals and petroleum coke.

Basis of Presentation

General

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 ~~2020~~2021 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.

Earnings per Share

We calculate earnings per share using the two-class method. Earnings were allocated to Class P ~~shares~~common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be 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 ~~(loss)~~ available to shareholders of Class P ~~shares~~common stock and participating securities:

Three Months Ended March 31,
2021 2020
(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders $ 1,409 $ (306)
Participating securities:
Less: Net Income allocated to restricted stock awards(a) (7) (3)
Net Income (Loss) Allocated to Class P Stockholders $ 1,402 $ (309)
Basic Weighted Average Shares Outstanding 2,264 2,264
Basic Earnings (Loss) Per Share $ 0.62 $ (0.14)


	Three Months Ended March 31,
		2022		2021
		(In millions, except per share amounts)
Net Income Available to Stockholders		$	667	$	1,409
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)		(4)		(7)
Net Income Allocated to Class P Stockholders		$	663	$	1,402

Basic Weighted Average Shares Outstanding		2,267		2,264
Basic Earnings Per Share		$	0.29	$	0.62

(a)As of March 31, ~~2021,~~2022, there were ~~approximately 12~~13 million restricted stock awards outstanding.

The following maximum number of potential common stock equivalents are antidilutive and, accordingly, are excluded from the determination of diluted earnings per share:


		Three Months Ended March 31,				Three Months Ended March 31,
			2021	2020			2022	2021
			(In millions on a weighted average basis)				(In millions on a weighted average basis)
Unvested restricted stock awards	Unvested restricted stock awards		13	12	Unvested restricted stock awards		13	13
Convertible trust preferred securities	Convertible trust preferred securities		3	3	Convertible trust preferred securities		3	3

2. ~~Gains and Losses on Divestitures, Impairments and Other Write-downs~~Investments

WeInvestment in Ruby

During the first quarter of 2021, we recognized ~~the following non-cash~~a pre-tax ~~(gains) losses on divestitures, impairments and other write-downs, net on assets during~~charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, which is included within “Earnings from equity investments” in our accompanying consolidated statement of income for the three months ended March 31, ~~2021 and 2020:~~

Three Months Ended March 31,
2021 2020
(In millions)
Natural Gas Pipelines
Gain on sale of interest in NGPL Holdings LLC(a) $ (206) $ 0
Loss on write-down of related party note receivable(a) 117 0
Products Pipelines
Impairment of long-lived and intangible assets 0 21
Terminals
Gain on divestitures of long-lived assets (1) 0
CO2
Impairment of goodwill(a) 0 600
Impairment of long-lived assets(a) 0 350
Other gain on divestitures of long-lived assets (3) 0
Pre-tax (gain) loss on divestitures, impairments and other write-downs, net $ (93) $ 971

~~(a)See below for a further discussion~~2021. The write-down was driven by the impairment recognized by Ruby of ~~these items.~~its assets.

Ruby Chapter 11 Bankruptcy Filing

The balance of Ruby Pipeline, L.L.C.'s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, will continue to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had 0 amounts included in our “Investments” in our accompanying consolidated balance sheets associated with Ruby as of March 31, 2022 or December 31, 2021.

Sale of an Interest in NGPL Holdings

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests ~~sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%.~~sold. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of ~~operations~~income for the three months ended March 31, 2021. ~~Upon closing, we~~We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

~~Impairments~~

During the first quarter of 2020, the energy production and demand factors related to COVID-19 and the sharp decline in commodity prices represented a triggering event that required us to perform impairment testing on certain businesses that are sensitive to commodity prices. As a result, we performed an impairment analysis of long-lived assets within our CO2 ~~business segment and conducted interim tests of the recoverability of goodwill for our CO~~2 ~~and Natural Gas Pipelines Non-Regulated reporting units as of March 31, 2020, which resulted in impairments of long-lived assets and goodwill within our CO~~2 ~~business segment shown in the above table during the three months ended March 31, 2020.~~

~~Other Write-downs~~

During the first quarter of 2021, we recognized a pre-tax charge of $117 million related to a write-down of our subordinated note receivable from our equity investee, Ruby, driven by the recent impairment by Ruby of its assets, which is included within “Earnings from equity investments” in our accompanying consolidated statement of operations. The impairment at Ruby was the result of upcoming contract expirations and additional uncertainty identified in late February 2021 regarding the proposed development of a third party liquefied natural gas exporting facility that could significantly increase the demand for its services.

3. Debt

The following table provides information on the principal amount of our outstanding debt balances:

March 31, 2021 December 31, 2020
(In millions, unless otherwise stated)
Current portion of debt
$4 billion credit facility due November 16, 2023 $ 0 $ 0
Commercial paper notes 0 0
Current portion of senior notes
5.00%, due February 2021(a) 0 750
3.50%, due March 2021(a) 0 750
5.80%, due March 2021(a) 0 400
5.00%, due October 2021 500 500
8.625%, due January 2022 260 0
4.15%, due March 2022 375 0
1.50%, due March 2022(b) 880 0
Trust I preferred securities, 4.75%, due March 2028 111 111
Current portion of other debt 47 47
Total current portion of debt 2,173 2,558
Long-term debt (excluding current portion)
Senior notes 29,314 30,141
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035 361 364
Trust I preferred securities, 4.75%, due March 2028 110 110
Other 222 223
Total long-term debt 30,007 30,838
Total debt(c) $ 32,180 $ 33,396


	March 31, 2022		December 31, 2021
	(In millions, unless otherwise stated)
Current portion of debt

$3.5 billion credit facility due August 20, 2026	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes(a)	290		—
Current portion of senior notes
8.625%, due January 2022(b)	—		260
4.15%, due March 2022(b)	—		375
1.50%, due March 2022(b)(c)	—		853
3.95% due September 2022	1,000		1,000
3.15% due January 2023	1,000		—
Floating rate, due January 2023(d)	250		—
3.45% due February 2023	625		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	48		47
Total current portion of debt	3,324		2,646

Long-term debt (excluding current portion)
Senior notes	27,506		29,097
EPC Building, LLC, promissory note, 3.967%, due 2021 through 2035	344		348

Trust I preferred securities, 4.75%, due March 2028	109		110
Other	216		217
Total long-term debt	28,175		29,772
Total debt(e)	$	31,499	$	32,418

(a)Weighted average interest rate on borrowings outstanding as of March 31, 2022 was 0.65%.

(b)We repaid the principal ~~amounts on~~amount of these senior notes during the first quarter of ~~2021.~~2022.

~~(b)~~(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The ~~March~~December 31, 2021 balance is reported above at the exchange rate of ~~1.1730~~1.1370 U.S. dollars per Euro. As of ~~March~~December 31, 2021, the cumulative change in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase to our debt balance of ~~$65~~$38 million related to these ~~notes. The cumulative increase in debt due to the changes in exchange rates for the 1.50%~~ notes, ~~due 2022 is~~which was offset by a corresponding change in the value of cross-currency swaps reflected in “Other current assets” and “Other current liabilities” on our accompanying consolidated balance ~~sheets.~~sheet. At the time of issuance, we entered into foreign currency contracts associated with these senior notes, effectively converting these Euro-denominated senior notes to U.S. dollars (see Note 5 “Risk Management—Foreign Currency Risk Management”).

~~(c)~~(d)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge (see Note 5, “Risk Management—Interest Rate Risk Management”).

(e)Excludes our “Debt fair value adjustments” which, as of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, increased our total debt balances by ~~$1,054~~$584 million and ~~$1,293~~$902 million, respectively.

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.

On February ~~11, 2021, we~~23, 2022, EPNG issued in a ~~registered~~private offering ~~$750~~$300 million aggregate principal amount of ~~3.60%~~3.50% senior notes due ~~2051~~2032 and received net proceeds of ~~$741 million.~~$298 million after discount and issuance costs. These notes are guaranteed through the cross guarantee agreement discussed above.

Credit ~~Facility~~Facilities and Restrictive Covenants

As of March 31, ~~2021,~~2022, we had 0no borrowings outstanding under our ~~$4.0 billion~~ credit ~~facility, 0~~facilities, $290 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit ~~facility~~facilities as of March 31, ~~2021~~2022 was ~~$3,919 million.~~$3.6 billion. As of March 31, ~~2021,~~2022, we were in compliance with all required covenants.

Fair Value of Financial Instruments

The carrying value and estimated fair value of our outstanding debt balances are disclosed below:

March 31, 2021 December 31, 2020
Carrying
value Estimated
fair value Carrying
value Estimated
fair value
(In millions)
Total debt $ 33,234 $ 37,050 $ 34,689 $ 39,622


	March 31, 2022				December 31, 2021
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	32,083	$	33,895	$	33,320	$	37,775

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $216 million and $218 million as of March 31, 2022 and December 31, 2021, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both March 31, ~~2021~~2022 and December 31, ~~2020.~~2021.

4. Stockholders’ Equity

Class P 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 three months ended March 31, 2022, we repurchased approximately 31,000 of our shares for less than $1 million at an average price of $16.97 per share. Since December 2017, in total, we have repurchased ~~approximately 32~~33 million of our ~~Class P~~ shares under the program at an average price of ~~approximately~~ $17.71 per share for ~~approximately $575~~$576 million.

Dividends

The following table provides information about our per share dividends:


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
Per share cash dividend declared for the period	Per share cash dividend declared for the period		$	0.27	$	0.2625	Per share cash dividend declared for the period		$	0.2775	$	0.27
Per share cash dividend paid in the period	Per share cash dividend paid in the period		0.2625		0.25		Per share cash dividend paid in the period		0.27		0.2625

On April ~~21, 2021,~~20, 2022, our board of directors declared a cash dividend of ~~$0.27~~$0.2775 per share for the quarterly period ended March 31, ~~2021,~~2022, which is payable on May ~~17, 2021~~16, 2022 to shareholders of record as of the close of business on ~~April 30, 2021.~~May 2, 2022.

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted EPS calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the three months ended March 31, 2022.

Accumulated Other Comprehensive Loss

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:

Net unrealized
gains/(losses)
on cash flow
hedge derivatives Foreign
currency
translation
adjustments Pension and
other
postretirement
liability adjustments Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2020 $ (13) $ 0 $ (394) $ (407)
Other comprehensive (loss) gain before reclassifications (156) 0 17 (139)
Loss reclassified from accumulated other comprehensive loss 59 0 0 59
Net current-period change in accumulated other comprehensive loss (97) 0 17 (80)
Balance as of March 31, 2021 $ (110) $ 0 $ (377) $ (487)


	Net unrealized gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2021	$	(172)	$	(239)	$	(411)
Other comprehensive (loss) gain before reclassifications	(411)		13		(398)
Loss reclassified from accumulated other comprehensive loss	135		—		135
Net current-period change in accumulated other comprehensive (loss) income	(276)		13		(263)
Balance as of March 31, 2022	$	(448)	$	(226)	$	(674)

Net unrealized
gains/(losses)
on cash flow
hedge derivatives Foreign
currency
translation
adjustments Pension and
other
postretirement
liability adjustments Total
accumulated other
comprehensive loss
(In millions)
Balance as of December 31, 2019 $ (7) $ 0 $ (326) $ (333)
Other comprehensive gain before reclassifications 222 1 11 234
Loss reclassified from accumulated other comprehensive loss 37 0 0 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		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2020	$	(13)	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(156)		17		(139)
Loss reclassified from accumulated other comprehensive loss	59		—		59
Net current-period change in accumulated other comprehensive (loss) income	(97)		17		(80)
Balance as of March 31, 2021	$	(110)	$	(377)	$	(487)

5. Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

Energy Commodity Price Risk Management

As of March 31, ~~2021,~~2022, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:


	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	~~(16.6)~~(20.5)	MMBbl
Crude oil basis	~~(8.7)~~(5.3)	MMBbl
Natural gas fixed price	~~(35.0)~~(59.4)	Bcf
Natural gas basis	~~(30.5)~~(28.5)	Bcf
NGL fixed price	~~(1.2)~~(0.8)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	~~(1.0)~~(1.5)	MMBbl
Crude oil basis	~~(12.6)~~(7.7)	MMBbl
Natural gas fixed price	~~(8.2)~~(10.6)	Bcf
Natural gas basis	~~(10.6)~~1.8	Bcf
Natural gas options	(0.6)	Bcf
NGL fixed price	~~(1.1)~~(1.6)	MMBbl

As of March 31, ~~2021,~~2022, 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 ~~2025.~~2026.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of March 31, ~~2021:~~2022:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

Fixed-to-variable interest rate contracts(a)(b)

~~7,100~~7,250

Fair value hedge

March 2035

Variable-to-fixed interest rate contracts

250

Cash flow hedge

January 2023

Derivatives not designated as hedging instruments

Variable-to-fixed interest rate contracts

~~2,500~~5,100

Mark-to-Market

December ~~2021~~2022

(a)The principal amount of hedged senior notes consisted of ~~$250~~$600 million included in “Current portion of debt” and ~~$6,850~~$6,650 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three months ended March 31, 2022, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 10 “Recent Accounting Pronouncements” for further information on Topic 848.

During the three months ended March 31, ~~2021,~~2022, we entered into fixed-to-variable interest rate swap agreements with a combined notional principal amount of ~~$375~~$400 million. These agreements were designated as accounting hedges and convert a portion of our fixed rate debt to variable ~~rate~~rates through February ~~2028.~~2032.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of March 31, ~~2021:~~

2022:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

EUR-to-USD cross currency swap contracts(a)

~~1,358~~543

Cash flow hedge

March 2027

(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.

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


Fair Value of Derivative Contracts	Fair Value of Derivative Contracts										Fair Value of Derivative Contracts
			Derivatives Asset				Derivatives Liability						Derivatives Asset				Derivatives Liability
			March 31, 2021		December 31, 2020		March 31, 2021		December 31, 2020				March 31, 2022		December 31, 2021		March 31, 2022		December 31, 2021
		Location	Fair value				Fair value					Location	Fair value				Fair value
			(In millions)										(In millions)
Derivatives designated as hedging instruments	Derivatives designated as hedging instruments										Derivatives designated as hedging instruments
Energy commodity derivative contracts	Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	13	$	42	$	(92)	$	(33)	Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	$	34	$	61	$	(398)	$	(141)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	6		33		(29)		(8)			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	5		3		(220)		(94)
Subtotal	Subtotal		19		75		(121)		(41)		Subtotal		39		64		(618)		(235)
Interest rate contracts	Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	126		119		(3)		(3)		Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	45		101		(4)		(3)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	364		575		(19)		(7)			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	106		284		(94)		(15)
Subtotal	Subtotal		490		694		(22)		(10)		Subtotal		151		385		(98)		(18)
Foreign currency contracts	Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	56		0		(12)		(6)		Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	—		35		(12)		(3)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	43		138		0		0			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	11		6		—		—
Subtotal	Subtotal		99		138		(12)		(6)		Subtotal		11		41		(12)		(3)
Total	Total		608		907		(155)		(57)		Total		201		490		(728)		(256)

Derivatives not designated as hedging instruments	Derivatives not designated as hedging instruments										Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	23		24		(33)		(21)		Energy commodity derivative contracts	Fair value of derivative contracts/(Other current liabilities)	20		11		(121)		(31)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	0		0		(1)		0			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	16		1		(57)		(6)
Subtotal											Subtotal		36		12		(178)		(37)
Interest rate contracts											Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	48		12		—		—

Subtotal											Subtotal		48		12		—		—

Total	Total		23		24		(34)		(21)		Total		84		24		(178)		(37)
Total derivatives	Total derivatives		$	631	$	931	$	(189)	$	(78)	Total derivatives		$	285	$	514	$	(906)	$	(293)

The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. 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
	Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
	(In millions)
As of March 31, 2022
Energy commodity derivative contracts(a)	$	35	$	40	$	—	$	75	$	(75)	$	—	$	—
Interest rate contracts	—		199		—		199		(25)		—		174
Foreign currency contracts	—		11		—		11		(11)		—		—
As of December 31, 2021
Energy commodity derivative contracts(a)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	—		41		—		41		(3)		—		38

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
(In millions)
As of March 31, 2021
Energy commodity derivative contracts(a) $ 10 $ 32 $ 0 $ 42 $ (37) $ 0 $ 5
Interest rate contracts 0 490 0 490 (9) 0 481
Foreign currency contracts 0 99 0 99 (12) 0 87
As of December 31, 2020
Energy commodity derivative contracts(a) $ 6 $ 93 $ 0 $ 99 $ (35) $ 0 $ 64
Interest rate contracts 0 694 0 694 (2) 0 692
Foreign currency contracts 0 138 0 138 (6) 0 132


		Balance sheet liability fair value measurements by level															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			Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral posted(b)		Net amount
		(In millions)															(In millions)
As of March 31, 2021
As of March 31, 2022																As of March 31, 2022
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	(12)	$	(143)	$	0	$	(155)	$	37	$	6	$	(112)	Energy commodity derivative contracts(a)	$	(141)	$	(655)	$	—	$	(796)	$	75	$	196	$	(525)
Interest rate contracts	Interest rate contracts	0		(22)		0		(22)		9		0		(13)		Interest rate contracts	—		(98)		—		(98)		25		—		(73)
Foreign currency contracts	Foreign currency contracts	0		(12)		0		(12)		12		0		0		Foreign currency contracts	—		(12)		—		(12)		11		—		(1)
As of December 31, 2020
As of December 31, 2021																As of December 31, 2021
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	(7)	$	(56)	$	0	$	(63)	$	35	$	(8)	$	(36)	Energy commodity derivative contracts(a)	$	(15)	$	(257)	$	—	$	(272)	$	53	$	—	$	(219)
Interest rate contracts	Interest rate contracts	0		(10)		0		(10)		2		0		(8)		Interest rate contracts	—		(18)		—		(18)		9		—		(9)
Foreign currency contracts	Foreign currency contracts	0		(6)		0		(6)		6		0		0		Foreign currency contracts	—		(3)		—		(3)		3		—		—

(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 ~~operations~~income and comprehensive ~~income (loss):~~income:


Derivatives in fair value hedging relationships	Derivatives in fair value hedging relationships	Location		Gain/(loss) recognized in income on derivative and related hedged item				Derivatives in fair value hedging relationships	Location		Gain/(loss) recognized in income on derivative and related hedged item
			Three Months Ended March 31,							Three Months Ended March 31,
				2021		2020					2022		2021
				(In millions)							(In millions)
Interest rate contracts	Interest rate contracts	Interest, net		$	(217)	$	433	Interest rate contracts	Interest, net		$	(317)	$	(217)

Hedged fixed rate debt(a)	Hedged fixed rate debt(a)	Interest, net		$	219	$	(440)	Hedged fixed rate debt(a)	Interest, net		$	320	$	219

(a)As of March 31, ~~2021,~~2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was an increase of ~~$484~~$56 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


Derivatives in cash flow hedging relationships	Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)				Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
		Three Months Ended March 31,					Three Months Ended March 31,					Three Months Ended March 31,					Three Months Ended March 31,
		2021		2020			2021		2020			2022		2021			2022		2021
		(In millions)					(In millions)					(In millions)					(In millions)
Energy commodity derivative contracts	Energy commodity derivative contracts	$	(158)	$	379	Revenues—Commodity sales	$	(20)	$	(8)	Energy commodity derivative contracts	$	(499)	$	(158)	Revenues—Commodity sales	$	(132)	$	(20)

						Costs of sales	4		(17)							Costs of sales	9		4
Interest rate contracts	Interest rate contracts	1		(8)		Earnings from equity investments(c)	0		0		Interest rate contracts	3		1		Earnings from equity investments(c)	—		—
Foreign currency contracts	Foreign currency contracts	(46)		(82)		Other, net	(61)		(23)		Foreign currency contracts	(40)		(46)		Other, net	(53)		(61)
Total	Total	$	(203)	$	289	Total	$	(77)	$	(48)	Total	$	(536)	$	(203)	Total	$	(176)	$	(77)

(a)We expect to reclassify approximately ~~$35~~$357 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of March 31, ~~2021~~2022 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)During the three months ended March 31, ~~2021~~2022 and ~~2020,~~2021, we recognized no gains ofand $6 million ~~and $12 million,~~gains, respectively, associated with a write-down of hedged inventory. All other amounts reclassified were the result of the hedged forecasted transactions actually affecting earnings (i.e., when the forecasted sales and purchases actually occurred).

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

Derivatives not designated as accounting hedges Location Gain/(loss) recognized in income on derivatives
Three Months Ended March 31,
2021 2020
(In millions)
Energy commodity derivative contracts Revenues—Commodity sales $ (631) $ 117
Costs of sales 163 4
Total(a) $ (468) $ 121


Derivatives not designated as accounting hedges	Location		Gain/(loss) recognized in income on derivatives
		Three Months Ended March 31,
			2022		2021
			(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales		$	(9)	$	(631)
	Costs of sales		(91)		163
	Earnings from equity investments		(5)		—
Interest rate contracts	Interest, net		36		—
Total(a)			$	(69)	$	(468)

(a)The three months ended March 31, ~~2021~~2022 and ~~2020~~2021 amounts include approximate gains of $18 million and losses of ~~$448 million and gains of $74~~$488 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, we had 0no outstanding letters of credit supporting our commodity price risk management program. As of March 31, ~~2021,~~2022, we had cash margins of ~~$30~~$254 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, ~~2020,~~2021, we had cash margins of $3$14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at March 31, ~~2021~~2022 represents ~~the net of~~ our initial margin requirements of ~~$24~~$58 million and ~~counterparty~~ variation margin requirements of ~~$6 million.~~$196 million posted by us with our counterparties. 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 March 31, ~~2021,~~2022, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post ~~$67~~$377 million of additional collateral.

1820

6. Revenue Recognition

Disaggregation of Revenues

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

Three Months Ended March 31, 2021
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b) $ 866 $ 59 $ 191 $ 0 $ 0 $ 1,116
Fee-based services 178 221 81 15 0 495
Total services 1,044 280 272 15 0 1,611
Commodity sales
Natural gas sales 3,319 0 0 1 (5) 3,315
Product sales 220 125 5 229 (10) 569
Total commodity sales 3,539 125 5 230 (15) 3,884
Total revenues from contracts with customers 4,583 405 277 245 (15) 5,495
Other revenues(c)
Leasing services(d) 119 43 143 12 (1) 316
Derivatives adjustments on commodity sales (618) 0 0 (33) 0 (651)
Other 41 5 0 5 0 51
Total other revenues (458) 48 143 (16) (1) (284)
Total revenues $ 4,125 $ 453 $ 420 $ 229 $ (16) $ 5,211


	Three Months Ended March 31, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	939	$	59	$	188	$	—	$	(1)	$	1,185
Fee-based services	213		234		98		13		—		558
Total services	1,152		293		286		13		(1)		1,743
Commodity sales
Natural gas sales	1,226		—		—		20		(4)		1,242
Product sales	342		426		4		348		(16)		1,104

Total commodity sales	1,568		426		4		368		(20)		2,346
Total revenues from contracts with customers	2,720		719		290		381		(21)		4,089
Other revenues(c)
Leasing services(d)	117		44		140		13		—		314
Derivatives adjustments on commodity sales	(39)		(3)		—		(99)		—		(141)
Other	15		6		—		10		—		31
Total other revenues	93		47		140		(76)		—		204
Total revenues	$	2,813	$	766	$	430	$	305	$	(21)	$	4,293

1921


		Three Months Ended March 31, 2020													Three Months Ended March 31, 2021
		Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total			Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
		(In millions)													(In millions)
Revenues from contracts with customers(a)	Revenues from contracts with customers(a)													Revenues from contracts with customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	865	$	79	$	189	$	0	$	0	$	1,133	Firm services(b)	$	866	$	59	$	191	$	—	$	—	$	1,116
Fee-based services	Fee-based services	193		260		121		13		0		587		Fee-based services	178		221		81		15		—		495
Total services	Total services	1,058		339		310		13		0		1,720		Total services	1,044		280		272		15		—		1,611
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	501		0		0		0		(2)		499		Natural gas sales	3,319		—		—		1		(5)		3,315
Product sales	Product sales	136		109		3		232		(13)		467		Product sales	220		125		5		229		(10)		569

Total commodity sales	Total commodity sales	637		109		3		232		(15)		966		Total commodity sales	3,539		125		5		230		(15)		3,884
Total revenues from contracts with customers	Total revenues from contracts with customers	1,695		448		313		245		(15)		2,686		Total revenues from contracts with customers	4,583		405		277		245		(15)		5,495
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	113		42		129		10		0		294		Leasing services(d)	119		43		143		12		(1)		316
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	52		0		0		52		0		104		Derivatives adjustments on commodity sales	(618)		—		—		(33)		—		(651)
Other	Other	15		5		0		2		0		22		Other	41		5		—		5		—		51
Total other revenues	Total other revenues	180		47		129		64		0		420		Total other revenues	(458)		48		143		(16)		(1)		(284)
Total revenues	Total revenues	$	1,875	$	495	$	442	$	309	$	(15)	$	3,106	Total revenues	$	4,125	$	453	$	420	$	229	$	(16)	$	5,211

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

(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 were primarily from leases and derivative contracts. See Note 5 for additional information related to our derivative contracts.

(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases 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 facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of both March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, our contract asset balances were ~~$31 million and $20 million, respectively.~~$39 million. Of the contract asset balance at December 31, ~~2020, $9~~2021, $16 million was transferred to accounts receivable during the three months ended March 31, ~~2021.~~2022. As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, our contract liability balances were ~~$243~~$222 million and ~~$239~~$212 million, respectively. Of the contract liability balance at December 31, ~~2020, $24~~2021, $35 million was recognized as revenue during the three months ended March 31, ~~2021.~~2022.

2022

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of March 31, ~~2021~~2022 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Year	Estimated Revenue		Year	Estimated Revenue
		(In millions)			(In millions)
Nine months ended December 31, 2021		$	3,276
2022		3,626
Nine months ended December 31, 2022				Nine months ended December 31, 2022	$	3,244
2023	2023	2,924		2023	3,595
2024	2024	2,508		2024	2,987
2025	2025	2,124		2025	2,453
2026				2026	2,158
Thereafter	Thereafter	13,585		Thereafter	12,760
Total	Total	$	28,043	Total	$	27,197

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 expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

7. Reportable Segments

Financial information by segment follows:


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions)						(In millions)
Revenues	Revenues						Revenues
Natural Gas Pipelines	Natural Gas Pipelines						Natural Gas Pipelines
Revenues from external customers	Revenues from external customers		$	4,110	$	1,861	Revenues from external customers		$	2,793	$	4,110
Intersegment revenues	Intersegment revenues		15		14		Intersegment revenues		20		15

Products Pipelines	Products Pipelines		453		495		Products Pipelines		766		453

Terminals	Terminals						Terminals
Revenues from external customers	Revenues from external customers		419		441		Revenues from external customers		429		419
Intersegment revenues	Intersegment revenues		1		1		Intersegment revenues		1		1
CO2	CO2		229		309		CO2		305		229

Corporate and intersegment eliminations	Corporate and intersegment eliminations		(16)		(15)		Corporate and intersegment eliminations		(21)		(16)
Total consolidated revenues	Total consolidated revenues		$	5,211	$	3,106	Total consolidated revenues		$	4,293	$	5,211

2123


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions)						(In millions)
Segment EBDA(a)	Segment EBDA(a)						Segment EBDA(a)
Natural Gas Pipelines	Natural Gas Pipelines		$	2,103	$	1,196	Natural Gas Pipelines		$	1,184	$	2,103
Products Pipelines	Products Pipelines		248		269		Products Pipelines		299		248
Terminals	Terminals		227		257		Terminals		238		227
CO2	CO2		286		(755)		CO2		192		286

Total Segment EBDA	Total Segment EBDA		2,864		967		Total Segment EBDA		1,913		2,864
DD&A	DD&A		(541)		(565)		DD&A		(538)		(541)
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments		(22)		(32)		Amortization of excess cost of equity investments		(19)		(22)

General and administrative and corporate charges	General and administrative and corporate charges		(148)		(165)		General and administrative and corporate charges		(145)		(148)
Interest, net	Interest, net		(377)		(436)		Interest, net		(333)		(377)

Income tax expense	Income tax expense		(351)		(60)		Income tax expense		(194)		(351)

Total consolidated net income (loss)			$	1,425	$	(291)
Total consolidated net income							Total consolidated net income		$	684	$	1,425


		March 31, 2021		December 31, 2020			March 31, 2022		December 31, 2021
		(In millions)					(In millions)
Assets	Assets					Assets
Natural Gas Pipelines	Natural Gas Pipelines	$	48,262	$	48,597	Natural Gas Pipelines	$	47,580	$	47,746
Products Pipelines	Products Pipelines	9,152		9,182		Products Pipelines	9,143		9,088
Terminals	Terminals	8,560		8,639		Terminals	8,465		8,513
CO2	CO2	2,517		2,478		CO2	2,895		2,843

Corporate assets(b)	Corporate assets(b)	2,717		3,077		Corporate assets(b)	1,052		2,226

Total consolidated assets	Total consolidated assets	$	71,208	$	71,973	Total consolidated assets	$	69,135	$	70,416

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

(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, including income tax related assets, risk management assets related to 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.

8. Income Taxes

Income tax expense included in our accompanying consolidated statements of ~~operations~~income is as follows:


		Three Months Ended March 31,								Three Months Ended March 31,
			2021			2020					2022			2021
			(In millions, except percentages)								(In millions, except percentages)
Income tax expense	Income tax expense		$	351		$	60		Income tax expense		$	194		$	351
Effective tax rate	Effective tax rate		19.8		%	(26.0)		%	Effective tax rate		22.1		%	19.8		%

The effective tax rate for the three months ended March 31, 2022 is higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings, and Products (SE) Pipe Line Company (PPL).

The effective tax rate for the three months ended March 31, 2021 is lower than the statutory federal rate of 21% primarily due to the release of the valuation allowance on our investment in NGPL Holdings upon the sale of a partial interest in NGPL Holdings, and dividend-received deductions from our investments in Citrus, ~~Corporation (Citrus),~~ NGPL Holdings and ~~Products (SE) Pipe Line Corporation (PPL),~~PPL, partially offset by state income taxes.

The effective tax rate for the three months ended March 31, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to a $600 million impairment of goodwill, which is a reduction to income but is not deductible for tax purposes. This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investment in Citrus and PPL. 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 a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for the period.~~

9. 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 to our 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 the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

SFPP FERC Proceedings

The FERC approved the SFPP ~~East~~North, Oregon, and West Line Settlement in Docket No. ~~IS21-138 (“EL Settlement”)~~IS22-100 (NOW Settlement) on ~~December 31, 2020~~January 14, 2022 and ~~it became~~the settlement is final and effective on February 2, 2021. The EL Settlement resolved certain dockets in their entirety (IS09-437 and OR16-6) and resolved the SFPP East Line related disputes in other dockets which remain ongoing (OR14-35/36 and OR19-21/33/37).effective. The amounts SFPP agreed to pay pursuant to the ELNOW Settlement were fully accrued on or before December 31, ~~2020.~~2021. Together with the East Line Settlement (which the FERC approved previously on December 31, 2020 in Docket No. IS21-138), the NOW Settlement resolves all remaining disputes before the FERC relating to SFPP (including Docket Nos. OR11-13, OR11-16, OR11-18, OR14-35, OR14-36, OR19-21, OR19-33, and OR19-37) and establishes a moratorium with settling shippers that prohibits the filing of a protest or complaint against SFPP’s FERC rates until February 1, 2025.

~~The tariffs~~EPNG FERC Proceeding

On April 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceeding against it pursuant to section 5 of the Natural Gas Act. This proceeding sets the matter for hearing to determine whether EPNG’s current rates remain just and reasonable. A proceeding under section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged ~~by SFPP which were not fully resolved by the EL Settlement are subject~~ to a number of ongoing shipper-initiated proceedings at the FERC. 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, theycustomers, if any, would be entitled to seek reparations for the two-year period preceding the filing date of their complaints and/or prospective refunds in protest cases from the date of protest, and SFPP may be required to reduce its rates going forward. With respect to the ongoing shipper-initiated proceedings atlikely only occur after the FERC ~~that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million~~has issued a final order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in ~~rate refunds and unspecified rate reductions as of the date of their complaints~~late May 2023, with a final FERC decision anticipated in 2014 and 2018. The claims pleaded by the shippers are expected to change due to the passage of time and interest. These proceedings tend to be protracted, with decisions of the FERC often appealed to the federal courts. Management believes SFPP has meritorious arguments supporting SFPP’s rates and intends to vigorously defend SFPP against these complaints and protests.late 2023. We do not believe that the ultimate resolution of ~~the shipper complaints and protests seeking rate reductions or refunds in the ongoing proceedings~~this proceeding will have a material adverse impact onto our business.

Gulf LNG Facility 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~~tribunal delivered ~~its~~an Award ~~and the panel's ruling~~that 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 February 1, 2019, the Delaware Court of Chancery issued a Final Order and Judgment confirming the Award, which was paid by Eni USA on February 20, 2019.

On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement entered into by Eni S.p.A. in connection with the terminal use agreement. ~~On December 12, 2018,~~In response to the foregoing lawsuit, Eni S.p.A. filed counterclaims under the terminal use agreement and claims under a ~~counterclaim seeking~~parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing claims asserted by Eni S.p.A seek unspecified damages ~~from GLNG. This lawsuit remains pending.~~and involve the same allegations as the claims which were resolved conclusively in the arbitrations with Eni USA described above and with GLNG’s remaining customer as described below. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the Guarantee Agreement. GLNG filed an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal, the foregoing counterclaims and other claims asserted by Eni S.p.A under the terminal use agreement and parent direct agreement remain pending in the trial court.

2325

On June 3, 2019, Eni USA filed a second Notice of Arbitration against GLNG asserting the same breach of contract 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 sought to recover as damages some or all of the payments made by Eni USA to satisfy the Final Order and Judgment of the Court of Chancery. In response to the second Notice of Arbitration, GLNG filed a complaint with the Court of Chancery together with a motion seeking to permanently enjoin the arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from re-arbitrating both the breach of contract and negligent misrepresentation claims. On April 15, 2021, Eni USA filed a petition for writ of certiorari with the U.S. Supreme Court seeking review of the Delaware Supreme Court’s decision. This petition remains pending.

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. ALSS also ~~seeks~~sought a declaration on substantially the same allegations asserted previously by Eni USA in arbitration that activities allegedly undertaken by affiliates of Gulf LNG Holdings Group LLC in connection with the pursuit of an LNG liquefaction export project ~~have given~~gave rise to a contractual right on the part of ALSS to terminate the agreement. ~~ALSS also seeks a monetary award directing GLNG~~On July 15, 2021, the arbitration tribunal delivered an Award on the merits of all claims submitted to ~~reimburse ALSS for all reservation charges~~the tribunal and ~~operating fees paid by ALSS after December 31, 2016 plus interest. A final decision in this arbitration is expected before the end of the third quarter of 2021.~~

~~GLNG intends to continue to vigorously prosecute and defend~~denied all of ALSS’s claims with prejudice. On November 23, 2021, the ~~foregoing proceedings.~~Delaware Court of Chancery issued a Final Order and Judgment confirming the Award.

Continental Resources, Inc. v. Hiland Partners Holdings, LLC

On December 8, 2017, Continental Resources, Inc. (CLR) filed an action in 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 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 specific dates nullifies the release contained in the settlement agreement. CLR’s amended petition makes additional claims under both the GPA and a May 8, 2008 gas purchase contract covering additional North Dakota counties, including CLR’s contention that Hiland Partners is not allowed to deduct third-party processing fees from the gas purchase price. CLR seeks damages in excess of ~~$225~~$276 million. ~~Hiland Partners denies~~We deny and ~~will~~are vigorously ~~defend~~defending against these claims.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed suit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. We believe that our declaration of force majeure is valid and appropriate and are vigorously defending against these claims.

Pipeline Integrity and Releases

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

General

As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, our total reserve for legal matters was ~~$130~~$164 million and ~~$273~~$231 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal 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 could result in substantial costs and liabilities to us, 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.

We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. 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 will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.

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, crude oil, NGL, natural gas or 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 (PHSS). The cost for the final remedy is estimated ~~by the EPA~~ to be more than $3$2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 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) 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 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. At this time we anticipate the non-judicial allocation process will be complete in or around ~~June~~October 2023. 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 PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the 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. The U.S. District Court issued an order on April 16, 2019 that allocated 35% of past and future response costs to the U.S. 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 our share of the costs of the remediation will have a material adverse impact to our 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,~~(collectively EPEC) are ~~involved~~identified as PRPs 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~~River in New Jersey. 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~~obligates EPEC to investigate and characterize contamination at the Site. ~~They are also~~EPEC is 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~~a Record of Decision (ROD) for the lower 8 miles of the Site. At that time the ~~final~~ cleanup plan in the ROD was 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 underway. Initial expectations were that the design work would take four years to complete. The cleanup is expected to take at least six years to complete once it begins.

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. That process was completed December 28, ~~2020. We anticipate the~~2020 and certain PRPs, including EPEC, ~~Polymers, will engage~~are engaged in ~~further~~ discussions with the EPA ~~during 2021.~~as a result thereof. 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 EPA FS directive for the upper nine miles of the Site not subject to the~~ lower eight mile ROD. ~~In a letter dated~~On October ~~10, 2018,~~4, 2021, the EPA ~~directed the CPG to prepare~~issued a ~~streamlined FS~~ROD for the ~~Site that evaluates interim remedy alternatives for sediments in the~~ upper ~~nine~~9 miles of the Site. ~~Until~~The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, ~~engage~~including EPEC, are engaged in discussions with the EPA concerning the ~~FS is completed,~~upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the ~~RI/FS is finalized,~~remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. ~~Because costs associated with any remedial plan are expected to be spread over at least several years, we~~We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the ~~remediation~~Site, will have a material adverse impact to our business.

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) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. 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 caused substantial damage to the coastal waters and nearby lands. Plaquemines Parish seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In ~~May 2018,~~December 2013, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In ~~May 2019,~~April 2015, the U.S. District Court ordered the case ~~was~~to be remanded to the state district court for Plaquemines Parish. AtIn May 2018, the ~~same~~case was removed for a second time to the U.S. District Court. In May 2019, the U.S. District Court ~~certified~~ordered the case to be remanded to the state district court. The case is effectively stayed pending the resolution of jurisdictional issues in separate, consolidated cases to which TGP is not a party; The Parish of Plaquemines, et al. vs. Chevron USA, Inc. et al. consolidated with The Parish of Cameron, et al. v. BP America Production Company, et al. Those cases were removed to federal ~~jurisdiction issue~~court and ordered to be remanded to the state district courts for ~~review by~~Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases are pursuing an appeal of the ~~U.S. Fifth Circuit~~remand decisions to the United States Court of ~~Appeals. On August 10, 2020,~~Appeals for the Fifth Circuit ~~affirmed remand.The defendants filed a motion for rehearing which~~to determine whether there is ~~pending.~~federal officer jurisdiction. The case remains effectively stayed pending a ~~final~~ ruling by the ~~Court of Appeals.~~Fifth Circuit in the consolidated 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.

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 waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 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 several separate lawsuits in state district courts in Louisiana against a number of oil and gas pipeline companies, including ~~3 cases against TGP, 2 cases against SNG, and 1 case 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. The Plaintiffs allege 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. The plaintiffs seek, among other relief, unspecified money damages, attorney 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. The Plaintiffs also seek a declaration that the defendants are obligated to take steps to maintain canals and canal banks going forward. We have resolved two of these cases and we will continue to vigorously defend the remaining cases.While it is not possible to predict the ultimate outcomes, we believe the resolution of these cases will not have a material adverse impact to our business.

Products Pipeline Incident, Walnut Creek, California

On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue over the next several days and on November 24, 2020, identified a crack in the pipeline and notified the regulatory agencies of a “confirmed release.” The damaged section of the pipeline was removed and replaced, and the pipeline resumed operations on November 26, 2020. We reported the estimated volume of gasoline released to be 8.1 Bbl. On December 2, 2020, complaints of gasoline odors were reported along the LS-16 pipeline corridor in Walnut Creek. A unified response was implemented by us along with the U.S. EPA, the California Office of Spill Prevention and Response, the California Fire Marshall, and the San Francisco Regional Water Quality Control Board. On December 8, 2020, we reported an updated estimated spill volume of up to 1,000 Bbl.

On October 28, 2021, we were informed by the California Attorney General it was contemplating criminal charges against us asserting the November 2020 discharge of gasoline affected waters of the State of California, and there was a failure to make timely notices of this discharge to appropriate state agencies. On December 16, 2021, we entered into a plea agreement with the State of California to resolve misdemeanor charges of the unintentional, non-negligent discharge of gasoline resulting from the release and the claimed failure to provide timely notices of the discharge to appropriate state agencies. Under the plea agreement, SFPP plead no-contest to two misdemeanors and paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months.

Since the November 2020 release, we have cooperated fully with federal and state agencies and have worked diligently to remediate the affected areas. We anticipate civil enforcement actions by federal and state agencies arising from the November 2020 release as well as ongoing monitoring and, where necessary, remediation under the oversight of the San Francisco Regional Water Quality Control Board until site conditions demonstrate no further actions are required. We do not anticipate the costs to resolve those enforcement matters, including the costs to monitor and further remediate the site, will have a material adverse impact to our business.

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. As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, we have accrued a total reserve for environmental liabilities in the amount of ~~$256~~$240 million and ~~$250~~$243 million, respectively. In addition, as of both March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

10. Recent Accounting Pronouncements

Accounting Standards Updates

Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued ~~Accounting Standards Update (ASU)~~ASU No. 2020-04, “Reference Rate Reform - Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing ~~Rate.~~ Rate (SOFR).

Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are 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.

On January 7, 2021, the FASB issued ASU No. 2021-01, “Reference Rate Reform (Topic 848): Scope.” This ASU clarifies that all derivative instruments affected by changes to the interest rates used for discounting, margining or contract price alignment (the “Discounting Transition”) are in the scope of ASC 848 and therefore qualify for the available temporary optional expedients and exceptions. As such, entities that employ derivatives that are the designated hedged item in a hedge relationship where perfect effectiveness is assumed can continue to apply hedge accounting without de-designating the hedging relationship to the extent such derivatives are impacted by the Discounting Transition.

The guidance iswas effective upon issuance and generally can be applied through December 31, 2022. ~~We are currently reviewing the effect of Topic 848 to our financial statements.~~

~~ASU No. 2020-06~~

~~On August 5, 2020,~~During the ~~FASB issued ASU No. 2020-06, “Debt - Debt~~first quarter of 2022 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $625 million and convert a portion of our fixed rate debt to variable rates through March 2035. Concurrent with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.~~” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two~~these amendments, we elected certain of the ~~three models~~optional expedients provided in ~~ASC 470-20 that require separate~~Topic 848 which allow us to maintain our prior designation of fair value hedge accounting to these agreements. As we continue to amend our interest rate swap agreements to transition from LIBOR to SOFR, we will assess whether such amendments qualify for ~~embedded conversion features; (ii) amends diluted EPS calculations for convertible instruments by requiring the use~~any of the ~~if-converted method;~~optional expedients in Topic 848 and, ~~(iii) simplifies the settlement assessment entities are required~~should they qualify, whether we wish to ~~perform~~elect any such optional expedients. See Note 5 “Risk Management—Interest Rate Risk Management” for more information on contracts that can potentially settle in an entity’s own equity by removing certain requirements. ASU No. 2020-06 will be effective for us for the fiscal year beginning January 1, 2022, and earlier adoption is permitted. We are currently reviewing the effect of this ASU to our ~~financial statements.~~

interest rate risk management activities.

2830

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;~~notes in our 2021 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our ~~2020~~2021 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our ~~2020~~2021 Form 10-K; and (iv) “Risk Factors” in our ~~2020~~2021 Form 10-K.

~~Sale of an Interest in NGPL Holdings LLC~~

On March 8, 2021, we and Brookfield Infrastructure Partners L.P. (Brookfield) completed the sale of a combined 25% interest in our joint venture, NGPL Holdings LLC (NGPL Holdings), to a fund controlled by ArcLight Capital Partners, LLC (ArcLight). We received net proceeds of $413 million for our proportionate share of the interests sold which included the transfer of $125 million of our $500 million related party promissory note receivable from NGPL Holdings to ArcLight with quarterly interest payments at 6.75%. We recognized a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net” in our accompanying consolidated statement of operations for the three months ended March 31, 2021. Upon closing, we and Brookfield each hold a 37.5% interest in NGPL Holdings.

~~February 2021 Winter Storm~~

Our first quarter earnings reflect impacts of the February 2021 winter storm that affected Texas, which are largely nonrecurring. See “—Segment Earnings Results” below. Some of the transactions executed during the winter storm remain subject to risks, including counterparty financial risk, potential disputed purchases and sales and potential legislative or regulatory action in response to, or litigation arising out of, the unprecedented circumstances of the winter storm, which could adversely affect our future earnings, cash flows and financial condition.

~~2021~~2022 Dividends and Discretionary Capital

We expect to declare dividends of ~~$1.08~~$1.11 per share for ~~2021,~~2022, a 3% increase from the ~~2020~~2021 declared dividends of ~~$1.05~~$1.08 per share. We ~~also~~now expect to invest ~~$0.8~~$1.5 billion in expansion projects and contributions to joint ventures or discretionary capital expenditures during ~~2021.~~2022.

The expectations for ~~2021~~2022 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 statement. ~~Furthermore, we plan to provide updates to these 2021 expectations when we believe previously disclosed expectations no longer have a reasonable basis.~~

Results of Operations

Overview

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

GAAP Financial Measures

The Consolidated Earnings Results for the three months ended March 31, ~~2021~~2022 and ~~2020~~2021 present Segment EBDA and ~~net~~Net income ~~(loss)~~ attributable to 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 Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP ~~net~~Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP 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 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.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in ~~net~~Net income ~~(loss)~~ attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and 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). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(Loss)~~ Attributable to Kinder Morgan, Inc. (GAAP) to

Adjusted EBITDA” and “—Non-GAAP 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 “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting ~~net~~Net income ~~(loss)~~ attributable to 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 our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is ~~net~~Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings ~~(loss)~~ per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(Loss)~~ Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted Earnings to DCF” below.

DCF

DCF is calculated by adjusting ~~net~~Net income ~~(loss)~~ attributable to 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. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). 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 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~~Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(Loss)~~ Attributable to 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 useful performance metric because it provides management and external users of our financial statements additional insight into the ability of our segments to generate 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. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, 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~~Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. In prior periods Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures. See “—Adjusted Segment EBDA to Adjusted EBITDA to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income ~~(Loss)~~ Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” below.

Amounts from Joint Ventures

Certain Items, DCF and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculations of DCF and Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include the same items (DD&A and income tax expense, and for DCF only, also cash taxes and sustaining capital expenditures) with respect to the joint ventures as those included in the calculations of DCF and Adjusted EBITDA for our wholly-owned consolidated subsidiaries. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of

DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of March 31, ~~2021,~~2022, by subtracting the following amounts from our debt balance of ~~$33,234~~$32,083 million: (i) cash and cash equivalents of ~~$1,377~~$84 million; (ii) debt fair value adjustments of ~~$1,054~~$584 million; and (iii) the foreign exchange impact on Euro-denominated bonds of ~~$109~~$10 million for which we have entered into currency ~~swaps.~~swaps to convert that debt to U.S. dollars. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.

Consolidated Earnings Results (GAAP)

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


		Three Months Ended March 31,									Three Months Ended March 31,
		2021		2020		Earnings increase/(decrease)					2022		2021		Earnings increase/(decrease)
		(In millions, except percentages)									(In millions, except percentages)
Segment EBDA(a)	Segment EBDA(a)									Segment EBDA(a)
Natural Gas Pipelines	Natural Gas Pipelines	$	2,103	$	1,196	$	907	76	%	Natural Gas Pipelines	$	1,184	$	2,103	$	(919)	(44)	%
Products Pipelines	Products Pipelines	248		269		(21)		(8)	%	Products Pipelines	299		248		51		21	%
Terminals	Terminals	227		257		(30)		(12)	%	Terminals	238		227		11		5	%
CO2	CO2	286		(755)		1,041		138	%	CO2	192		286		(94)		(33)	%

Total Segment EBDA	Total Segment EBDA	2,864		967		1,897		196	%	Total Segment EBDA	1,913		2,864		(951)		(33)	%
DD&A	DD&A	(541)		(565)		24		4	%	DD&A	(538)		(541)		3		1	%
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(22)		(32)		10		31	%	Amortization of excess cost of equity investments	(19)		(22)		3		14	%

General and administrative and corporate charges	General and administrative and corporate charges	(148)		(165)		17		10	%	General and administrative and corporate charges	(145)		(148)		3		2	%

Interest, net	Interest, net	(377)		(436)		59		14	%	Interest, net	(333)		(377)		44		12	%
Income (loss) before income taxes		1,776		(231)		2,007		869	%
Income before income taxes										Income before income taxes	878		1,776		(898)		(51)	%
Income tax expense	Income tax expense	(351)		(60)		(291)		(485)	%	Income tax expense	(194)		(351)		157		45	%

Net income (loss)		1,425		(291)		1,716		590	%
Net income										Net income	684		1,425		(741)		(52)	%
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(16)		(15)		(1)		(7)	%	Net income attributable to noncontrolling interests	(17)		(16)		(1)		(6)	%
Net income (loss) attributable to Kinder Morgan, Inc.		$	1,409	$	(306)	$	1,715	560	%
Net income attributable to Kinder Morgan, Inc.										Net income attributable to Kinder Morgan, Inc.	$	667	$	1,409	$	(742)	(53)	%

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

Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. ~~increased $1,715~~decreased $742 million in ~~2021~~2022 compared to ~~2020.~~2021. The ~~increase~~decrease primarily resulted from the benefit in ~~results were impacted by higher~~the 2021 period of $1,077 million for largely nonrecurring earnings related to the February 2021 winter storm, mostly impacting the earnings from our Natural Gas Pipelines and CO2business segments ~~primarily related to the February 2021 winter storm and therefore largely nonrecurring, a combined $950 million of non-cash impairments of goodwill associated with our CO~~2 ~~reporting unit and of certain oil and gas producing assets in our CO~~2 ~~business segment recognized in 2020, lower interest expense and DD&A expense,~~ partially offset by lower income tax expense and higher earnings from our ~~Terminals and~~ Products Pipelines business ~~segments.~~segment.

3233

Certain Items Affecting Consolidated Earnings Results

Three Months Ended March 31,
2021 2020
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 2,103 $ (9) $ 2,094 $ 1,196 $ (17) $ 1,179 $ 915
Products Pipelines 248 15 263 269 4 273 (10)
Terminals 227 — 227 257 — 257 (30)
CO2
286 5 291 (755) 930 175 116
Total Segment EBDA(a) 2,864 11 2,875 967 917 1,884 991
DD&A and amortization of excess cost of equity investments (563) — (563) (597) — (597) 34
General and administrative and corporate charges(a) (148) — (148) (165) 25 (140) (8)
Interest, net(a) (377) (6) (383) (436) 1 (435) 52
Income (loss) before income taxes 1,776 5 1,781 (231) 943 712 1,069
Income tax expense(b) (351) (40) (391) (60) (96) (156) (235)
Net income (loss) 1,425 (35) 1,390 (291) 847 556 834
Net income attributable to noncontrolling interests(a) (16) — (16) (15) — (15) (1)
Net income (loss) attributable to Kinder Morgan, Inc. $ 1,409 $ (35) $ 1,374 $ (306) $ 847 $ 541 $ 833


	Three Months Ended March 31,
	2022						2021
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,184	$	113	$	1,297	$	2,103	$	(9)	$	2,094	$	(797)
Products Pipelines	299		—		299		248		15		263		36
Terminals	238		—		238		227		—		227		11
CO2	192		16		208		286		5		291		(83)

Total Segment EBDA(a)	1,913		129		2,042		2,864		11		2,875		(833)
DD&A and amortization of excess cost of equity investments	(557)		—		(557)		(563)		—		(563)		6
General and administrative and corporate charges(a)	(145)		—		(145)		(148)		—		(148)		3
Interest, net(a)	(333)		(44)		(377)		(377)		(6)		(383)		6
Income before income taxes	878		85		963		1,776		5		1,781		(818)
Income tax expense(b)	(194)		(20)		(214)		(351)		(40)		(391)		177
Net income	684		65		749		1,425		(35)		1,390		(641)
Net income attributable to noncontrolling interests(a)	(17)		—		(17)		(16)		—		(16)		(1)

Net income attributable to Kinder Morgan, Inc.	$	667	$	65	$	732	$	1,409	$	(35)	$	1,374	$	(642)

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

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

Net income ~~(loss)~~ attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings) ~~increased~~decreased by ~~$833~~$642 million ~~in 2021 compared to 2020. The increase in Adjusted Segment EBDA was impacted by higher~~from the prior year resulting from earnings decreases of $834 million from our Natural Gas Pipelines business segment’s Midstream region and $93 million from our CO2 business ~~segments~~segment’s oil and gas producing activities (both primarily related to the February 2021 winter storm, and therefore largely ~~nonrecurring, and lower interest expense and DD&A expense~~nonrecurring) partially offset by lower income tax expense and higher earnings from our ~~Terminals and~~ Products Pipelines business ~~segments.~~segment.

3334

Non-GAAP Financial Measures

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


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions)						(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)			$	1,409	$	(306)
Net income attributable to Kinder Morgan, Inc. (GAAP)							Net income attributable to Kinder Morgan, Inc. (GAAP)		$	667	$	1,409
Total Certain Items	Total Certain Items		(35)		847		Total Certain Items		65		(35)
Adjusted Earnings(a)	Adjusted Earnings(a)		1,374		541		Adjusted Earnings(a)		732		1,374
DD&A and amortization of excess cost of equity investments for DCF(b)	DD&A and amortization of excess cost of equity investments for DCF(b)		638		691		DD&A and amortization of excess cost of equity investments for DCF(b)		623		638
Income tax expense for DCF(a)(b)	Income tax expense for DCF(a)(b)		419		181		Income tax expense for DCF(a)(b)		235		419
Cash taxes(b)	Cash taxes(b)		1		(3)		Cash taxes(b)		(1)		1
Sustaining capital expenditures(b)	Sustaining capital expenditures(b)		(107)		(141)		Sustaining capital expenditures(b)		(125)		(107)
Other items(c)	Other items(c)		4		(8)		Other items(c)		(9)		4
DCF	DCF		$	2,329	$	1,261	DCF		$	1,455	$	2,329

Adjusted Segment EBDA to Adjusted EBITDA to DCF


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions, except per share amounts)						(In millions, except per share amounts)
Natural Gas Pipelines	Natural Gas Pipelines		$	2,094	$	1,179	Natural Gas Pipelines		$	1,297	$	2,094
Products Pipelines	Products Pipelines		263		273		Products Pipelines		299		263
Terminals	Terminals		227		257		Terminals		238		227
CO2	CO2		291		175		CO2		208		291

Adjusted Segment EBDA(a)	Adjusted Segment EBDA(a)		2,875		1,884		Adjusted Segment EBDA(a)		2,042		2,875
General and administrative and corporate charges(a)	General and administrative and corporate charges(a)		(148)		(140)		General and administrative and corporate charges(a)		(145)		(148)
Joint venture DD&A and income tax expense(a)(b)	Joint venture DD&A and income tax expense(a)(b)		103		119		Joint venture DD&A and income tax expense(a)(b)		87		103
Net income attributable to noncontrolling interests(a)	Net income attributable to noncontrolling interests(a)		(16)		(15)		Net income attributable to noncontrolling interests(a)		(17)		(16)
Adjusted EBITDA	Adjusted EBITDA		2,814		1,848		Adjusted EBITDA		1,967		2,814
Interest, net(a)	Interest, net(a)		(383)		(435)		Interest, net(a)		(377)		(383)
Cash taxes(b)	Cash taxes(b)		1		(3)		Cash taxes(b)		(1)		1
Sustaining capital expenditures(b)	Sustaining capital expenditures(b)		(107)		(141)		Sustaining capital expenditures(b)		(125)		(107)

Other items(c)	Other items(c)		4		(8)		Other items(c)		(9)		4
DCF	DCF		$	2,329	$	1,261	DCF		$	1,455	$	2,329

Adjusted Earnings per share	Adjusted Earnings per share		$	0.60	$	0.24	Adjusted Earnings per share		$	0.32	$	0.60
Weighted average shares outstanding for dividends(d)	Weighted average shares outstanding for dividends(d)		2,277		2,277		Weighted average shares outstanding for dividends(d)		2,280		2,277
DCF per share	DCF per share		$	1.02	$	0.55	DCF per share		$	0.64	$	1.02
Declared dividends per share	Declared dividends per share		$	0.27	$	0.2625	Declared dividends per share		$	0.2775	$	0.27

(a)Amounts are adjusted for Certain Items. See tables included in “—Reconciliation of Net Income ~~(Loss)~~ Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Supplemental Information” below.

(b)Includes or represents DD&A, income tax expense, cash taxes and/or sustaining capital expenditures (as applicable for each item) from joint ventures. See tables included in “—Supplemental Information” below.

(c)Includes pension contributions, non-cash pension expense and non-cash compensation associated with our restricted stock ~~program, non-cash pension expense and pension contributions.~~program.

(d)Includes restricted stock awards that participate in ~~share~~ dividends.

3435

Reconciliation of Net Income ~~(Loss)~~ Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions)						(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)(a)			$	1,409	$	(306)
Net income attributable to Kinder Morgan, Inc. (GAAP)							Net income attributable to Kinder Morgan, Inc. (GAAP)		$	667	$	1,409
Certain Items:	Certain Items:						Certain Items:
Fair value amortization	Fair value amortization		(4)		(8)		Fair value amortization		(4)		(4)
Legal, environmental and taxes other than income tax reserves	Legal, environmental and taxes other than income tax reserves		84		(8)		Legal, environmental and taxes other than income tax reserves		—		84
Change in fair value of derivative contracts~~(b)~~(a)	Change in fair value of derivative contracts~~(b)~~(a)		14		(36)		Change in fair value of derivative contracts~~(b)~~(a)		82		14
(Gain) loss on divestitures, impairments and other write-downs, net(c)			(89)		371
Loss on impairment of goodwill(d)			—		600
Gain on divestitures, impairments and other write-downs, net(b)							Gain on divestitures, impairments and other write-downs, net(b)		—		(89)

Income tax Certain Items	Income tax Certain Items		(40)		(96)		Income tax Certain Items		(20)		(40)

Other	Other		—		24		Other		7		—
Total Certain Items~~(e)~~(c)	Total Certain Items~~(e)~~(c)		(35)		847		Total Certain Items~~(e)~~(c)		65		(35)
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments		563		597		DD&A and amortization of excess cost of equity investments		557		563
Income tax expense~~(f)~~(d)	Income tax expense~~(f)~~(d)		391		156		Income tax expense~~(f)~~(d)		214		391
Joint venture DD&A and income tax expense~~(g)~~(e)	Joint venture DD&A and income tax expense~~(g)~~(e)		103		119		Joint venture DD&A and income tax expense~~(g)~~(e)		87		103
Interest, net~~(f)~~(d)	Interest, net~~(f)~~(d)		383		435		Interest, net~~(f)~~(d)		377		383

Adjusted EBITDA	Adjusted EBITDA		$	2,814	$	1,848	Adjusted EBITDA		$	1,967	$	2,814

(a)In prior periods, Net income (loss) was considered the comparable GAAP measure and has been updated to Net income (loss) attributable to Kinder Morgan, Inc. for consistency with our other non-GAAP performance measures.

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

~~(c)~~(b)2021 amount includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings LLC, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, ~~Ruby. 2020 amount includes a pre-tax non-cash impairment loss of $350 million related to oil and gas producing assets in our CO~~2 ~~business segment driven by low oil prices and $21 million for asset impairments in our Products Pipelines business segment, which are~~Ruby, reported within ~~“(Gain) loss on divestitures~~“Other, net” and ~~impairments, net”~~“Earnings from equity investments,” respectively, on the accompanying consolidated statement of ~~operations.~~income.

~~(d)~~(c)~~2020 amount represents a non-cash impairment of goodwill associated with our CO~~2 ~~reporting unit.~~

~~(e)~~2022 and 2021 ~~amount includes~~amounts include $5 million and $117 million, ~~and 2020 amount includes less than $1 million~~respectively, reported within “Earnings from equity investments” on our consolidated statements of ~~operations.~~income.

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

~~(g)~~(e)Represents joint venture DD&A and income tax expense. See tables included in “—Supplemental Information” below.

3536

Supplemental Information


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions)						(In millions)
DD&A (GAAP)	DD&A (GAAP)		$	541	$	565	DD&A (GAAP)		$	538	$	541
Amortization of excess cost of equity investments (GAAP)	Amortization of excess cost of equity investments (GAAP)		22		32		Amortization of excess cost of equity investments (GAAP)		19		22
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments		563		597		DD&A and amortization of excess cost of equity investments		557		563
Joint venture DD&A	Joint venture DD&A		75		94		Joint venture DD&A		66		75

DD&A and amortization of excess cost of equity investments for DCF	DD&A and amortization of excess cost of equity investments for DCF		$	638	$	691	DD&A and amortization of excess cost of equity investments for DCF		$	623	$	638

Income tax expense (GAAP)	Income tax expense (GAAP)		$	351	$	60	Income tax expense (GAAP)		$	194	$	351
Certain Items	Certain Items		40		96		Certain Items		20		40
Income tax expense(a)	Income tax expense(a)		391		156		Income tax expense(a)		214		391
Unconsolidated joint venture income tax expense(a)(b)	Unconsolidated joint venture income tax expense(a)(b)		28		25		Unconsolidated joint venture income tax expense(a)(b)		21		28

Income tax expense for DCF(a)	Income tax expense for DCF(a)		$	419	$	181	Income tax expense for DCF(a)		$	235	$	419

Additional joint venture information	Additional joint venture information						Additional joint venture information
Unconsolidated joint venture DD&A	Unconsolidated joint venture DD&A		$	86	$	103	Unconsolidated joint venture DD&A		$	77	$	86
Less: Consolidated joint venture partners’ DD&A	Less: Consolidated joint venture partners’ DD&A		11		9		Less: Consolidated joint venture partners’ DD&A		11		11
Joint venture DD&A	Joint venture DD&A		75		94		Joint venture DD&A		66		75
Unconsolidated joint venture income tax expense(a)(b)	Unconsolidated joint venture income tax expense(a)(b)		28		25		Unconsolidated joint venture income tax expense(a)(b)		21		28
Joint venture DD&A and income tax expense(a)	Joint venture DD&A and income tax expense(a)		$	103	$	119	Joint venture DD&A and income tax expense(a)		$	87	$	103

Unconsolidated joint venture cash taxes(b)	Unconsolidated joint venture cash taxes(b)		$	—	$	(4)	Unconsolidated joint venture cash taxes(b)		$	—	$	—

Unconsolidated joint venture sustaining capital expenditures	Unconsolidated joint venture sustaining capital expenditures		$	(20)	$	(26)	Unconsolidated joint venture sustaining capital expenditures		$	(12)	$	(20)
Less: Consolidated joint venture partners’ sustaining capital expenditures	Less: Consolidated joint venture partners’ sustaining capital expenditures		(1)		(1)		Less: Consolidated joint venture partners’ sustaining capital expenditures		(2)		(1)
Joint venture sustaining capital expenditures	Joint venture sustaining capital expenditures		$	(19)	$	(25)	Joint venture sustaining capital expenditures		$	(10)	$	(19)

(a)Amounts are adjusted for Certain Items.

(b)Amounts are associated with our Citrus, NGPL and Products (SE) Pipe Line equity investments.

3637

Segment Earnings Results

Natural Gas Pipelines


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions, except operating statistics)						(In millions, except operating statistics)
Revenues	Revenues		$	4,125	$	1,875	Revenues		$	2,813	$	4,125
Operating expenses	Operating expenses		(2,270)		(848)		Operating expenses		(1,784)		(2,270)

Other income	Other income		1		1		Other income		1		1
Earnings from equity investments	Earnings from equity investments		41		164		Earnings from equity investments		154		41

Other, net	Other, net		206		4		Other, net		—		206
Segment EBDA	Segment EBDA		2,103		1,196		Segment EBDA		1,184		2,103
Certain Items(a)	Certain Items(a)		(9)		(17)		Certain Items(a)		113		(9)
Adjusted Segment EBDA	Adjusted Segment EBDA		$	2,094	$	1,179	Adjusted Segment EBDA		$	1,297	$	2,094

Change from prior period	Change from prior period		Increase/(Decrease)				Change from prior period		Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA		$	915			Adjusted Segment EBDA		$	(797)

Volumetric data(b)	Volumetric data(b)						Volumetric data(b)
Transport volumes (BBtu/d)	Transport volumes (BBtu/d)		37,222		38,328		Transport volumes (BBtu/d)		39,731		38,850
Sales volumes (BBtu/d)	Sales volumes (BBtu/d)		2,260		2,495		Sales volumes (BBtu/d)		2,515		2,260
Gathering volumes (BBtu/d)	Gathering volumes (BBtu/d)		2,509		3,361		Gathering volumes (BBtu/d)		2,817		2,509
NGLs (MBbl/d)	NGLs (MBbl/d)		30		30		NGLs (MBbl/d)		32		30

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $113 million and $(9) million for 2022 and ~~$(17)~~2021, respectively. 2022 amount includes a decrease in revenues of $14 million ~~for 2021~~ and ~~2020, respectively.~~an increase in costs of sales of $87 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales and purchases. 2021 amount includes a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings partially offset by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, and an increase in expense of $69 million related to a ~~certain~~ litigation matter. 2020 amount includes an increase in revenues of $24 million related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales partially offset by an increase in expense associated with a certain EPNG litigation matter.reserve.

Other

(b)Joint venture throughput is reported at our ownership share. Volumes for acquired pipelines are included and volumes for assets sold are excluded for all periods presented.

Below are the changes in Adjusted Segment EBDA in the comparable three-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended March 31, ~~2021~~2022 versus Three Months Ended March 31, ~~2020~~2021

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Midstream $ 901 284%
East Region 19 3%
West Region (5) (2)%
Total Natural Gas Pipelines $ 915 78 %


	Adjusted Segment EBDA
	2022		2021		increase/(decrease)
Midstream	$	384	$	1,218	$	(834)
West	261		286		(25)
East	652		590		62



Total Natural Gas Pipelines	$	1,297	$	2,094	$	(797)

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-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

•$~~901~~834 million ~~(284%~~(68%) ~~increase~~decrease in Midstream was primarily due to ~~(i) higher~~ ~~sales margins driven by higher~~lower commodity prices, primarily as a result of the February 2021 winter storm, driving lower sales margins resulting in decreases of $869 million on our Texas intrastate natural gas pipeline operations~~; (ii) higher commodity prices as a result of~~ ~~the February 2021 winter storm~~ and $88 million on our South Texas ~~assets; and (iii)~~ ~~higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021.~~assets. These ~~increases~~decreases were partially offset by ~~lower~~higher earnings on ~~(i)~~ our Oklahoma assets ~~due to higher~~from lower commodity prices on certain purchase contracts as a result of the February 2021 winter ~~storm;~~storm and ~~(ii)~~ ~~KinderHawk~~higher volumes on Kinderhawk Field Services LLC. Overall Midstream’s revenues decreased primarily due to lower ~~volumes. Overall Midstream’s revenues increase~~dcommodity prices, primarily ~~due to higher commodity prices~~as a result of the February 2021 winter storm, which was partially offset by corresponding ~~increases~~decrease in costs of sales; and

•$1925 million ~~(3%~~(9%) decrease in the West Region was primarily due to lower earnings from EPNG driven by lower fee and park and loan revenues; and lower earnings from Colorado Interstate Gas Company, L.L.C. driven by lower revenues due to contract expirations; partially offset by,

•$62 million (11%) increase in the East Region was primarily due to ~~an increase in~~(i) our July 2021 acquisition of the Stagecoach assets; and (ii) higher earnings from ~~(i)~~ TGP primarily due to increases in transportation revenues as a result of ~~increased revenues primarily driven by the February 2021 winter storm; and (ii) ELC resulting from the liquefaction units of the Elba Liquefaction project being fully operational as of August 2020,~~new customer contracts partially offset by ~~reduced equity earnings from Fayetteville Express Pipeline LLC primarily due to~~ lower revenues as a result of ~~contract expirations.~~the February 2021 winter storm.

Products Pipelines


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions, except operating statistics)						(In millions, except operating statistics)
Revenues	Revenues		$	453	$	495	Revenues		$	766	$	453
Operating expenses	Operating expenses		(219)		(221)		Operating expenses		(497)		(219)
Loss on divestitures and impairments, net			—		(21)
Gain on divestitures and impairments, net							Gain on divestitures and impairments, net		12		—

Earnings from equity investments	Earnings from equity investments		14		15		Earnings from equity investments		18		14

Other, net			—		1

Segment EBDA	Segment EBDA		248		269		Segment EBDA		299		248
Certain Items(a)	Certain Items(a)		15		4		Certain Items(a)		—		15
Adjusted Segment EBDA	Adjusted Segment EBDA		$	263	$	273	Adjusted Segment EBDA		$	299	$	263

Change from prior period	Change from prior period		Increase/(Decrease)				Change from prior period		Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA		$	(10)			Adjusted Segment EBDA		$	36

Volumetric data(b)	Volumetric data(b)						Volumetric data(b)
Gasoline(c)	Gasoline(c)		892		961		Gasoline(c)		940		892
Diesel fuel	Diesel fuel		379		358		Diesel fuel		369		379
Jet fuel	Jet fuel		175		293		Jet fuel		242		175
Total refined product volumes	Total refined product volumes		1,446		1,612		Total refined product volumes		1,551		1,446
Crude and condensate	Crude and condensate		507		702		Crude and condensate		486		507
Total delivery volumes (MBbl/d)	Total delivery volumes (MBbl/d)		1,953		2,314		Total delivery volumes (MBbl/d)		2,037		1,953

Certain Items affecting Segment EBDA

(a)Includes Certain Item ~~amounts~~amount of $15 million ~~and $4 million for~~in 2021 ~~and 2020, respectively. 2021 amount includes~~as an increase in expense ~~of $15 million~~ related to an environmental reserve adjustment. ~~2020 amount includes a non-cash loss on impairment of our Belton Terminal of $21 million and a $17 million favorable adjustment for tax reserves, other than income taxes.~~

Other

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

(c)Volumes include ethanol pipeline volumes.

Below are the changes in Adjusted Segment EBDA in the comparable three-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended March 31, ~~2021~~2022 versus Three Months Ended March 31, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/(decrease)
West Coast Refined Products	West Coast Refined Products	$	(13)	(11)	%	West Coast Refined Products	$	137	$	110	$	27
Southeast Refined Products						Southeast Refined Products	73		65		8
Crude and Condensate	Crude and Condensate	(10)		(10)	%	Crude and Condensate	89		88		1
Southeast Refined Products		13		25	%

Total Products Pipelines	Total Products Pipelines	$	(10)	(4)	%	Total Products Pipelines	$	299	$	263	$	36

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-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

•$1327 million ~~(11%~~(25%) ~~decrease~~increase in West Coast Refined Products was primarily due to ~~decreased~~(i) increased earnings on Calnev Pipe Line LLC (Calnev), Pacific operations (SFPP) ~~operations~~and West Coast terminals driven by ~~lower services~~higher revenues asresulting from higher volumes; and (ii) a ~~result~~gain on sale of ~~lower volumes and higher operating expense as a result of higher integrity management spending;~~land at Calnev;

•$108 million (10%) decrease in Crude and Condensate was primarily due to decreased earnings from Kinder Morgan Crude & Condensate Pipeline (KMCC) and the Bakken Crude assets. KMCC’s decreased earnings was primarily due to expiration of contracts in 2020 and lower volumes which were exacerbated by temporary supply and demand interruptions from the February 2021 winter storm partially offset by lower operating expense attributable to first quarter 2020 unfavorable inventory valuation adjustments. The Bakken Crude assets decreased earnings were primarily driven by lower volumes partially offset by lower operating expense attributable to first quarter 2020 unfavorable inventory valuation adjustments and lower field operating expenses; and

•~~$13 million (25%~~(12%) increase in Southeast Refined Products was primarily due to ~~lower operating expenses~~higher earnings at our Transmix processing operations ~~driven by first quarter 2020 unfavorable inventory adjustments.~~primarily due to higher prices and volumes; and

•Crude and Condensate had higher revenues of $223 million, with corresponding increases in cost of sales, resulting from increased marketing activities.

Terminals

Three Months Ended March 31,
2021 2020
(In millions, except operating statistics)
Revenues $ 420 $ 442
Operating expenses (197) (192)
Gain on divestitures and impairments, net 1 —
Earnings from equity investments 3 5
Other, net — 2
Segment EBDA 227 257
Certain Items — —
Adjusted Segment EBDA $ 227 $ 257
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (30)
Volumetric data(a)
Liquids leasable capacity (MMBbl) 79.9 79.7
Liquids utilization %(b) 94.6 % 93.6 %
Bulk transload tonnage (MMtons) 11.0 13.0


	Three Months Ended March 31,
		2022			2021
		(In millions, except operating statistics)
Revenues		$	430		$	420
Operating expenses		(199)			(197)
(Loss) gain on divestitures and impairments, net		(3)			1
Other income		4			—
Earnings from equity investments		4			3
Other, net		2			—
Segment EBDA		238			227
Certain Items		—			—
Adjusted Segment EBDA		$	238		$	227

Change from prior period		Increase/(Decrease)
Adjusted Segment EBDA		$	11

Volumetric data(a)
Liquids leasable capacity (MMBbl)		78.9			79.0
Liquids utilization %(b)		92.3		%	95.1		%
Bulk transload tonnage (MMtons)		13.0			10.9

Other

(a)Volumes for ~~assets sold~~acquired pipelines are included for all periods. Volumes for facilities divested, idled and/or held for sale 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 Adjusted Segment EBDA in the comparable three-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended March 31, ~~2021~~2022 versus Three Months Ended March 31 ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/(decrease)
Gulf Central	Gulf Central	$	(15)	(44)	%	Gulf Central	$	32	$	19	$	13
Mid Atlantic						Mid Atlantic	21		16		$	5
Marine operations	Marine operations	(10)		(19)	%	Marine operations	38		42		$	(4)
Gulf Liquids		(5)		(6)	%
Northeast						Northeast	22		26		$	(4)
All others (including intrasegment eliminations)	All others (including intrasegment eliminations)	—		—	%	All others (including intrasegment eliminations)	125		124		$	1
Total Terminals	Total Terminals	$	(30)	(12)	%	Total Terminals	$	238	$	227	$	11

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-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

•$1513 million ~~(44%~~(68%) ~~decrease~~increase in the Gulf Central terminals was primarily ~~driven by unfavorable~~due to higher revenues resulting from contractual rate escalations and higher volumes for petroleum coke ~~volumes due~~handling activities, owing largely to refinery outages in the 2021 period associated with the February 2021 winter storm, ~~as well as an increase in~~higher revenues due to increased coal volumes and lower property tax expense at Battleground Oil Specialty Terminal Company ~~LLC;~~LLC in 2021; and

•$105 million ~~(19%~~(31%) increase in the Mid Atlantic terminals was primarily due to higher handling rates and coal volumes at our Pier IX facility; partially offset by,

•$4 million (10%) decrease in Marine operations was primarily due to lower average charter rates partially offset by higher fleet ~~utilization due to market weakness associated with demand reduction attributable to COVID-19;~~utilization; and

•$54 million ~~(6%~~(15%) decrease in the ~~Gulf Liquids~~Northeast terminals was primarily driven by decreased revenues associated with lower ~~volumes~~utilization and ~~associated ancillary fees related to both continued demand reduction attributable to COVID-19~~rates on re-contracted tank positions at our Carteret and ~~the February 2021 winter storm, which also resulted in higher utility costs. These items were partially offset by additional contributions from growth projects placed in service.~~Perth Amboy facilities.

4042

CO2


		Three Months Ended March 31,						Three Months Ended March 31,
			2021		2020				2022		2021
			(In millions, except operating statistics)						(In millions, except operating statistics)
Revenues	Revenues		$	229	$	309	Revenues		$	305	$	229
Operating benefit (expenses)			49		(122)
Loss on divestitures and impairments, net			—		(950)
Operating expenses							Operating expenses		(125)		49

Earnings from equity investments	Earnings from equity investments		8		8		Earnings from equity investments		11		8

Segment EBDA	Segment EBDA		286		(755)		Segment EBDA		192		286
Certain Items(a)	Certain Items(a)		5		930		Certain Items(a)		16		5
Adjusted Segment EBDA	Adjusted Segment EBDA		$	291	$	175	Adjusted Segment EBDA		$	208	$	291

Change from prior period	Change from prior period		Increase/(Decrease)				Change from prior period		Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA		$	116			Adjusted Segment EBDA		$	(83)

Volumetric data	Volumetric data						Volumetric data
SACROC oil production	SACROC oil production		19.4		23.2		SACROC oil production		19.3		19.4
Yates oil production	Yates oil production		6.1		7.0		Yates oil production		6.8		6.1
Katz and Goldsmith oil production	Katz and Goldsmith oil production		2.6		3.4		Katz and Goldsmith oil production		1.9		2.6
Tall Cotton oil production	Tall Cotton oil production		0.9		2.4		Tall Cotton oil production		1.0		0.9
Total oil production, net (MBbl/d)(b)	Total oil production, net (MBbl/d)(b)		29.0		36.0		Total oil production, net (MBbl/d)(b)		29.0		29.0
NGL sales volumes, net (MBbl/d)(b)	NGL sales volumes, net (MBbl/d)(b)		8.8		9.8		NGL sales volumes, net (MBbl/d)(b)		9.4		8.8

CO2 sales volumes, net (Bcf/d)	CO2 sales volumes, net (Bcf/d)		0.4		0.5		CO2 sales volumes, net (Bcf/d)		0.4		0.4
Realized weighted average oil price ($ per Bbl)	Realized weighted average oil price ($ per Bbl)		$	51.05	$	54.61	Realized weighted average oil price ($ per Bbl)		$	66.90	$	51.05
Realized weighted average NGL price ($ per Bbl)	Realized weighted average NGL price ($ per Bbl)		$	20.14	$	19.74	Realized weighted average NGL price ($ per Bbl)		$	43.68	$	20.14

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of $16 million and $5 million decreasing revenue in 2022 and ~~$930 million for~~ 2021, ~~and 2020, respectively. 2020 amount includes (i) a $600 million goodwill impairment on our CO~~2 ~~reporting unit; (ii) non-cash impairments of $350 million on our oil and gas producing assets; and (iii) an increase in revenues of $20 million~~respectively, related to non-cash mark-to-market ~~gains associated with~~ derivative contracts used to hedge forecasted commodity sales.

Other

(b)Net of royalties and outside working interests.

Below are the changes in Adjusted Segment EBDA in the comparable three-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended March 31, ~~2021~~2022 versus Three Months Ended March 31, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/(decrease)
Oil and Gas Producing activities	Oil and Gas Producing activities	$	123	110	%	Oil and Gas Producing activities	$	142	$	235	(93)
Source and Transportation activities	Source and Transportation activities	(7)		(10)	%	Source and Transportation activities	62		56		6

Subtotal						Subtotal	204		291		(87)
Energy Transition Ventures						Energy Transition Ventures	4		—		4
Total CO2	Total CO2	$	116	67	%	Total CO2	$	208	$	291	$	(83)

4143

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-month periods ended March 31, ~~2021~~2022 and ~~2020:~~2021:

•$~~123~~93 million ~~(110%~~(40%) ~~increase~~decrease in Oil and Gas Producing activities was primarily due to ~~lower~~higher operating expenses of ~~$163~~$153 million driven by athe benefit ~~for~~realized in the ~~current~~2021 period ~~realized~~ from returning power to the grid by curtailing oil production during the February 2021 winter storm partially offset by ~~lower volumes driven in part by the curtailed oil production, which decreased revenues by $24 million and lower~~higher realized crude oil and NGL prices which ~~decreased~~increased revenues by ~~$14~~$60 million; and

•$76 million ~~(10%~~(11%) ~~decrease~~increase in Source and Transportation activities primarily due to ~~a decrease of $12 million~~increase in revenues related to ~~lower~~higher CO2 sales ~~volumes partially offset by lower operating expenses of $7 million.~~prices.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2business segment hedges outstanding as of March 31, ~~2021.~~2022.


		Remaining 2021		2022		2023		2024		2025			Remaining 2022		2023		2024		2025		2026
Crude Oil(a)	Crude Oil(a)											Crude Oil(a)
Price ($ per Bbl)	Price ($ per Bbl)	$	50.38	$	51.03	$	49.30	$	45.11	$	46.89	Price ($ per Bbl)	$	61.32	$	58.92	$	58.07	$	58.84	$	64.98
Volume (MBbl/d)	Volume (MBbl/d)	25.70		13.80		8.65		2.85		0.80		Volume (MBbl/d)	25.13		17.80		11.20		6.65		1.60
NGLs	NGLs											NGLs
Price ($ per Bbl)	Price ($ per Bbl)	$	31.75	$	44.57							Price ($ per Bbl)	$	54.07	$	75.61
Volume (MBbl/d)	Volume (MBbl/d)	5.36		0.16								Volume (MBbl/d)	4.56		0.45
Midland-to-Cushing Basis Spread	Midland-to-Cushing Basis Spread											Midland-to-Cushing Basis Spread
Price ($ per Bbl)	Price ($ per Bbl)	$	0.26	$	0.73							Price ($ per Bbl)	$	0.53
Volume (MBbl/d)	Volume (MBbl/d)	24.55		10.25								Volume (MBbl/d)	23.65

(a)Includes West Texas Intermediate hedges.

DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests

Three Months Ended March 31, Earnings
increase/(decrease)
2021 2020
(In millions, except percentages)
DD&A (GAAP) $ (541) $ (565) $ 24 4 %
General and administrative (GAAP) $ (156) $ (153) $ (3) (2) %
Corporate benefit (charges) 8 (12) 20 167 %
Certain Items(a) — 25 (25) (100) %
General and administrative and corporate charges(b) $ (148) $ (140) $ (8) (6) %
Interest, net (GAAP) $ (377) $ (436) $ 59 14 %
Certain Items(c) (6) 1 (7) (700) %
Interest, net(b) $ (383) $ (435) $ 52 12 %
Net income attributable to noncontrolling interests (GAAP) $ (16) $ (15) $ (1) (7) %
Certain Items(d) — — — — %
Net income attributable to noncontrolling interests(b) $ (16) $ (15) $ (1) (7) %


	Three Months Ended March 31,				Earnings increase/(decrease)
	2022		2021
	(In millions, except percentages)
DD&A (GAAP)	$	(538)	$	(541)	$	3	1	%

General and administrative (GAAP)	$	(156)	$	(156)	$	—	—	%
Corporate benefit	11		8		3		38	%
Certain Items	—		—		—		—	%
General and administrative and corporate charges(a)	$	(145)	$	(148)	$	3	2	%

Interest, net (GAAP)	$	(333)	$	(377)	$	44	12	%
Certain Items(b)	(44)		(6)		(38)		(633)	%
Interest, net(a)	$	(377)	$	(383)	$	6	2	%






Net income attributable to noncontrolling interests (GAAP)	$	(17)	$	(16)	$	(1)	(6)	%
Certain Items(c)	—		—		—		—	%
Net income attributable to noncontrolling interests(b)	$	(17)	$	(16)	$	(1)	(6)	%

Certain items

(a)~~2020 amount includes an increase in expense of $23 million associated with the non-cash fair value adjustment and the dividend accrual prior to the sale of our investment in Pembina common stock.~~

~~(b)~~Amounts are adjusted for Certain Items.

~~(c)~~(b)~~2021~~2022 and ~~2020~~2021 amounts include ~~(i)~~ decreases in interest expense of $4$40 million and ~~$8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease and an increase in expense of~~ $2 ~~million and $11~~ 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.~~debt, primarily related to our floating-to-fixed

~~(d)~~

LIBOR interest rate swaps which are not designated as accounting hedges, and decreases of $4 million in each period related to non-cash debt fair value adjustments associated with acquisitions.

~~DD&A expense decreased $24 million in 2021 when compared to 2020 primarily due to non-cash impairments taken in the first quarter 2020 on our oil and gas producing assets.~~

General and administrative expenses and corporate charges adjusted for Certain Items ~~increased $8~~decreased $3 million in ~~2021~~2022 when compared to ~~2020~~2021 primarily due to ~~lower~~higher capitalized costs of ~~$16~~$9 million reflecting ~~reduced~~higher capital spending ~~primarily by our Natural Gas Pipelines business segment~~and $5 million of lower environmental expenses partially offset by ~~$10~~$5 million of ~~cost savings associated with organizational efficiency efforts.~~higher employee labor and travel costs.

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. Our consolidated interest expense, net adjusted for Certain Items decreased ~~$52~~$6 million in ~~2021~~2022 when compared to ~~2020~~2021 primarily due to lower ~~LIBOR~~long-term average interest rates and long-term ~~interest~~debt balances, partially offset by higher LIBOR rates.

We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed rate debt securities (senior notes) into variable rate debt in order to achieve our desired mix of fixed and variable rate debt. As of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, approximately ~~14%~~8% and ~~16%~~21%, respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. For more information on our interest rate swaps, see Note 5 ~~“Risk~~“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.

Income Taxes

Our tax expense for the three months ended March 31, ~~2021~~2022 was approximately ~~$351~~$194 million as compared with ~~$60~~tax expense of $351 million for the same period of ~~2020.~~2021. The ~~$291~~$157 million ~~increase~~decrease in tax expense ~~was~~is due primarily to higher pre-tax book income in the 2021 period, ~~and the refund of alternative minimum tax sequestration credits in the 2020 period,~~partially offset by the ~~prior year disallowance~~release of a ~~tax benefit for the non-tax deductible goodwill impairment and the current year release of the~~ valuation allowance onrelated to our investment in NGPL ~~Holdings.~~Holdings in 2021.

Liquidity and Capital Resources

General

As of March 31, ~~2021,~~2022, we had ~~$1,377~~$84 million of “Cash and cash equivalents,” ~~an increase~~a decrease of ~~$193~~$1,056 million from December 31, ~~2020.~~2021. Additionally, as of March 31, ~~2021,~~2022, we had borrowing capacity of approximately ~~$3.9~~$3.6 billion under our ~~$4 billion revolving~~ credit ~~facility~~facilities (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 ~~facility~~facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flows from operations, providing a source of funds of ~~$1,873~~$1,084 million and ~~$893~~$1,873 million in the first three months of ~~2021~~2022 and ~~2020,~~2021, respectively. The period-to-period ~~increase~~decrease is discussed below in “—Cash Flows—Operating Activities.” 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 believe our current cash on hand, our cash flows from operations, and our borrowing capacity under our revolving credit facility are more than adequate to allow us to manage our cash requirements, including maturing debt, through 2021;expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt.

Our board of directors declared a quarterly dividend of ~~$0.27~~$0.2775 per share for the first quarter of ~~2021,~~2022, a 3% increase over the dividend declared for the previous quarter. We expect to fully fund our dividend payments as well as our discretionary spending for ~~2021~~2022 without funding from the capital ~~markets and still have additional flexibility to engage in share repurchases on an opportunistic basis.~~markets.

On February ~~11, 2021, we~~23, 2022, EPNG issued in a ~~registered~~private offering ~~$750~~$300 million aggregate principal amount of ~~3.60%~~3.50% senior notes due ~~2051~~2032 and received net proceeds of ~~$741~~$298 million ~~which were used to repay maturing senior notes.~~after discount and issuance costs.

During the first quarter, upon maturity, we repaid EPNG’s 8.625% senior notes, our 4.15% corporate senior notes, and the 1.50% series of our Euro denominated debt.

Short-term Liquidity

As of March 31, ~~2021,~~2022, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion ~~revolving~~of credit ~~facility~~facilities and associated commercial paper ~~program; and (iii) cash and cash equivalents.~~program. The loan commitments under our ~~revolving~~ credit ~~facility~~facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. ~~Letters of credit and commercial~~Commercial paper borrowings reduce borrowings allowed under our credit facilities and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit ~~facility~~facilities 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 March 31, ~~2021,~~2022, our ~~$2,173~~$3,324 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through ~~cash on hand,~~ 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, ~~2020~~2021 was ~~$2,558~~$2,646 million.

We had working capital (defined as current assets less current liabilities) deficits of ~~$884~~$3,417 million and ~~$1,871~~$1,992 million as of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall ~~$987~~$1,425 million ~~favorable~~unfavorable change from year-end ~~2020~~2021 was primarily due to (i) a $1,056 million decrease in cash and cash equivalents which includes $1,190 million related to repayments of ~~approximately $385~~senior notes that matured in the first quarter of 2022 using cash on hand; (ii) net unfavorable short-term fair value adjustments on derivative contracts of $430 million; (iii) a $387 million increase in senior notes that mature in the next twelve months; and (iv) a $290 million increase in commercial paper borrowings; partially offset by (i) a $257 million increase in restricted deposits related to our derivative activity; (ii) a ~~$221~~$202 million decrease in accrued interest; (iii) a ~~$193~~combined $105 million ~~increase~~favorable change in ~~cash~~our accounts receivables and ~~cash equivalents;~~payables; and (iv) a ~~$150~~$68 million decrease in accrued ~~contingencies; and (v) an increase in accounts receivable, net of change in accounts payable, of $85 million, partially offset by a $186 million increase in current regulatory liabilities.~~contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

~~Counterparty Creditworthiness~~

Some of 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 regulations, prepayments and other security requirements, such as letters of 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 or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations, or future cash flows. The balance of our allowance for credit losses as of March 31, 2021 and December 31, 2020, was $29 million and $26 million, respectively, reflected in “Other current assets” on our consolidated balance sheets.

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~~which increase throughput or capacity from that which existed immediately prior to the addition or improvement, and are not deducted in calculating DCF (see “—Results of Operations—Overview—Non-GAAP Financial Measures—DCF”). With respect to our oil and gas producing activities, we classify a capital expenditure as an expansion capital expenditure if it is expected to increase capacity or throughput (i.e., production capacity) from the capacity or throughput immediately prior to the making or acquisition of such additions or improvements. Maintenance capital expenditures are those ~~that~~which maintain throughput or capacity. The distinction

between maintenance and expansion capital expenditures is a physical determination rather than an economic one, irrespective of the amount by which the throughput or capacity is increased.

Budgeting of maintenance capital expenditures is done annually on a bottom-up basis. For each of our assets, we budget for and make those maintenance capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional maintenance capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures are generally made periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Generally, the determination of whether a capital expenditure is classified as a maintenance/sustaining or as an expansion capital ~~expenditure~~expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as maintenance capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted from DCF, while those classified as maintenance capital expenditures are.

Our capital expenditures for the three months ended March 31, ~~2021,~~2022, and the amount we expect to spend for the remainder of ~~2021~~2022 to sustain our assets and grow our ~~businesses~~business are as follows:


		Three Months Ended March 31, 2021		2021 Remaining		Total 2021			Three Months Ended March 31, 2022		2022 Remaining		Total 2022
		(In millions)							(In millions)
Sustaining capital expenditures(a)(b)	Sustaining capital expenditures(a)(b)	$	107	$	757	$	864	Sustaining capital expenditures(a)(b)	$	125	$	784	$	909
Discretionary capital investments(b)(c)(d)	Discretionary capital investments(b)(c)(d)	132		703		835		Discretionary capital investments(b)(c)(d)	206		1,257		1,463

(a)Three months ended March 31, ~~2021, 2021~~2022, 2022 Remaining, and Total ~~2021~~2022 amounts include ~~$18~~$10 million, ~~$86~~$112 million, and ~~$104~~$122 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “Non-GAAP Financial Measures—Supplemental Information.”

(b)Three months ended March 31, ~~2021~~2022 amount excludes ~~$67~~$101 million due to decreases in accrued capital expenditures and contractor retainage and net changes in other.

(c)Three months ended March 31, ~~2021~~2022 amount includes ~~$21~~$15 million of our contributions to certain unconsolidated joint ventures for capital investments.

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

Off Balance Sheet Arrangements

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, ~~2020~~2021 in our ~~2020~~2021 Form 10-K.

Commitments for the purchase of property, plant and equipment as of March 31, ~~2021~~2022 and December 31, ~~2020~~2021 were ~~$182~~$283 million and ~~$141~~$209 million, respectively. The increase of ~~$41~~$74 million was primarily driven by capital commitments related to our Natural Gas Pipelines and Products Pipelines business ~~segment.~~segments.

Cash Flows

Operating Activities

Cash provided by operating activities ~~increased $980~~decreased $789 million in the three months ended March 31, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily due to:

•~~a $1,043~~an $840 million ~~increase in cash after adjusting the $1,716 million increase~~decrease in net income resulting from the benefit recognized in the 2021 period for largely nonrecurring earnings related to the February 2021 winter storm (see discussion above in “—Results of Operations”); partially offset by, ~~$673~~

•a combined $83 million ~~for the combined effects~~net impact of the ~~period-to-period net changes in~~certain non-cash items ~~including the following: (i)~~consisting of a $206 million gain from the sale of a partial interest in our equity investment in NGPL Holdings ~~(see discussion above in “—Results of Operations”); (ii) (gain) loss on divestitures and impairments, net (see discussion above in “—Results of Operations”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred income taxes; and (v) earnings from equity investments (including~~LLC, partially offset by a ~~non-cash~~$117 million write-down of a related party note receivable from ~~Ruby); partially offset by,~~

•a $63 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities. The decrease was driven, among other things, primarily by an unfavorable change in accounts

~~receivables due to the timing of collections from customers, offset by a favorable change due to the timing of trade payables payments~~Ruby, both in the 2021 period, ~~compared to the 2020 period. The decrease was also driven by payments for litigation matters~~and a $6 million increase in gains on divestitures and impairments, net in the 2022 period over the 2021 period. See Note 2 “Investments” to our consolidated financial statements for further information regarding the sale of an interest in NGPL Holdings LLC and write-down of note receivable from Ruby.

Investing Activities

Cash ~~provided by~~used in investing activities ~~decreased $205~~increased $501 million for the three months ended March 31, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily attributable to:

•a ~~$494~~$413 million decrease in cash ~~primarily~~ due to $413 million of net proceeds received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 ~~period, versus the $907~~period; and

•a $140 million increase in capital expenditures reflecting an overall increase of ~~proceeds received from the sale of Pembina shares~~expansion capital projects in the ~~2020 period. See Note 2 “Gains and Losses from Divestitures, Impairments and Other Write-downs” to our consolidated financial statements for further information regarding~~2022 period over the ~~transaction of the sale of an interest in NGPL Holdings;~~comparative 2021 period; partially offset by,

•a ~~$173~~combined $43 million ~~decrease in capital expenditures reflecting our overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and~~

•~~a $129 million decrease~~increase in cash ~~used for~~in distributions received from equity investments in excess of cumulative earnings and lower contributions to equity investees ~~driven by lower contributions to SNG and Permian Highway Pipeline~~ in the ~~2021~~2022 period compared with the ~~2020~~2021 period.

Financing Activities

Cash used in financing activities ~~increased $1,302~~decreased $277 million for the three months ended March 31, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily attributable to:

•a ~~$1,317~~$299 million net ~~increase~~decrease in cash used related to debt activity as a result of ~~$1,168 million of~~lower net debt payments in the ~~2021~~2022 period compared to ~~$149 million of net debt issuances in~~ the ~~2020~~2021 period.

Dividends

We expect to declare dividends of ~~$1.08~~$1.11 per share on our stock for ~~2021.~~2022. The table below reflects our ~~2021~~2022 dividends declared:

Three months ended

Total quarterly dividend per share for the period

Date of declaration

Date of record

Date of dividend

March 31, ~~2021~~2022

~~0.27~~0.2775

April ~~21, 2021~~

~~April 30, 2021~~20, 2022

May ~~17, 2021~~2, 2022

May 16, 2022

The actual amount of 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 ~~2020~~2021 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally ~~are expected to~~will be paid on or about the 15th day of each February, May, August and November.

4648

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

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,~~subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, ~~subsidiary issuers~~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~~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.

In lieu of providing separate financial statements for ~~subsidiary issuers and guarantors,~~the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.1 to this ~~report~~Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of March 31, ~~2021.~~2022.”

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~~Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors, (referred to as “affiliates”) are presented separately in the accompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of March 31, ~~2021~~2022 and December 31, ~~2020,~~2021, the Obligated Group had ~~$31,353~~$30,695 million and ~~$32,563~~$31,608 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:


Summarized Combined Balance Sheet Information	Summarized Combined Balance Sheet Information	March 31, 2021		December 31, 2020		Summarized Combined Balance Sheet Information	March 31, 2022		December 31, 2021
		(In millions)					(In millions)

Current assets	Current assets	$	3,465	$	2,957	Current assets	$	2,752	$	3,556
Current assets - affiliates	Current assets - affiliates	1,197		1,151		Current assets - affiliates	1,266		1,233
Noncurrent assets	Noncurrent assets	60,648		61,783		Noncurrent assets	61,294		61,754
Noncurrent assets - affiliates	Noncurrent assets - affiliates	506		616		Noncurrent assets - affiliates	508		508
Total Assets	Total Assets	$	65,816	$	66,507	Total Assets	$	65,820	$	67,051

Current liabilities	Current liabilities	$	4,295	$	4,528	Current liabilities	$	6,111	$	5,413
Current liabilities - affiliates	Current liabilities - affiliates	1,223		1,209		Current liabilities - affiliates	1,399		1,332
Noncurrent liabilities	Noncurrent liabilities	32,847		33,907		Noncurrent liabilities	30,595		32,310
Noncurrent liabilities - affiliates	Noncurrent liabilities - affiliates	893		1,078		Noncurrent liabilities - affiliates	1,012		1,047
Total Liabilities	Total Liabilities	39,258		40,722		Total Liabilities	39,117		40,102
Redeemable noncontrolling interest		705		728

Kinder Morgan, Inc.’s stockholders’ equity	Kinder Morgan, Inc.’s stockholders’ equity	25,853		25,057		Kinder Morgan, Inc.’s stockholders’ equity	26,703		26,949
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity		$	65,816	$	66,507
Total Liabilities and Stockholders’ Equity						Total Liabilities and Stockholders’ Equity	$	65,820	$	67,051

Summarized Combined Income Statement Information

Three Months Ended March 31, ~~2021~~2022

(In millions)

Revenues

~~4,902~~3,977

Operating income

~~1,829~~906

Net income

~~1,377~~568

4749

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, ~~2020,~~2021, in Item 7A in our ~~2020~~2021 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of March 31, ~~2021,~~2022, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended March 31, ~~2021~~2022 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 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our ~~2020~~2021 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

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, 2022	—	$	—	—	$	1,424,909,386
February 1 to February 28, 2022	—	—		—	1,424,909,386
March 1 to March 31, 2022	31,283	16.96		31,283	1,424,378,799

Total	31,283	$	16.96	31,283	$	1,424,378,799

(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~~Except for at one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do 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~~. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended March 31, ~~2021.~~2022.

Item 5. Other Information.

None.

4851

Item 6. Exhibits.

~~Exhibit~~

~~NumberDescription~~


~~4.1~~ Exhibit Number		~~Certificate of the Vice President and Chief Financial Officer, and Vice President, Investor Relations and Treasurer of Kinder Morgan~~, ~~Inc. establishing the terms of the~~ 3 .6 ~~0% Notes due February 15, 20~~5 1 .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 March 31, ~~2021.~~2022.

22.1	Subsidiary guarantors and issuers of guaranteed securities.

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 ~~Operations~~Income for the three months ended March 31, ~~2021~~2022 and ~~2020;~~2021; (ii) our Consolidated Statements of Comprehensive Income ~~(Loss)~~ for the three months ended March 31, ~~2021~~2022 and ~~2020;~~2021; (iii) our Consolidated Balance Sheets as of March 31, ~~2021~~2022 and December 31, ~~2020;~~2021; (iv) our Consolidated Statements of Cash Flows for the three months ended March 31, ~~2021~~2022 and ~~2020;~~2021; (v) our Consolidated Statements of Stockholders’ Equity for the three months ended March 31, ~~2021~~2022 and ~~2020;~~2021; 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.

4952

SIGNATURE

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


			KINDER MORGAN, INC.
						Registrant

Date:

April ~~23, 2021~~22, 2022

By:

/s/ David P. Michels

David P. Michels
Vice President and Chief Financial Officer
(principal financial and accounting officer)

5053


	Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2020	$	(13)	$	0	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(156)		0		17		(139)
Loss reclassified from accumulated other comprehensive loss	59		0		0		59
Net current-period change in accumulated other comprehensive loss	(97)		0		17		(80)
Balance as of March 31, 2021	$	(110)	$	0	$	(377)	$	(487)