UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September~~June 30, ~~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 ~~October~~July 21, ~~2021,~~2022, the registrant had ~~2,267,425,507~~2,253,000,833 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 - Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~2021		4
	Consolidated Statements of Comprehensive Income (Loss) - Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~2021		5
	Consolidated Balance Sheets - as of ~~September~~June ~~30, 2021~~3 0 , 2022 and December 31, ~~2020~~2021		6
	Consolidated Statements of Cash Flows - ~~Nine~~Six Months Ended ~~September~~June ~~30, 2021~~3 0 , 2022 and ~~2020~~2021		7
	Consolidated Statements of Stockholders’ Equity - Three and ~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~ 2021		9
	Notes to Consolidated Financial Statements		1110
	Note 1 .	General	1110
	Note 2 .	~~Acquisitions~~	12
	~~Note~~ 3 .2.	Losses and Gains on Impairments, Divestitures and Other Write-downs	1411
	Note 4 .3.	Debt	1612
	Note 5 .4.	~~Stockholders’~~Stockholders’ Equity	1713
	Note 6 .5.	Risk Management	1815
	Note 7 .6.	Revenue Recognition	2321
	Note 8 .7.	Reportable Segments	24
	Note 8.	Income Taxes	25
	Note 9.	Litigation and Environmental	26
	Note 9 .	~~Income Taxes~~	27
	~~Note~~ 10 .	~~Litigation and Environmental~~	28
	~~Note 1~~1 .10.	Recent Accounting Pronouncements	3230
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		3432
	Results of Operations		3532
	Overview		3532
	Consolidated Earnings Results (GAAP)		3735
	Non-GAAP Financial Measures		4038
	Segment Earnings Results		4341
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		5149
	Income Taxes		5250
	Liquidity and Capital Resources		5251
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		5654
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		5755
Item 4.	Controls and Procedures		5755
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		5755
Item 1A.	Risk Factors		5755
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5755
Item 3.	Defaults Upon Senior Securities		5755
Item 4.	Mine Safety Disclosures		5756
Item 5.	Other Information		5756
Item 6.	Exhibits		5957
	Signature		6058

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

EPNG

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

Ruby

Ruby Pipeline Holding Company, L.L.C.

KMBT

Kinder Morgan Bulk Terminals, Inc.

SFPP

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~~FERC

~~U.S. Environmental Protection Agency~~Federal Energy Regulatory Commission

Bbl

~~barrel~~barrels

~~FASB~~GAAP

~~Financial~~U.S. Generally Accepted Accounting ~~Standards Board~~Principles

BBtu

billion British Thermal Units

~~FERC~~LLC

~~Federal Energy Regulatory Commission~~limited liability company

Bcf

billion cubic feet

~~GAAP~~LIBOR

~~U.S. Generally Accepted Accounting Principles~~London Interbank Offered Rate

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

~~LLC~~MBbl

~~limited liability company~~thousand barrels

~~LIBOR~~MMBbl

~~London Interbank Offered Rate~~million 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

natural gas liquids

DD&A

depreciation, depletion and amortization

NYMEX

New York Mercantile Exchange

EBDA

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

OTC

over-the-counter

~~ROU~~PHMSA

~~Right-of-Use~~Pipeline and Hazardous Materials Safety Administration

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

FASB

Financial Accounting Standards Board

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, our anticipated dividends ~~our proposed acquisition of Kinetrex Energy~~ and ~~our~~ capital projects, including expected completion timing and benefits of ~~the acquisition and~~ 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

(In millions, except per share amounts, unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Revenues	Revenues									Revenues
Services	Services	$	1,928	$	1,881	$	5,734	$	5,664	Services	$	2,011	$	1,889	$	4,061	$	3,806
Commodity sales	Commodity sales	1,868		982		6,343		2,772		Commodity sales	3,100		1,246		5,308		4,475
Other	Other	28		56		108		149		Other	40		15		75		80
Total Revenues	Total Revenues	3,824		2,919		12,185		8,585		Total Revenues	5,151		3,150		9,444		8,361

Operating Costs, Expenses and Other	Operating Costs, Expenses and Other									Operating Costs, Expenses and Other
Costs of sales	Costs of sales	1,559		655		4,504		1,759		Costs of sales	2,683		936		4,577		2,945
Operations and maintenance	Operations and maintenance	614		643		1,710		1,869		Operations and maintenance	663		582		1,248		1,096
Depreciation, depletion and amortization	Depreciation, depletion and amortization	526		539		1,595		1,636		Depreciation, depletion and amortization	543		528		1,081		1,069
General and administrative	General and administrative	174		153		490		461		General and administrative	152		160		308		316
Taxes, other than income taxes	Taxes, other than income taxes	106		100		324		295		Taxes, other than income taxes	116		108		227		218

Loss on impairments and divestitures, net (Note 3)		4		11		1,602		1,987
(Gain) loss on divestitures and impairments, net										(Gain) loss on divestitures and impairments, net	(11)		1,602		(21)		1,598
Other income, net	Other income, net	(3)		(1)		(6)		(2)		Other income, net	(1)		(2)		(6)		(3)
Total Operating Costs, Expenses and Other	Total Operating Costs, Expenses and Other	2,980		2,100		10,219		8,005		Total Operating Costs, Expenses and Other	4,145		3,914		7,414		7,239

Operating Income		844		819		1,966		580
Operating Income (Loss)										Operating Income (Loss)	1,006		(764)		2,030		1,122

Other Income (Expense)	Other Income (Expense)									Other Income (Expense)
Earnings from equity investments	Earnings from equity investments	169		194		392		562		Earnings from equity investments	182		157		369		223

Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)		Amortization of excess cost of equity investments	(19)		(13)		(38)		(35)
Interest, net	Interest, net	(368)		(383)		(1,122)		(1,214)		Interest, net	(355)		(377)		(688)		(754)
Other, net (Note 3)		21		14		264		32
Other, net (Note 2)										Other, net (Note 2)	23		20		42		243
Total Other Expense	Total Other Expense	(199)		(207)		(522)		(719)		Total Other Expense	(169)		(213)		(315)		(323)

Income (Loss) Before Income Taxes	Income (Loss) Before Income Taxes	645		612		1,444		(139)		Income (Loss) Before Income Taxes	837		(977)		1,715		799

Income Tax Expense		(134)		(140)		(248)		(304)
Income Tax (Expense) Benefit										Income Tax (Expense) Benefit	(184)		237		(378)		(114)

Net Income (Loss)	Net Income (Loss)	511		472		1,196		(443)		Net Income (Loss)	653		(740)		1,337		685

Net Income Attributable to Noncontrolling Interests	Net Income Attributable to Noncontrolling Interests	(16)		(17)		(49)		(45)		Net Income Attributable to Noncontrolling Interests	(18)		(17)		(35)		(33)

Net Income (Loss) Attributable to Kinder Morgan, Inc.	Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	495	$	455	$	1,147	$	(488)	Net Income (Loss) Attributable to Kinder Morgan, Inc.	$	635	$	(757)	$	1,302	$	652

Class P Shares
Class P Common Stock										Class P Common Stock
Basic and Diluted Earnings (Loss) Per Share	Basic and Diluted Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)	Basic and Diluted Earnings (Loss) Per Share	$	0.28	$	(0.34)	$	0.57	$	0.29

Basic and Diluted Weighted Average Shares Outstanding	Basic and Diluted Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263		Basic and Diluted Weighted Average Shares Outstanding	2,265		2,265		2,266		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
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
Net income (loss) $ 511 $ 472 $ 1,196 $ (443)
Other comprehensive (loss) income, net of tax
Change in fair value of hedge derivatives (net of tax benefit of $41, $17, $135 and $5, respectively) (131) (56) (444) (16)
Reclassification of change in fair value of derivatives to net income (loss) (net of tax (benefit) expense of $(28), $1, $(55) and $(22), respectively) 92 (5) 181 72
Foreign currency translation adjustments (net of tax expense of $—, $—, $— and $—, respectively) — — — 1
Benefit plan adjustments (net of tax expense of $2, $2, $7 and $7, respectively) 6 5 28 21
Total other comprehensive (loss) income (33) (56) (235) 78
Comprehensive income (loss) 478 416 961 (365)
Comprehensive income attributable to noncontrolling interests (16) (17) (49) (45)
Comprehensive income (loss) attributable to Kinder Morgan, Inc. $ 462 $ 399 $ 912 $ (410)


	Three Months Ended June 30,				Six Months Ended June 30,
	2022		2021		2022		2021
Net income (loss)	$	653	$	(740)	$	1,337	$	685
Other comprehensive income (loss), net of tax
Net unrealized loss from derivative instruments (net of taxes of $24, $47, $149 and $94, respectively)	(78)		(157)		(489)		(313)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(48), $(9), $(89), and $(27), respectively)	157		30		292		89

Benefit plan adjustments (net of taxes of $(1), $(1), $(5) and $(5), respectively)	3		5		16		22
Total other comprehensive income (loss)	82		(122)		(181)		(202)

Comprehensive income (loss)	735		(862)		1,156		483
Comprehensive income attributable to noncontrolling interests	(18)		(17)		(35)		(33)
Comprehensive income (loss) attributable to KMI	$	717	$	(879)	$	1,121	$	450

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share and per share amounts, unaudited)


		September 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	102	$	1,184	Cash and cash equivalents	$	100	$	1,140
Restricted deposits	Restricted deposits	177		25		Restricted deposits	317		7
Accounts receivable	Accounts receivable	1,433		1,293		Accounts receivable	2,063		1,611
Fair value of derivative contracts	Fair value of derivative contracts	199		185		Fair value of derivative contracts	141		220
Inventories	Inventories	457		348		Inventories	690		562

Other current assets	Other current assets	318		168		Other current assets	297		289
Total current assets	Total current assets	2,686		3,203		Total current assets	3,608		3,829

Property, plant and equipment, net	Property, plant and equipment, net	35,576		35,836		Property, plant and equipment, net	35,530		35,653
Investments	Investments	7,620		7,917		Investments	7,470		7,578
Goodwill	Goodwill	20,033		19,851		Goodwill	19,914		19,914
Other intangibles, net	Other intangibles, net	1,744		2,453		Other intangibles, net	1,557		1,678
Deferred income taxes	Deferred income taxes	303		536		Deferred income taxes	—		115

Deferred charges and other assets	Deferred charges and other assets	1,678		2,177		Deferred charges and other assets	1,311		1,649
Total Assets	Total Assets	$	69,640	$	71,973	Total Assets	$	69,390	$	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	$	2,822	$	2,558	Current portion of debt	$	2,970	$	2,646
Accounts payable	Accounts payable	1,189		837		Accounts payable	1,691		1,259

Accrued interest	Accrued interest	332		525		Accrued interest	442		504
Accrued taxes	Accrued taxes	284		267		Accrued taxes	217		270
Accrued contingencies		246		307
Fair value of derivative contracts						Fair value of derivative contracts	521		178

Other current liabilities	Other current liabilities	952		580		Other current liabilities	1,051		964
Total current liabilities	Total current liabilities	5,825		5,074		Total current liabilities	6,892		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	28,988		30,838		Outstanding	28,140		29,772

Debt fair value adjustments	Debt fair value adjustments	1,014		1,293		Debt fair value adjustments	412		902
Total long-term debt	Total long-term debt	30,002		32,131		Total long-term debt	28,552		30,674

Deferred income taxes						Deferred income taxes	196		—

Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits	2,160		2,202		Other long-term liabilities and deferred credits	2,125		2,000

Total long-term liabilities and deferred credits	Total long-term liabilities and deferred credits	32,162		34,333		Total long-term liabilities and deferred credits	30,873		32,674
Total Liabilities	Total Liabilities	37,987		39,407		Total Liabilities	37,765		38,495

Commitments and contingencies (Notes 4 and 10)		0		0
Redeemable Noncontrolling Interest		661		728
Commitments and contingencies (Notes 3 and 9)						Commitments and contingencies (Notes 3 and 9)	0		0
Stockholders’ Equity	Stockholders’ Equity					Stockholders’ Equity

Class P shares, $0.01 par value, 4,000,000,000 shares authorized, 2,267,381,482 and 2,264,257,336 shares, respectively, issued and outstanding		23		23
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,257,464,962 and 2,267,391,527 shares, respectively, issued and outstanding						Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,257,464,962 and 2,267,391,527 shares, respectively, issued and outstanding	23		23
Additional paid-in capital	Additional paid-in capital	41,788		41,756		Additional paid-in capital	41,654		41,806
Accumulated deficit	Accumulated deficit	(10,617)		(9,936)		Accumulated deficit	(10,540)		(10,595)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(642)		(407)		Accumulated other comprehensive loss	(592)		(411)
Total Kinder Morgan, Inc.’s stockholders’ equity	Total Kinder Morgan, Inc.’s stockholders’ equity	30,552		31,436		Total Kinder Morgan, Inc.’s stockholders’ equity	30,545		30,823
Noncontrolling interests	Noncontrolling interests	440		402		Noncontrolling interests	1,080		1,098
Total Stockholders’ Equity	Total Stockholders’ Equity	30,992		31,838		Total Stockholders’ Equity	31,625		31,921
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity		$	69,640	$	71,973
Total Liabilities and Stockholders’ Equity						Total Liabilities and Stockholders’ Equity	$	69,390	$	70,416

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

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
Nine Months Ended September 30,
2021 2020
Cash Flows From Operating Activities
Net income (loss) $ 1,196 $ (443)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation, depletion and amortization 1,595 1,636
Deferred income taxes 236 164
Amortization of excess cost of equity investments 56 99
Loss on impairments and divestitures, net (Note 3) 1,602 1,987
Gain on sale of interest in equity investment (Note 3) (206) —
Earnings from equity investments (392) (562)
Distributions from equity investment earnings 535 487
Changes in components of working capital
Accounts receivable (119) 238
Inventories (89) 41
Other current assets (90) 14
Accounts payable 362 (107)
Accrued interest, net of interest rate swaps (177) (208)
Accrued taxes 15 (25)
Other current liabilities 71 (93)
Rate reparations, refunds and other litigation reserve adjustments (97) 48
Other, net (58) 6
Net Cash Provided by Operating Activities 4,440 3,282
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (1,518) (16)
Capital expenditures (894) (1,351)
Proceeds from sales of investments 417 907
Contributions to investments (36) (365)
Distributions from equity investments in excess of cumulative earnings 121 105
Other, net (1) (56)
Net Cash Used in Investing Activities (1,911) (776)
Cash Flows From Financing Activities
Issuances of debt 4,950 3,888
Payments of debt (6,459) (3,991)
Debt issue costs (20) (23)
Dividends (1,828) (1,764)
Repurchases of shares — (50)
Contributions from investment partner and noncontrolling interests 4 11
Distributions to investment partner (67) (60)
Distributions to noncontrolling interests (14) (11)
Other, net (25) (13)
Net Cash Used in Financing Activities (3,459) (2,013)
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits — (3)
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits (930) 490
Cash, Cash Equivalents, and Restricted Deposits, beginning of period 1,209 209
Cash, Cash Equivalents, and Restricted Deposits, end of period $ 279 $ 699


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

	Six Months Ended June 30,
	2022		2021
Cash Flows From Operating Activities
Net income	$	1,337	$	685
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,081		1,069
Deferred income taxes	369		105
Amortization of excess cost of equity investments	38		35

Change in fair market value of derivative contracts	51		40
(Gain) loss on divestitures and impairments, net	(21)		1,598
Gain on sale of interest in equity investment (Note 2)	—		(206)
Earnings from equity investments	(369)		(223)
Distributions from equity investment earnings	348		346
Changes in components of working capital
Accounts receivable	(414)		(130)
Inventories	(108)		(51)
Other current assets	(39)		(31)
Accounts payable	499		145
Accrued interest, net of interest rate swaps	(53)		(42)
Accrued taxes	(53)		(51)
Other current liabilities	86		195
Rate reparations, refunds and other litigation reserve adjustments	(53)		(102)
Other, net	(51)		(71)
Net Cash Provided by Operating Activities	2,648		3,311
Cash Flows From Investing Activities


Capital expenditures	(779)		(545)
Proceeds from sales of investments	4		413
Contributions to investments	(20)		(26)
Distributions from equity investments in excess of cumulative earnings	104		48

Other, net	19		(1)
Net Cash Used in Investing Activities	(672)		(111)
Cash Flows From Financing Activities
Issuances of debt	4,622		3,110
Payments of debt	(5,848)		(4,273)
Debt issue costs	(7)		(12)
Dividends	(1,247)		(1,212)

Repurchases of shares	(173)		—

Contributions from noncontrolling interests	—		3
Distributions to investment partner	—		(45)

Distributions to noncontrolling interests	(53)		(8)
Other, net	—		(3)
Net Cash Used in Financing Activities	(2,706)		(2,440)

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(730)		760
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	1,147		1,209
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	417	$	1,969


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)

		Nine Months Ended September 30,					Six Months Ended June 30,
		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	102		632		Cash and Cash Equivalents, end of period	100		1,365
Restricted Deposits, end of period	Restricted Deposits, end of period	177		67		Restricted Deposits, end of period	317		604
Cash, Cash Equivalents, and Restricted Deposits, end of period	Cash, Cash Equivalents, and Restricted Deposits, end of period	279		699		Cash, Cash Equivalents, and Restricted Deposits, end of period	417		1,969
Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(930)	$	490	Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(730)	$	760

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		$	35	$	15
Increase in property, plant and equipment from both accruals and contractor retainage		4		0
ROU assets and operating lease obligations recognized including adjustments						ROU assets and operating lease obligations recognized including adjustments	$	(8)	$	28

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)	1,313		1,440		Cash paid during the period for interest (net of capitalized interest)	792		807
Cash paid during the period for income taxes, net	Cash paid during the period for income taxes, net	8		202		Cash paid during the period for income taxes, net	10		8

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			Additional paid-in capital				Accumulated deficit		Accumulated other comprehensive loss				Stockholders’ equity attributable to KMI				Non-controlling interests
		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										Total
Balance at June 30, 2021		2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140
Balance at March 31, 2022																	Balance at March 31, 2022	2,267	$	23			$	41,813					$	(10,544)			$	(674)			$	30,618			$	1,089	$	31,707

Repurchases of shares																	Repurchases of shares	(10)			(172)										(172)								(172)
Restricted shares	Restricted shares	2			(5)						(5)				(5)		Restricted shares				13										13								13
Net income	Net income						495				495		16		511		Net income								635						635				18				653
Distributions	Distributions										—		(6)		(6)		Distributions														—				(27)				(27)
Contributions											—		1		1

Dividends	Dividends						(616)				(616)				(616)		Dividends								(631)						(631)								(631)

Other comprehensive loss									(33)		(33)				(33)
Balance at September 30, 2021		2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992
Other comprehensive income																	Other comprehensive income										82				82								82
Balance at June 30, 2022																	Balance at June 30, 2022	2,257	$	23	$	41,654			$	(10,540)	$	(592)			$	30,545			$	1,080			$	31,625


		Common stock																Common stock			Additional paid-in capital				Accumulated deficit		Accumulated other comprehensive loss				Stockholders’ equity attributable to KMI				Non-controlling interests
		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										Total
Balance at June 30, 2020		2,261	$	23	$	41,731	$	(9,802)	$	(199)	$	31,753	$	371	$	32,124
Balance at March 31, 2021																	Balance at March 31, 2021	2,264	$	23			$	41,775					$	(9,124)			$	(487)			$	32,187			$	416	$	32,603

Restricted shares	Restricted shares	3			5						5				5		Restricted shares	1			18										18								18
Net income							455				455		17		472
Net (loss) income																	Net (loss) income								(757)						(757)				17				(740)

Distributions	Distributions										—		(4)		(4)		Distributions														—				(5)				(5)
Contributions	Contributions										—		2		2		Contributions														—				1				1
Dividends	Dividends						(598)				(598)				(598)		Dividends								(615)						(615)								(615)

Other comprehensive loss	Other comprehensive loss								(56)		(56)				(56)		Other comprehensive loss										(122)				(122)								(122)
Balance at September 30, 2020		2,264	$	23	$	41,736	$	(9,945)	$	(255)	$	31,559	$	386	$	31,945
Balance at June 30, 2021																	Balance at June 30, 2021	2,265	$	23	$	41,793			$	(10,496)	$	(609)			$	30,711			$	429			$	31,140


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value												Total
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)				(11)						(11)				(11)
Balance at January 1, 2022	2,267	23		41,795		(10,595)		(411)		30,812		1,098		31,910

Repurchases of shares	(10)			(173)						(173)				(173)
EP Trust I Preferred security conversions				1						1				1
Restricted shares				31						31				31
Net income						1,302				1,302		35		1,337
Distributions										—		(53)		(53)

Dividends						(1,247)				(1,247)				(1,247)

Other comprehensive loss								(181)		(181)				(181)
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non-controlling interests
	Issued shares	Par value												Total
Balance at December 31, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838





Restricted shares	1			37						37				37
Net income						652				652		33		685


Distributions										—		(8)		(8)
Contributions										—		3		3
Dividends						(1,212)				(1,212)				(1,212)


Other										—		(1)		(1)
Other comprehensive loss								(202)		(202)				(202)
Balance at June 30, 2021	2,265	$	23	$	41,793	$	(10,496)	$	(609)	$	30,711	$	429	$	31,140

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

~~KINDER MORGAN, INC. AND SUBSIDIARIES~~

~~CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)~~

~~(In millions, unaudited)~~

Common stock
Issued shares Par value Additional
paid-in
capital 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 3 32 32 32
Net income 1,147 1,147 49 1,196
Distributions — (14) (14)
Contributions — 4 4
Dividends (1,828) (1,828) (1,828)
Other — (1) (1)
Other comprehensive loss (235) (235) (235)
Balance at September 30, 2021 2,267 $ 23 $ 41,788 $ (10,617) $ (642) $ 30,552 $ 440 $ 30,992

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 3 41 41 41
Net (loss) income (488) (488) 45 (443)
Distributions — (11) (11)
Contributions — 8 8
Dividends (1,764) (1,764) (1,764)
Other comprehensive income 78 78 78
Balance at September 30, 2020 2,264 $ 23 $ 41,736 $ (9,945) $ (255) $ 31,559 $ 386 $ 31,945

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

Mas CanAm, LLC Acquisition

On July 19, 2022, we completed an acquisition of 3 landfill assets from Mas CanAm, LLC, comprising a renewable natural gas facility in Arlington, Texas and medium Btu facilities in Shreveport, Louisiana and Victoria, Texas for approximately $358 million including a preliminary purchase price adjustment for working capital.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, ~~2021~~2022 evaluation, we grouped our businesses into 67 reporting units as follows: (i) Products Pipelines (excluding associated terminals); (ii) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (iii) Natural Gas Pipelines Regulated; (iv) Natural Gas Pipelines Non-Regulated; (v) CO2; (vi) Terminals and ~~(vi) Terminals. See Note~~(vii) Energy Transition Ventures.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates using market approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect to market multiples, comparable sales transactions, general economic conditions and the related demand for products handled or transported by our assets. Changes to any one or a combination of these factors would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.

The results of our May 31, ~~2021 goodwill~~2022 annual impairment ~~test.~~test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value.

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 September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions, except per share amounts)									(In millions, except per share amounts)
Net Income (Loss) Available to Stockholders	Net Income (Loss) Available to Stockholders	$	495	$	455	$	1,147	$	(488)	Net Income (Loss) Available to Stockholders	$	635	$	(757)	$	1,302	$	652
Participating securities:	Participating securities:									Participating securities:
Less: Net Income allocated to restricted stock awards(a)		(4)		(3)		(10)		(9)
Less: Net Income Allocated to Restricted Stock Awards(a)										Less: Net Income Allocated to Restricted Stock Awards(a)	(2)		(3)		(6)		(6)
Net Income (Loss) Allocated to Class P Stockholders	Net Income (Loss) Allocated to Class P Stockholders	$	491	$	452	$	1,137	$	(497)	Net Income (Loss) Allocated to Class P Stockholders	$	633	$	(760)	$	1,296	$	646

Basic Weighted Average Shares Outstanding	Basic Weighted Average Shares Outstanding	2,267		2,263		2,265		2,263		Basic Weighted Average Shares Outstanding	2,265		2,265		2,266		2,264
Basic Earnings (Loss) Per Share	Basic Earnings (Loss) Per Share	$	0.22	$	0.20	$	0.50	$	(0.22)	Basic Earnings (Loss) Per Share	$	0.28	$	(0.34)	$	0.57	$	0.29

(a)As of ~~September~~June 30, ~~2021,~~2022, there were ~~approximately 13~~12 million restricted stock awards outstanding.

The following table presents the maximum number of potential common stock equivalents which are antidilutive and accordingly are excluded from the determination of diluted earnings per ~~share:~~share. As we have no other common stock equivalents, our diluted earnings per share are the same as our basic earnings per share for all periods presented.


		Three Months Ended September 30,		Nine Months Ended September 30,			Three Months Ended June 30,		Six Months Ended June 30,
		2021	2020	2021	2020		2022	2021	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	13	13	13	Unvested restricted stock awards	12	12	13	12
Convertible trust preferred securities	Convertible trust preferred securities	3	3	3	3	Convertible trust preferred securities	3	3	3	3

2. ~~Acquisitions~~

~~As of September 30, 2021, our preliminary allocation of the purchase price for significant acquisitions completed during the nine months ended September 30, 2021 are detailed below.~~

Assignment of Purchase Price
Ref Date Acquisition Purchase price Current assets Property, plant & equipment Deferred charges & other Goodwill Current liabilities Long-term liabilities
(In millions)
(1) 8/21 Kinetrex Energy $ 318 $ 17 $ 49 $ 262 $ 64 $ (6) $ (68)
(2) 7/21 Stagecoach Gas Services LLC 1,228 52 1,041 23 118 (6) —

~~Pro Forma Information~~

Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1, 2021 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of operations.

~~(1) Kinetrex Energy Acquisition~~

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation includes $63 million related to an equity investment and $199 million related to a customer relationship with an amortization period of approximately 10 years. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on 3 additional landfill-based RNG facilities in September 2021. The acquired assets align with our strategy to invest in low-carbon energy and are included as part of our new Energy Transition Ventures group within our CO2 ~~business segment.~~

~~(2) Stagecoach Acquisition~~

On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. Deferred charges and other within the preliminary purchase price allocation relates to customer contracts with a weighted average amortization period of less than 2 years. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets complement and expand our natural gas pipeline and storage business and are included in our Natural Gas Pipelines business segment.

~~Goodwill~~

After measuring all of the identifiable tangible and intangible assets acquired and liabilities assumed at fair value on the acquisition date, the excess purchase price is assigned to goodwill. Goodwill is an intangible asset representing the future economic benefits expected to be derived from an acquisition that are not assigned to other identifiable, separately recognizable assets. We believe the primary items that generated our goodwill are both the value of the synergies created between the acquired assets and our pre-existing assets, and our expected ability to grow the business we acquired by leveraging our pre-existing business experience. Of our acquisitions made during the nine months ended September 30, 2021, goodwill of $118 million associated with our Stagecoach acquisition is tax deductible and we apply a look through method of recording deferred income taxes on the outside book-tax basis differences in our investments. As a result, no deferred income taxes are recorded associated with non-deductible goodwill recorded at the investee level.

~~Changes in the amounts of our goodwill for the nine months ended September 30, 2021 are summarized by reporting unit as follows:~~

Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated
CO2
Products Pipelines Products Pipelines Terminals Terminals Energy Transition Ventures Total
(In millions)
Goodwill as of December 31, 2020 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ — $ 19,851
Acquisitions 118 — — — — — 64 182
Goodwill as of September 30, 2021 $ 14,367 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 64 $ 20,033

3. Losses and Gains on Impairments, Divestitures and Other Write-downs

~~We recognized the following pre-tax losses (gains) on impairments, divestitures and other write-downs, net on assets during the three and nine months ended September 30, 2021 and 2020:~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
(In millions)
Natural Gas Pipelines
Impairment of long-lived and intangible assets(a) $ — $ — $ 1,600 $ —
Impairment of goodwill(a) — — — 1,000
Gain on sale of interest in NGPL Holdings LLC(a) — — (206) —
Loss on write-down of related party note receivable(a) — — 117 —
Loss (gain) on divestitures of long-lived assets and other write-downs — 11 (1) 11
Products Pipelines
Impairment of long-lived and intangible assets — — — 21
Terminals
Impairment of long-lived and intangible assets 14 — 14 5
CO2
Impairment of goodwill(a) — — — 600
Impairment of long-lived assets(a) — — — 350
Gain on divestitures of long-lived assets, net (11) — (8) —
Other loss (gain) on divestitures of long-lived assets, net 1 — (3) —
Pre-tax loss on impairments, divestitures and other write-downs, net $ 4 $ 11 $ 1,513 $ 1,987

~~(a)See below for a further discussion of these items.~~Long-lived Asset Impairment

~~Impairments~~

~~Long-lived Assets~~

During the second quarter of 2021, we evaluated our South Texas gathering and processing assets within our Natural Gas Pipeline business segment for impairment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024. The long-lived asset impairment test involved two steps. Step one was an assessment as to whether the asset’s net book value was expected to be recovered from the estimated undiscounted future cash flows. To compute the estimated undiscounted future cash flows we included an unfavorable adjustment for upcoming contract expirations. With this inclusion, our South Texas gathering and processing assets failed step one. In step two, weWe utilized an income approach to estimate fair value and compared it to the carrying value. ~~We applied an approximate 8.5%~~The significant assumptions made in calculating fair value include estimates of future cash flows and discount ~~rate,~~rates, a Level 3 ~~input, which we believed represented the estimated weighted average cost of capital of a theoretical market participant.~~ input. As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the ~~nine~~six months ended ~~September~~June 30, 2021.

During the first half 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 which resulted in a non-cash impairment of long-lived assets within our CO~~2 ~~business segment shown in the above table during the nine months ended September 30, 2020.~~

~~Goodwill~~Investment in Ruby

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, which is included within “Earnings from equity investments” on our accompanying consolidated statement of operations for the six months ended June 30, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.

Ruby Chapter 11 Bankruptcy Filing

The ~~results~~balance of ~~our May 31, 2021 annual impairment test indicated that for each of our reporting units, the reporting unit fair value exceeded the carrying value. The fair value estimates used~~Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the ~~goodwill impairment test are primarily based on Level 3 inputs~~principal amount of the fair value hierarchy. The inputs include valuation estimates using market and income approach valuation methodologies, which include assumptions primarily involving management’s significant judgments and estimates with respect$475 million. Although Ruby has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its

1411

~~to market multiples, comparable sales transactions, weighted average costs~~obligations under the 2022 unsecured notes on the maturity date of ~~capital, general economic conditions and the related demand~~April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for products handled or transported by our assets as well as assumptions regarding future cash flows based on production growth rate assumptions, terminal values and discount rates. We use primarily a market approach and, in some instances where deemed necessary, also use discounted cash flow analyses to determine the fair value of our assets. We use discount rates representing our estimaterelief under Chapter 11 of the ~~risk-adjusted discount rates that would be used by market participants specific~~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 ~~particular reporting unit.~~

~~During~~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 ~~2020, we conducted interim impairment tests~~2021. We had 0 amounts included in our “Investments” on our accompanying consolidated balance sheets associated with Ruby as of ~~goodwill for our CO~~2 and Natural Gas Pipelines Non-Regulated reporting units, and during the second quarter 2020, we conducted our annual impairment test of goodwill for all of our reporting units which resulted in non-cash impairments of goodwill within our CO2 ~~and Natural Gas Pipelines business segments during the nine months ended September~~June 30, ~~2020 as shown in the table above.~~2022 or December 31, 2021.

As conditions warrant, we routinely evaluate our assets for potential triggering events that could impact the fair value of certain assets or our ability to recover the carrying value of long-lived assets. Such assets include accounts receivable, equity investments, goodwill, other intangibles and property plant and equipment, including oil and gas properties and in-process construction. Depending on the nature of the asset, these evaluations require the use of significant judgments including but not limited to judgments related to customer credit worthiness, future volume expectations, current and future commodity prices, discount rates, regulatory environment, as well as general economic conditions and the related demand for products handled or transported by our assets. Because certain of our assets have been written down to fair value, or its fair value is close to carrying value, any deterioration in fair value could result in further impairments. Such non-cash impairments could have a significant effect on our results of operations, which would be recognized in the period in which the carrying value is determined to not be recoverable.

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 ~~$412~~$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” inon our accompanying consolidated statement of operations for the ~~nine~~six months ended ~~September~~June 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

~~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 for the nine months ended September 30, 2021. 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.

4.3. Debt

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


		September 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(In millions, unless otherwise stated)					(In millions, unless otherwise stated)
Current portion of debt	Current portion of debt					Current portion of debt

$3.5 billion credit facility due August 20, 2026~~(a)~~	$3.5 billion credit facility due August 20, 2026~~(a)~~	$	—	$	—	$3.5 billion credit facility due August 20, 2026~~(a)~~	$	—	$	—
$500 million credit facility due November 16, 2023~~(a)~~	$500 million credit facility due November 16, 2023~~(a)~~	—		—		$500 million credit facility due November 16, 2023~~(a)~~	—		—
Commercial paper notes(a)	Commercial paper notes(a)	160		—		Commercial paper notes(a)	936		—
Current portion of senior notes	Current portion of senior notes					Current portion of senior notes
5.00%, due February 2021(b)		—		750
3.50%, due March 2021(b)		—		750
5.80%, due March 2021(b)		—		400
5.00%, due October 2021(c)		—		500
8.625%, due January 2022		260		—
4.15%, due March 2022		375		—
1.50%, due March 2022(d)		869		—
3.95% due September 2022		1,000		—
8.625%, due January 2022(b)						8.625%, due January 2022(b)	—		260
4.15%, due March 2022(b)						4.15%, due March 2022(b)	—		375
1.50%, due March 2022(b)(c)						1.50%, due March 2022(b)(c)	—		853
3.95% due September 2022(d)						3.95% due September 2022(d)	—		1,000
3.15% due January 2023						3.15% due January 2023	1,000		—
Floating rate, due January 2023(e)						Floating rate, due January 2023(e)	250		—
3.45% due February 2023						3.45% due February 2023	625		—
Trust I preferred securities, 4.75%, due March 2028	Trust I preferred securities, 4.75%, due March 2028	111		111		Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	Current portion of other debt	47		47		Current portion of other debt	48		47
Total current portion of debt	Total current portion of debt	2,822		2,558		Total current portion of debt	2,970		2,646

Long-term debt (excluding current portion)	Long-term debt (excluding current portion)					Long-term debt (excluding current portion)
Senior notes	Senior notes	28,306		30,141		Senior notes	27,477		29,097
EPC Building, LLC, promissory note, 3.967%, due 2020 through 2035		353		364
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035						EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	339		348

Trust I preferred securities, 4.75%, due March 2028	Trust I preferred securities, 4.75%, due March 2028	110		110		Trust I preferred securities, 4.75%, due March 2028	109		110
Other	Other	219		223		Other	215		217
Total long-term debt	Total long-term debt	28,988		30,838		Total long-term debt	28,140		29,772
Total debt(e)		$	31,810	$	33,396
Total debt(f)						Total debt(f)	$	31,110	$	32,418

(a)On August 20, 2021, we entered into an agreement for a new five-year credit facility and amended our existing credit facility discussed further in “—Credit Facilities and Restrictive Covenants” following.Weighted average interest rate on borrowings outstanding as of June 30, 2022 was 1.90%.

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

(c)~~These notes were repaid on July 1, 2021.~~

~~(d)~~Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The ~~September 30,~~December 31, 2021 balance is reported above at the exchange rate of ~~1.1580~~1.1370 U.S. dollars per Euro. As of ~~September 30,~~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 ~~$54~~$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”~~“Current Assets—Fair value of derivative contracts” and ~~“Other current liabilities”~~“Current Liabilities—Fair value of derivative contracts” 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 ~~6 “~~5 “Risk Management~~Risk Management—~~—Foreign Currency Risk Management”).

(d)We repaid the principal amount of these senior notes on June 1, 2022.

(e)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”).

(f)Excludes our “Debt fair value adjustments” which, as of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, increased our total debt balances by ~~$1,014~~$412 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 Facilities and Restrictive Covenants

On August 20, 2021, we entered into a new $3.5 billion revolving credit facility (the “New Credit Facility”) due August 2026 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under the New Credit Facility may be used for working capital and other general corporate purposes. On the same date, we also entered into a first amendment (the “Amendment”) to our existing Revolving Credit Agreement, dated as of November 16, 2018 (as amended prior to the Amendment, the “Existing Credit

Facility”). The Amendment provides for certain amendments to the Existing Credit Facility to, among other things, reduce the Existing Credit Facility’s borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder. The combined credit facilities continue to support our $4 billion commercial paper program.

Depending on the type of loan request, our credit facility borrowings under our New Credit Facility bear interest at either (i) LIBOR adjusted for a eurocurrency funding reserve plus an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) LIBOR for a one-month Eurodollar loan adjusted for a eurocurrency funding reserve, plus 1%, plus, in each case, an applicable margin ranging from 0.100% to 0.750% per annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.100% to 0.250%. The New Credit Facility also includes customary provisions to provide for replacement of LIBOR with an alternative benchmark rate when LIBOR ceases to be available.

The New Credit Facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the New Credit Facility) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions or making or prepayments of loans to us or any guarantor. The New Credit Facility also restricts our ability to make certain restricted payments if an event of default (as defined in the New Credit Facility) has occurred and is continuing or would occur and be continuing.

As of ~~September~~June 30, ~~2021,~~2022, we had no borrowings outstanding under our credit facilities, ~~$160~~$936 million in borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of ~~September~~June 30, ~~2021~~2022 was ~~$3,759 million.~~$3.0 billion. As of ~~September~~June 30, ~~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:

September 30, 2021 December 31, 2020
Carrying
value Estimated
fair value Carrying
value Estimated
fair value
(In millions)
Total debt $ 32,824 $ 37,797 $ 34,689 $ 39,622


	June 30, 2022				December 31, 2021
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,522	$	30,376	$	33,320	$	37,775

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $203 million and $218 million as of June 30, 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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020.~~2021.

5.4. 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. ~~Since~~During the six months ended June 30, 2022, we repurchased approximately 10 million of our shares for $173 million at an average price of $17.37 per share. Subsequent to June 30, 2022 and through July 21, 2022, we repurchased 6 million of our shares for $102 million at an average price of $16.63 per share, and since December 2017, in total, we have repurchased ~~approximately 32~~49 million of our ~~Class P~~ shares under the program at an average price of ~~approximately $17.71~~$17.50 per share for ~~approximately $575~~$850 million.

Dividends

The following table provides information about our per share dividends:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
Per share cash dividend declared for the period	Per share cash dividend declared for the period	$	0.27	$	0.2625	$	0.81	$	0.7875	Per share cash dividend declared for the period	$	0.2775	$	0.27	$	0.555	$	0.54
Per share cash dividend paid in the period	Per share cash dividend paid in the period	0.27		0.2625		0.8025		0.775		Per share cash dividend paid in the period	0.2775		0.27		0.5475		0.5325

On ~~October~~July 20, ~~2021,~~2022, our board of directors declared a cash dividend of ~~$0.27~~$0.2775 per share for the quarterly period ended ~~September~~June 30, ~~2021,~~2022, which is payable on ~~November~~August 15, ~~2021~~2022 to shareholders of record as of the close of business on ~~November~~August 1, ~~2021.~~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 earnings per share 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 six months ended June 30, 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” inon 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) $ — $ (394) $ (407)
Other comprehensive (loss) gain before reclassifications (444) — 28 (416)
Loss reclassified from accumulated other comprehensive loss 181 — — 181
Net current-period change in accumulated other comprehensive loss (263) — 28 (235)
Balance as of September 30, 2021 $ (276) $ — $ (366) $ (642)


	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	(489)		16		(473)
Loss reclassified from accumulated other comprehensive loss	292		—		292
Net current-period change in accumulated other comprehensive (loss) income	(197)		16		(181)
Balance as of June 30, 2022	$	(369)	$	(223)	$	(592)


		Net unrealized gains/(losses) on cash flow hedge derivatives		Foreign currency translation adjustments		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss			Net unrealized gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
		(In millions)									(In millions)
Balance as of December 31, 2019		$	(7)	$	—	$	(326)	$	(333)
Balance as of December 31, 2020										Balance as of December 31, 2020	$	(13)	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	Other comprehensive (loss) gain before reclassifications	(16)		1		21		6		Other comprehensive (loss) gain before reclassifications	(313)		22		(291)
Loss reclassified from accumulated other comprehensive loss	Loss reclassified from accumulated other comprehensive loss	72		—		—		72		Loss reclassified from accumulated other comprehensive loss	89		—		89
Net current-period change in accumulated other comprehensive (loss) income	Net current-period change in accumulated other comprehensive (loss) income	56		1		21		78		Net current-period change in accumulated other comprehensive (loss) income	(224)		22		(202)
Balance as of September 30, 2020		$	49	$	1	$	(305)	$	(255)
Balance as of June 30, 2021										Balance as of June 30, 2021	$	(237)	$	(372)	$	(609)

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 ~~September~~June 30, ~~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	~~(15.9)~~(19.0)	MMBbl
Crude oil basis	~~(6.4)~~(5.2)	MMBbl
Natural gas fixed price	~~(29.5)~~(55.9)	Bcf
Natural gas basis	~~(27.1)~~(45.0)	Bcf
NGL fixed price	~~(1.0)~~(0.8)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	~~(1.4)~~(1.1)	MMBbl
Crude oil basis	~~(8.7)~~(6.6)	MMBbl
Natural gas fixed price	~~(8.7)~~(9.3)	Bcf
Natural gas basis	~~(22.8)~~(22.5)	Bcf
Natural gas options	(0.4)	Bcf
NGL fixed price	~~(1.9)~~(1.1)	MMBbl

As of ~~September~~June 30, ~~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 ~~September~~June 30, ~~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~~6,750

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

~~6,250~~5,100

Mark-to-Market

December 2022

(a)The principal amount of hedged senior notes consisted of ~~$750~~$100 million included in “Current portion of debt” and ~~$6,350~~$6,650 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three and six months ended June 30, 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 ~~nine~~six months ended ~~September~~June 30, ~~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 rates through February 2028. In addition, we entered into variable-to-fixed interest rate swap agreements with a combined notional principal amount of $3,750 million. These agreements were not designated as accounting hedges and effectively fixed our LIBOR exposure for a portion of our fixed-to-variable interest rate swaps for 2022.2032.

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 ~~September~~June 30, ~~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.

Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included inon 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
			September 30, 2021		December 31, 2020		September 30, 2021		December 31, 2020				June 30, 2022		December 31, 2021		June 30, 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	$	(256)	$	(33)	Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	$	58	$	61	$	(357)	$	(141)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		33		(96)		(8)			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		3		(193)		(94)
Subtotal	Subtotal		14		75		(352)		(41)		Subtotal		62		64		(550)		(235)
Interest rate contracts	Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	127		119		(4)		(3)		Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	6		101		(38)		(3)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	350		575		(14)		(7)			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	59		284		(132)		(15)
Subtotal	Subtotal		477		694		(18)		(10)		Subtotal		65		385		(170)		(18)
Foreign currency contracts	Foreign currency contracts	Fair value of derivative contracts/(Other current liabilities)	49		—		(6)		(6)		Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(9)		(3)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		138		—		—			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(27)		—
Subtotal	Subtotal		69		138		(6)		(6)		Subtotal		—		41		(36)		(3)
Total	Total		560		907		(376)		(57)		Total		127		490		(756)		(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)	10		24		(63)		(21)		Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	18		11		(117)		(31)
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		—		(3)		—			Deferred charges and other assets/(Other long-term liabilities and deferred credits)	11		1		(42)		(6)
Subtotal	Subtotal		14		24		(66)		(21)		Subtotal		29		12		(159)		(37)
Interest rate contracts	Interest rate contracts	Fair value of derivative contracts/(Other current liabilities)	—		—		(1)		—		Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	59		12		—		—
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	1		—		—		—
Subtotal			1		—		(1)		—

Total	Total		15		24		(67)		(21)		Total		88		24		(159)		(37)
Total derivatives	Total derivatives		$	575	$	931	$	(443)	$	(78)	Total derivatives		$	215	$	514	$	(915)	$	(293)

2017

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															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			Level 1		Level 2		Level 3		Gross amount		Contracts available for netting		Cash collateral held(b)		Net amount
		(In millions)															(In millions)
As of September 30, 2021
As of June 30, 2022																As of June 30, 2022
Energy commodity derivative contracts(a)																Energy commodity derivative contracts(a)	$	52	$	39	$	—	$	91	$	(90)	$	—	$	1
Interest rate contracts																Interest rate contracts	—		124		—		124		—		—		124

As of December 31, 2021																As of December 31, 2021
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	15	$	13	$	—	$	28	$	(26)	$	—	$	2	Energy commodity derivative contracts(a)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	Interest rate contracts	—		478		—		478		(9)		—		469		Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	Foreign currency contracts	—		69		—		69		(6)		—		63		Foreign currency contracts	—		41		—		41		(3)		—		38
As of December 31, 2020
Energy commodity derivative contracts(a)		$	6	$	93	$	—	$	99	$	(35)	$	—	$	64
Interest rate contracts		—		694		—		694		(2)		—		692
Foreign currency contracts		—		138		—		138		(6)		—		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 September 30, 2021
As of June 30, 2022																As of June 30, 2022
Energy commodity derivative contracts(a)	Energy commodity derivative contracts(a)	$	(111)	$	(307)	$	—	$	(418)	$	26	$	135	$	(257)	Energy commodity derivative contracts(a)	$	(96)	$	(613)	$	—	$	(709)	$	90	$	125	$	(494)
Interest rate contracts	Interest rate contracts	—		(19)		—		(19)		9		—		(10)		Interest rate contracts	—		(170)		—		(170)		—		—		(170)
Foreign currency contracts	Foreign currency contracts	—		(6)		—		(6)		6		—		—		Foreign currency contracts	—		(36)		—		(36)		—		—		(36)
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)	$	—	$	(63)	$	35	$	(8)	$	(36)	Energy commodity derivative contracts(a)	$	(15)	$	(257)	$	—	$	(272)	$	53	$	—	$	(219)
Interest rate contracts	Interest rate contracts	—		(10)		—		(10)		2		—		(8)		Interest rate contracts	—		(18)		—		(18)		9		—		(9)
Foreign currency contracts	Foreign currency contracts	—		(6)		—		(6)		6		—		—		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 inon our accompanying consolidated statements of operations and comprehensive income (loss):


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 September 30,				Nine Months Ended September 30,						Three Months Ended June 30,				Six Months Ended June 30,
			2021		2020		2021		2020				2022		2021		2022		2021
			(In millions)										(In millions)
Interest rate contracts	Interest rate contracts	Interest, net	$	(39)	$	(50)	$	(228)	$	409	Interest rate contracts	Interest, net	$	(160)	$	28	$	(476)	$	(189)

Hedged fixed rate debt(a)	Hedged fixed rate debt(a)	Interest, net	$	39	$	50	$	229	$	(418)	Hedged fixed rate debt(a)	Interest, net	$	162	$	(28)	$	482	$	190

(a)As of ~~September~~June 30, ~~2021,~~2022, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was ~~an increase~~a decrease of ~~$473~~$106 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

2118


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 September 30,					Three Months Ended September 30,					Three Months Ended June 30,					Three Months Ended June 30,
		2021		2020			2021		2020			2022		2021			2022		2021
		(In millions)					(In millions)					(In millions)					(In millions)
Energy commodity derivative contracts	Energy commodity derivative contracts	$	(140)	$	(143)	Revenues—Commodity sales	$	(94)	$	(47)	Energy commodity derivative contracts	$	(70)	$	(215)	Revenues—Commodity sales	$	(185)	$	(53)

						Costs of sales	8		(7)							Costs of sales	7		(2)
Interest rate contracts	Interest rate contracts	1		—		Earnings from equity investments(c)	—		(1)		Interest rate contracts	3		1		Earnings from equity investments(c)	—		—
Foreign currency contracts	Foreign currency contracts	(33)		70		Other, net	(34)		61		Foreign currency contracts	(35)		10		Other, net	(27)		16
Total	Total	$	(172)	$	(73)	Total	$	(120)	$	6	Total	$	(102)	$	(204)	Total	$	(205)	$	(39)

Derivatives in cash flow hedging relationships Gain/(loss)
recognized in OCI on derivative(a) Location Gain/(loss) reclassified from Accumulated OCI
into income(b)
Nine Months Ended
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
(In millions) (In millions)
Energy commodity derivative contracts $ (514) $ (29) Revenues—Commodity sales $ (167) $ (145)
Costs of sales 10 (12)
Interest rate contracts 3 (9) Earnings from equity investments(c) — (1)
Foreign currency contracts (68) 17 Other, net (79) 64
Total $ (579) $ (21) Total $ (236) $ (94)


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2022		2021			2022		2021
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(569)	$	(374)	Revenues—Commodity sales	$	(317)	$	(73)

					Costs of sales	17		2
Interest rate contracts	6		2		Earnings from equity investments(c)	—		—
Foreign currency contracts	(75)		(35)		Other, net	(81)		(45)
Total	$	(638)	$	(407)	Total	$	(381)	$	(116)

(a)We expect to reclassify approximately ~~$181~~$267 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of ~~September~~June 30, ~~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 ~~nine~~six months ended ~~September~~June 30, 2022 and 2021, we recognized approximate gains of $5 million and $6 million, 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
September 30, Nine Months Ended
September 30,
2021 2020 2021 2020
(In millions)
Energy commodity derivative contracts Revenues—Commodity sales $ (40) $ 87 $ (703) $ 353
Costs of sales (7) 12 154 18
Earnings from equity investments (2) — (4) —
Total(a) $ (49) $ 99 $ (553) $ 371


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended June 30,				Six Months Ended June 30,
		2022		2021		2022		2021
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	(17)	$	(33)	$	(26)	$	(663)
	Costs of sales	(8)		(2)		(99)		160
	Earnings from equity investments	—		(2)		(5)		(2)
Interest rate contracts	Interest, net	12		—		48		—
Total(a)		$	(13)	$	(37)	$	(82)	$	(505)

(a)The three and ~~nine~~six months ended ~~September~~June 30, 2022 amounts include approximate losses of $38 million and $20 million, respectively, and the three and six months ended June 30, 2021 amounts include approximate losses of ~~$24~~$7 million and ~~$480 million, respectively, and the three and nine months ended September 30, 2020 amounts include approximate gains of $96 million and $349~~$455 million, respectively. These ~~gains and~~ losses were associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of ~~September~~June 30, ~~2021,~~2022, we had cash margins of ~~$165~~$309 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 ~~September~~June 30, ~~2021~~2022 represents ~~the net of~~ our initial margin requirements of ~~$30~~$184 million and ~~counterparty~~ variation margin requirements of ~~$135 million.~~$125 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 ~~September~~June 30, ~~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 ~~$177~~$358 million of additional collateral.

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 September 30, 2021													Three Months Ended June 30, 2022
		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 customers(a)														Revenues from customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082	Firm services(b)	$	849	$	60	$	198	$	1	$	(1)	$	1,107
Fee-based services	Fee-based services	190		244		93		10		—		537		Fee-based services	234		242		96		11		—		583
Total services	Total services	1,026		310		274		11		(2)		1,619		Total services	1,083		302		294		12		(1)		1,690
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	1,097		—		—		7		(3)		1,101		Natural gas sales	1,810		—		—		24		(6)		1,828
Product sales	Product sales	372		247		8		279		(11)		895		Product sales	410		640		7		404		13		1,474

Total commodity sales	Total commodity sales	1,469		247		8		286		(14)		1,996		Total commodity sales	2,220		640		7		428		7		3,302
Total revenues from contracts with customers		2,495		557		282		297		(16)		3,615
Total revenues from customers														Total revenues from customers	3,303		942		301		440		6		4,992
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	119		42		140		15		—		316		Leasing services(d)	118		49		149		15		—		331
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)		Derivatives adjustments on commodity sales	(81)		—		—		(121)		—		(202)
Other	Other	12		6		—		8		1		27		Other	16		5		—		9		—		30
Total other revenues	Total other revenues	60		48		140		(40)		1		209		Total other revenues	53		54		149		(97)		—		159
Total revenues	Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824	Total revenues	$	3,356	$	996	$	450	$	343	$	6	$	5,151

2321


		Three Months Ended September 30, 2020													Three Months Ended June 30, 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 customers(a)														Revenues from customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	818	$	69	$	185	$	1	$	(2)	$	1,071	Firm services(b)	$	799	$	66	$	198	$	—	$	—	$	1,063
Fee-based services	Fee-based services	173		228		91		8		3		503		Fee-based services	176		244		84		10		—		514
Total services	Total services	991		297		276		9		1		1,574		Total services	975		310		282		10		—		1,577
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	507		—		—		1		(2)		506		Natural gas sales	674		—		—		1		(3)		672
Product sales	Product sales	158		97		5		180		(5)		435		Product sales	248		157		7		258		(13)		657

Total commodity sales	Total commodity sales	665		97		5		181		(7)		941		Total commodity sales	922		157		7		259		(16)		1,329
Total revenues from contracts with customers		1,656		394		281		190		(6)		2,515
Total revenues from customers														Total revenues from customers	1,897		467		289		269		(16)		2,906
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	119		42		143		13		—		317		Leasing services(d)	118		43		144		15		1		321
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	(6)		—		—		46		—		40		Derivatives adjustments on commodity sales	(37)		(1)		—		(47)		—		(85)
Other	Other	40		6		—		2		(1)		47		Other	(2)		5		—		6		(1)		8
Total other revenues	Total other revenues	153		48		143		61		(1)		404		Total other revenues	79		47		144		(26)		—		244
Total revenues	Total revenues	$	1,809	$	442	$	424	$	251	$	(7)	$	2,919	Total revenues	$	1,976	$	514	$	433	$	243	$	(16)	$	3,150

Nine Months Ended September 30, 2021
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b) $ 2,501 $ 191 $ 570 $ 1 $ (2) $ 3,261
Fee-based services 544 709 258 35 — 1,546
Total services 3,045 900 828 36 (2) 4,807
Commodity sales
Natural gas sales 5,090 — — 9 (11) 5,088
Product sales 840 529 20 766 (34) 2,121
Total commodity sales 5,930 529 20 775 (45) 7,209
Total revenues from contracts with customers 8,975 1,429 848 811 (47) 12,016
Other revenues(c)
Leasing services(d) 356 128 427 42 — 953
Derivatives adjustments on commodity sales (726) (1) — (143) — (870)
Other 51 16 — 19 — 86
Total other revenues (319) 143 427 (82) — 169
Total revenues $ 8,656 $ 1,572 $ 1,275 $ 729 $ (47) $ 12,185


	Six Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	1,788	$	119	$	386	$	1	$	(2)	$	2,292
Fee-based services	447		476		194		24		—		1,141
Total services	2,235		595		580		25		(2)		3,433
Commodity sales
Natural gas sales	3,036		—		—		44		(10)		3,070
Product sales	752		1,066		11		752		(3)		2,578

Total commodity sales	3,788		1,066		11		796		(13)		5,648
Total revenues from customers	6,023		1,661		591		821		(15)		9,081
Other revenues(c)
Leasing services(d)	235		93		289		28		—		645
Derivatives adjustments on commodity sales	(120)		(3)		—		(220)		—		(343)
Other	31		11		—		19		—		61
Total other revenues	146		101		289		(173)		—		363
Total revenues	$	6,169	$	1,762	$	880	$	648	$	(15)	$	9,444

2422

Nine Months Ended September 30, 2020
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b) $ 2,479 $ 215 $ 563 $ 1 $ (2) $ 3,256
Fee-based services 523 670 307 31 1 1,532
Total services 3,002 885�� 870 32 (1) 4,788
Commodity sales
Natural gas sales 1,385 — — 1 (5) 1,381
Product sales 396 255 11 546 (22) 1,186
Total commodity sales 1,781 255 11 547 (27) 2,567
Total revenues from contracts with customers 4,783 1,140 881 579 (28) 7,355
Other revenues(c)
Leasing services(d) 346 126 404 34 — 910
Derivatives adjustments on commodity sales 35 — — 173 — 208
Other 91 16 — 6 (1) 112
Total other revenues 472 142 404 213 (1) 1,230
Total revenues $ 5,255 $ 1,282 $ 1,285 $ 792 $ (29) $ 8,585


	Six Months Ended June 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	1,665	$	125	$	389	$	—	$	—	$	2,179
Fee-based services	354		465		165		25		—		1,009
Total services	2,019		590		554		25		—		3,188
Commodity sales
Natural gas sales	3,993		—		—		2		(8)		3,987
Product sales	468		282		12		487		(23)		1,226

Total commodity sales	4,461		282		12		489		(31)		5,213
Total revenues from customers	6,480		872		566		514		(31)		8,401
Other revenues(c)
Leasing services(d)	237		86		287		27		—		637
Derivatives adjustments on commodity sales	(655)		(1)		—		(80)		—		(736)
Other	39		10		—		11		(1)		59
Total other revenues	(379)		95		287		(42)		(1)		(40)
Total revenues	$	6,101	$	967	$	853	$	472	$	(32)	$	8,361

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

(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~~“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 65 “Risk Management” 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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, our contract asset balances were ~~$62~~$42 million and ~~$20~~$39 million, respectively. Of the contract asset balance at December 31, ~~2020, $14~~2021, $22 million was transferred to accounts receivable during the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022. As of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, our contract liability balances were ~~$217~~$215 million and ~~$239~~$212 million, respectively. Of the contract liability balance at December 31, ~~2020, $63~~2021, $59 million was recognized as revenue during the ~~nine~~six months ended ~~September~~June 30, ~~2021.~~2022.

2523

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of ~~September~~June 30, ~~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)
Three months ended December 31, 2021		$	1,178
2022		4,022
Six months ended December 31, 2022				Six months ended December 31, 2022		$	2,279
2023	2023	3,186		2023		3,895
2024	2024	2,711		2024		3,173
2025	2025	2,277		2025		2,635
2026				2026		2,319
Thereafter	Thereafter	14,018		Thereafter	0	13,421
Total	Total	$	27,392	Total		$	27,722

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.

8.7. Reportable Segments

Financial information by segment follows:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		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	$	2,541	$	1,803	$	8,611	$	5,229	Revenues from external customers	$	3,363	$	1,960	$	6,156	$	6,070
Intersegment revenues	Intersegment revenues	14		6		45		26		Intersegment revenues	(7)		16		13		31

Products Pipelines	Products Pipelines	605		442		1,572		1,282		Products Pipelines	996		514		1,762		967

Terminals	Terminals									Terminals
Revenues from external customers	Revenues from external customers	421		423		1,273		1,282		Revenues from external customers	449		433		878		852
Intersegment revenues	Intersegment revenues	1		1		2		3		Intersegment revenues	1		—		2		1
CO2	CO2	257		251		729		792		CO2	343		243		648		472

Corporate and intersegment eliminations	Corporate and intersegment eliminations	(15)		(7)		(47)		(29)		Corporate and intersegment eliminations	6		(16)		(15)		(32)
Total consolidated revenues	Total consolidated revenues	$	3,824	$	2,919	$	12,185	$	8,585	Total consolidated revenues	$	5,151	$	3,150	$	9,444	$	8,361

2624


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions)									(In millions)
Segment EBDA(a)	Segment EBDA(a)									Segment EBDA(a)
Natural Gas Pipelines	Natural Gas Pipelines	$	1,069	$	1,091	$	2,602	$	2,284	Natural Gas Pipelines	$	1,134	$	(570)	$	2,318	$	1,533
Products Pipelines	Products Pipelines	279		223		792		719		Products Pipelines	299		265		598		513
Terminals	Terminals	216		246		689		732		Terminals	253		246		491		473
CO2	CO2	163		156		599		(453)		CO2	212		150		404		436

Total Segment EBDA	Total Segment EBDA	1,727		1,716		4,682		3,282		Total Segment EBDA	1,898		91		3,811		2,955
DD&A	DD&A	(526)		(539)		(1,595)		(1,636)		DD&A	(543)		(528)		(1,081)		(1,069)
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(21)		(32)		(56)		(99)		Amortization of excess cost of equity investments	(19)		(13)		(38)		(35)

General and administrative and corporate charges	General and administrative and corporate charges	(167)		(150)		(465)		(472)		General and administrative and corporate charges	(144)		(150)		(289)		(298)
Interest, net	Interest, net	(368)		(383)		(1,122)		(1,214)		Interest, net	(355)		(377)		(688)		(754)

Income tax expense		(134)		(140)		(248)		(304)
Income tax (expense) benefit										Income tax (expense) benefit	(184)		237		(378)		(114)

Total consolidated net income (loss)	Total consolidated net income (loss)	$	511	$	472	$	1,196	$	(443)	Total consolidated net income (loss)	$	653	$	(740)	$	1,337	$	685


		September 30, 2021		December 31, 2020			June 30, 2022		December 31, 2021
		(In millions)					(In millions)
Assets	Assets					Assets
Natural Gas Pipelines	Natural Gas Pipelines	$	47,576	$	48,597	Natural Gas Pipelines	$	47,780	$	47,746
Products Pipelines	Products Pipelines	9,118		9,182		Products Pipelines	9,221		9,088
Terminals	Terminals	8,507		8,639		Terminals	8,428		8,513
CO2	CO2	2,808		2,478		CO2	2,921		2,843

Corporate assets(b)	Corporate assets(b)	1,631		3,077		Corporate assets(b)	1,040		2,226

Total consolidated assets	Total consolidated assets	$	69,640	$	71,973	Total consolidated assets	$	69,390	$	70,416

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

9.8. Income Taxes

Income tax expense (benefit) included inon our accompanying consolidated statements of operations is as follows:


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended June 30,						Six Months Ended June 30,
		2021			2020			2021			2020				2022			2021			2022			2021
		(In millions, except percentages)													(In millions, except percentages)
Income tax expense		$	134		$	140		$	248		$	304
Income tax expense (benefit)														Income tax expense (benefit)	$	184		$	(237)		$	378		$	114
Effective tax rate	Effective tax rate	20.8		%	22.9		%	17.2		%	(218.7)		%	Effective tax rate	22.0		%	24.3		%	22.0		%	14.3		%

The effective tax rate for the three and six months ended June 30, 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 ~~September~~June 30, 2021 is slightly lower than the statutory federal rate of 21% primarily due to dividend-received deductions from our investments in Citrus Corporation (Citrus), NGPL Holdings and Products (SE) Pipe Line Corporation (PPL), partially offset by state income taxes.

~~The effective tax rates for the three months ended September 30, 2020~~ is higher than the statutory federal rate of 21% primarily due to state income taxes.

The effective tax rate for the ~~nine~~six months ended ~~September~~June 30, 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, NGPL Holdings and PPL, partially offset by state income taxes.

The effective tax rate for the nine months ended September 30, 2020 is “negative” and lower than the statutory federal rate of 21% primarily due to the $1,600 million impairment of non-tax deductible goodwill contributing to our loss before income taxes but not providing a tax benefit.~~This was partially offset by the refund of alternative minimum tax sequestration credits and dividend-received deductions from our investments in Citrus and PPL.~~

While we would normally expect a federal income tax benefit from our loss before income taxes for the nine months ended September 30, 2020, because a tax benefit is not allowed on the goodwill impairment, we incurred an income tax expense for these periods.

~~10.~~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~~EPNG FERC ~~Proceedings~~Proceeding

~~The~~On April 21, 2022, EPNG was notified by the FERC ~~approved~~of the ~~SFPP East Line Settlement in Docket No. IS21-138 (“EL Settlement”) on December 31, 2020 and~~commencement of a rate proceeding against it became 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). The amounts SFPP agreed to pay pursuant to section 5 of the ~~EL Settlement were fully accrued on or before December 31, 2020.~~

~~The tariffs~~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 atonly occur after the FERC ~~that were not fully resolved by the EL Settlement, the shippers pleaded claims to at least $50 million~~has issued an 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 June 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~~The Notice of Arbitration ~~Eni USA~~ sought declaratory and monetary relief based upon ~~its~~Eni USA’s 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 tribunal delivered an Award 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.~~

~~On June 3, 2019,~~and involve the same allegations as the claims which were resolved conclusively in the arbitrations with Eni USA ~~filed~~described above and with GLNG’s remaining customer as described below. On January 4, 2022, the trial court entered 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.decision granting Eni USA’s second arbitration 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, GLNG filed a complaint with the Court of Chancery together with aS.p.A’s motion ~~seeking to permanently enjoin the second arbitration. On cross-appeals from an Order and Final Judgment of the Court of Chancery, the Delaware Supreme Court ruled in favor of GLNG~~for summary judgment on November 17, 2020 and a permanent injunction was entered prohibiting Eni USA from pursuing the second arbitration, including the breach of contract and negligent misrepresentation claims therein. On October 4, 2021, the U.S. Supreme Court denied Eni USA’s petition for writ of certiorari. Consequently, Eni USA remains permanently enjoined from pursuing the second arbitration and the claims asserted ~~therein.~~by GLNG to enforce the Guarantee Agreement. GLNG filed an interlocutory appeal of the decision. Pending resolution of GLNG’s appeal and further proceedings in the trial court, 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.

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 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 gave rise to a contractual right on the part of ALSS to terminate the agreement. ALSS also sought a monetary award directing GLNG to reimburse ALSS for all reservation charges and operating fees paid by ALSS after December 31, 2016 plus interest. On July 15, 2021, the arbitration tribunal delivered ~~a Final~~an Award on the merits of all claims submitted to the tribunal and denied all of ALSS’s claims with prejudice. On November 23, 2021, the 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~~asserts 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 $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 ~~$98~~$104 million, plus attorney fees and interest. We believe that our declaration of force majeure iswas valid and ~~appropriate and intend to~~we are vigorously ~~defend~~defending against ~~Freeport’s~~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.

Arizona Line 2000 Rupture

On August 15, 2021, the 30” EPNG Line 2000 natural gas transmission pipeline ruptured in a rural area in Coolidge, Arizona. The failure resulted in a fire which destroyed a home, resulting in two fatalities and one injury. The National Transportation Safety Board is investigating the incident. The impacted pipeline segment is currently out of service.

General

As of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, our total reserve for legal matters was ~~$192~~$178 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.

PHMSA Enforcement Matter for KMLT Midwest Terminals

On July 11, 2022, Kinder Morgan Liquid Terminals (KMLT) received a Notice of Probable Violation (NOPV) from PHMSA relating to inspections conducted during 2021 at KMLT’s Cincinnati, Indianapolis, Dayton, Argo, O’Hare, and Wood River Terminals. The NOPV alleges 16 violations of Department of Transportation regulations. The NOPV proposes a penalty of approximately $455,000 and seeks a compliance agreement relating to 3 of the alleged violations. The alleged violations are predominately procedural in nature. We are reviewing the NOPV and have not yet determined which of the allegations we will contest or whether we will pursue an alternative resolution with PHMSA. We do not anticipate the costs to resolve this matter, including any costs to implement a compliance agreement, will have a material adverse impact to our business.

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 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. and EPEC Oil Company Liquidating Trust (collectively EPEC) are 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 in New Jersey. EPEC entered into two Administrative Orders on Consent (AOCs) with the EPA which ~~obligate them~~obligates EPEC to investigate and characterize contamination at the Site. EPEC is part of a joint defense group of approximately 44 cooperating parties which is directing and funding the AOC work required by the EPA. We have established a reserve for the anticipated cost of compliance with these two AOCs. On March 4, 2016, the EPA issued a Record of Decision (ROD) for the lower 8 miles of the Site. At that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, 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 and certain PRPs, including EPEC, are engaged in discussions with the EPA as a result thereof. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the lower eight mile ROD. On October 4, 2021, the EPA issued a ROD for the upper 9 miles of the Site. The cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the 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. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the 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 to be remanded to the state district court for Plaquemines Parish. ~~The defendants appealed that decision. On August 10, 2020,~~In May 2018, the ~~Fifth Circuit affirmed remand.The defendants filed~~case was removed for a ~~motion for rehearing. On August 5, 2021, the Fifth Circuit remanded the case~~second time to the U.S. District Court. In May 2019, the U.S. District Court 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 court and ordered to be remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases are pursuing an appeal of the remand decisions to the United States Court of Appeals for the Fifth Circuit to determine whether there is federal officer jurisdiction. The case remains effectively stayed pending a ruling by the ~~U.S. District Court on~~Fifth Circuit in the ~~federal officer issue.~~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~~Products Pipeline Incident, Walnut Creek, California

~~Beginning~~On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in ~~January 2015,~~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 ~~private landowners~~days and on November 24, 2020, identified a crack in ~~Louisiana, as Plaintiffs, filed separate lawsuits in state district courts in Louisiana against~~the pipeline and notified the regulatory agencies of a number of oil and gas pipeline companies, including 4 cases against TGP, 3 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“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 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 ~~property, and damage to timber and wildlife. The Plaintiffs allege the defendants’ conduct constitutes a breach~~waters of the ~~subject right~~State of ~~way agreements, is inconsistent with prudent operating practices, violates Louisiana law,~~California, and ~~that defendants’~~there was a failure to ~~maintain canals~~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 ~~canal banks constitutes negligence~~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 ~~trespass. The plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest,~~paid approximately $2.5 million in fines, penalties, restitution, environmental improvement project funding, and ~~payment~~for enforcement training in the State of ~~costs necessary~~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 ~~return the canals and canal banks to their as-built conditions and restore and~~ remediate the affected ~~property. The Plaintiffs also seek~~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 ~~declaration that the defendants are obligated~~material adverse impact to ~~take steps to maintain canals and canal banks going forward. We will continue to vigorously defend the remaining cases.~~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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we have accrued a total reserve for environmental liabilities in the amount of ~~$242~~$235 million and ~~$250~~$243 million, respectively. In addition, as of both ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, we had a receivable of $12 million recorded for expected cost recoveries that have been deemed probable.

~~11.~~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~~six months ended June 30, 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 $725 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.~~

~~ASU No. 2021-05~~

~~On July 19, 2021, the FASB issued ASU No. 2021-05, “Leases (Topic 842); Lessors - Certain Leases with Variable Lease Payments.” This ASU requires a lessor to classify a lease with entirely or partially variable payments that do not depend on an index or~~interest rate as an operating lease if another classification (i.e. sales-type or direct financing) would trigger a day-one loss. ASU No. 2021-05 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.

risk management activities.

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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 in our ~~2020~~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 Part I, Item 1A of our ~~2020~~2021 Form 10-K.

~~Long-lived Asset Impairment~~

During the second quarter 2021 we recognized a non-cash, long-lived asset impairment of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipeline business segment, which was driven by lower expectations regarding the volumes and rates associated with the re-contracting of contracts expiring through 2024.

~~Stagecoach Acquisition~~

On July 9, 2021, we completed the acquisition of subsidiaries of Stagecoach Gas Services LLC (Stagecoach), a natural gas pipeline and storage joint venture between Consolidated Edison, Inc. and Crestwood Equity Partners, LP, for approximately $1,228 million, including a preliminary purchase price adjustment for working capital. The Stagecoach assets include 4 natural gas storage facilities with a total FERC-certificated working capacity of 41 Bcf and a network of FERC-regulated natural gas transportation pipelines with multiple interconnects to major interstate natural gas pipelines in the northeast region of the U.S., including TGP. The acquired assets are included in our Natural Gas Pipelines business segment.

~~Kinetrex Energy Acquisition~~

On August 20, 2021, we completed the acquisition of Indianapolis-based Kinetrex Energy (Kinetrex) from an affiliate of Parallel49 Equity for $318 million, including a preliminary purchase price adjustment for working capital. Kinetrex is a supplier of liquefied natural gas in the Midwest and a producer and supplier of renewable natural gas (RNG) under long-term contracts to transportation service providers. Kinetrex has a 50% interest in the largest RNG facility in Indiana and we commenced construction on three additional landfill-based RNG facilities in September 2021. The acquired assets are included as part of our new Energy Transition Ventures group within our CO2 ~~business segment.~~

~~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 $412 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 nine months ended September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.

~~February 2021 Winter Storm~~

Our year-to-date 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. ~~Excluding the recent acquisitions, we~~We now expect to invest ~~$0.8~~$1.9 billion in expansion projects, acquisitions, 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.

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 8, ~~“Reportable~~7 “Reportable Segments”) and 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 and Net Debt.

GAAP Financial Measures

The Consolidated Earnings Results for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020~~2021 present Segment EBDA and 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 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 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 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 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 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 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 “—Non-GAAP Financial Measures—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 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 “—Non-GAAP Financial Measures—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 ~~September~~June 30, ~~2021,~~2022, by subtracting the following amounts from our debt balance of ~~$32,824~~$31,522 million: (i) cash and cash equivalents of ~~$102~~$100 million; and (ii) debt fair value adjustments of ~~$1,014~~$412 million; and ~~(iii)~~excluding the foreign exchange impact on Euro-denominated bonds of ~~$90~~$(19) 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.

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Consolidated Earnings Results (GAAP)

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


		Three Months Ended September 30,									Three Months Ended June 30,
		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	$	1,069	$	1,091	$	(22)	(2)	%	Natural Gas Pipelines	$	1,134	$	(570)	$	1,704	299%
Products Pipelines	Products Pipelines	279		223		56		25	%	Products Pipelines	299		265		34		13%
Terminals	Terminals	216		246		(30)		(12)	%	Terminals	253		246		7		3%
CO2	CO2	163		156		7		4	%	CO2	212		150		62		41%

Total Segment EBDA	Total Segment EBDA	1,727		1,716		11		1	%	Total Segment EBDA	1,898		91		1,807		1,986%
DD&A	DD&A	(526)		(539)		13		2	%	DD&A	(543)		(528)		(15)		(3)%
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(21)		(32)		11		34	%	Amortization of excess cost of equity investments	(19)		(13)		(6)		(46)%

General and administrative and corporate charges	General and administrative and corporate charges	(167)		(150)		(17)		(11)	%	General and administrative and corporate charges	(144)		(150)		6		4%

Interest, net	Interest, net	(368)		(383)		15		4	%	Interest, net	(355)		(377)		22		6%
Income before income taxes		645		612		33		5	%
Income tax expense		(134)		(140)		6		4	%
Income (loss) before income taxes										Income (loss) before income taxes	837		(977)		1,814		186%
Income tax (expense) benefit										Income tax (expense) benefit	(184)		237		(421)		(178)%

Net income		511		472		39		8	%
Net income (loss)										Net income (loss)	653		(740)		1,393		188%
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(16)		(17)		1		6	%	Net income attributable to noncontrolling interests	(18)		(17)		(1)		(6)%
Net income attributable to Kinder Morgan, Inc.		$	495	$	455	$	40	9	%
Net income (loss) attributable to Kinder Morgan, Inc.										Net income (loss) attributable to Kinder Morgan, Inc.	$	635	$	(757)	$	1,392	184%


		Nine Months Ended September 30,									Six Months Ended June 30,
		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	$	2,602	$	2,284	$	318	14	%	Natural Gas Pipelines	$	2,318	$	1,533	$	785	51	%
Products Pipelines	Products Pipelines	792		719		73		10	%	Products Pipelines	598		513		85		17	%
Terminals	Terminals	689		732		(43)		(6)	%	Terminals	491		473		18		4	%
CO2	CO2	599		(453)		1,052		232	%	CO2	404		436		(32)		(7)	%

Total Segment EBDA	Total Segment EBDA	4,682		3,282		1,400		43	%	Total Segment EBDA	3,811		2,955		856		29	%
DD&A	DD&A	(1,595)		(1,636)		41		3	%	DD&A	(1,081)		(1,069)		(12)		(1)	%
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(56)		(99)		43		43	%	Amortization of excess cost of equity investments	(38)		(35)		(3)		(9)	%

General and administrative and corporate charges	General and administrative and corporate charges	(465)		(472)		7		1	%	General and administrative and corporate charges	(289)		(298)		9		3	%

Interest, net	Interest, net	(1,122)		(1,214)		92		8	%	Interest, net	(688)		(754)		66		9	%
Income (loss) before income taxes		1,444		(139)		1,583		1,139	%
Income before income taxes										Income before income taxes	1,715		799		916		115	%
Income tax expense	Income tax expense	(248)		(304)		56		18	%	Income tax expense	(378)		(114)		(264)		(232)	%

Net income (loss)		1,196		(443)		1,639		370	%
Net income										Net income	1,337		685		652		95	%
Net income attributable to noncontrolling interests	Net income attributable to noncontrolling interests	(49)		(45)		(4)		(9)	%	Net income attributable to noncontrolling interests	(35)		(33)		(2)		(6)	%
Net income (loss) attributable to Kinder Morgan, Inc.		$	1,147	$	(488)	$	1,635	335	%
Net income attributable to Kinder Morgan, Inc.										Net income attributable to Kinder Morgan, Inc.	$	1,302	$	652	$	650	100	%

(a)Includes revenues, earnings from equity investments, ~~and other, net, less~~ operating expenses, (gain) loss on divestitures and impairments, ~~and divestitures,~~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 ~~$40~~$1,392 million and ~~$1,635~~$650 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, respectively, as compared to the respective prior year periods. The ~~third~~second quarter ~~increase in results~~and year-to-

date increases were impacted by higher earnings from our Products Pipelines business segment, lower interest expense and DD&A expense (including amortization of excess cost of equity investments) partially offset by lower earnings from our Terminals and Natural Gas Pipelines business segments and higher general and administrative and corporate charges expense. The year-to-date increase was primarily ~~impacted by higher earnings from our Natural Gas Pipelines and CO~~2 ~~business segments primarily related~~due to ~~the February 2021 winter storm and therefore largely nonrecurring, and a decrease of $362 million of impairments in 2021 as compared to 2020 primarily reflecting~~ the $1,600 million pre-tax non-cash ~~asset~~ impairment loss in 2021 related to South Texas gathering and processing assets within our Natural Gas Pipeline segment ~~in 2021 compared to the combined $1,950 million of non-cash impairments recognized in 2020 of goodwill associated with our Natural Gas Pipelines Non-Regulated~~ and CO2 ~~reporting units and non-cash asset impairments of certain oil and gas producing assets in our CO~~2 ~~business segment. The impacts of the long-lived asset impairments for both periods were partially offset by associated tax benefits. The year-to-date increase was also impacted by~~ higher earnings from our Products Pipelines business segment ~~lower interest expense~~with our West Coast Refined Products and ~~DD&A expense (including amortization of excess cost of equity investments)~~Southeast Refined Products assets. The year-to-date increase was partially offset by ~~lower~~the benefit in the 2021 period of $1,102 million for largely nonrecurring earnings related to the February 2021 winter storm, mostly impacting the earnings from our ~~Terminals~~Natural Gas Pipelines and CO2 business ~~segment.~~segments.

Certain Items Affecting Consolidated Earnings Results

Three Months Ended September 30,
2021 2020
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 1,069 $ 21 $ 1,090 $ 1,091 $ (9) $ 1,082 $ 8
Products Pipelines 279 1 280 223 46 269 11
Terminals 216 17 233 246 — 246 (13)
CO2
163 (9) 154 156 (2) 154 —
Total Segment EBDA(a) 1,727 30 1,757 1,716 35 1,751 6
DD&A and amortization of excess cost of equity investments (547) — (547) (571) — (571) 24
General and administrative and corporate charges(a) (167) — (167) (150) 11 (139) (28)
Interest, net(a) (368) (8) (376) (383) (8) (391) 15
Income before income taxes 645 22 667 612 38 650 17
Income tax expense(b) (134) (12) (146) (140) (8) (148) 2
Net income 511 10 521 472 30 502 19
Net income attributable to noncontrolling interests(a) (16) — (16) (17) — (17) 1
Net income attributable to Kinder Morgan, Inc. $ 495 $ 10 $ 505 $ 455 $ 30 $ 485 $ 20


	Three Months Ended June 30,
	2022						2021
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,134	$	(1)	$	1,133	$	(570)	$	1,634	$	1,064	$	69
Products Pipelines	299		—		299		265		28		293		6
Terminals	253		—		253		246		—		246		7
CO2	212		(1)		211		150		1		151		60

Total Segment EBDA(a)	1,898		(2)		1,896		91		1,663		1,754		142
DD&A and amortization of excess cost of equity investments	(562)		—		(562)		(541)		—		(541)		(21)
General and administrative and corporate charges(a)	(144)		—		(144)		(150)		—		(150)		6
Interest, net(a)	(355)		(17)		(372)		(377)		(3)		(380)		8
Income (loss) before income taxes	837		(19)		818		(977)		1,660		683		135
Income tax (expense) benefit(b)	(184)		5		(179)		237		(387)		(150)		(29)
Net income (loss)	653		(14)		639		(740)		1,273		533		106
Net income attributable to noncontrolling interests(a)	(18)		—		(18)		(17)		—		(17)		(1)

Net income (loss) attributable to Kinder Morgan, Inc.	$	635	$	(14)	$	621	$	(757)	$	1,273	$	516	$	105

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		Nine Months Ended September 30,															Six Months Ended June 30,
		2021						2020									2022						2021
		GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings			GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
		(In millions)															(In millions)
Segment EBDA	Segment EBDA															Segment EBDA
Natural Gas Pipelines	Natural Gas Pipelines	$	2,602	$	1,646	$	4,248	$	2,284	$	993	$	3,277	$	971	Natural Gas Pipelines	$	2,318	$	112	$	2,430	$	1,533	$	1,625	$	3,158	$	(728)
Products Pipelines	Products Pipelines	792		44		836		719		50		769		67		Products Pipelines	598		—		598		513		43		556		42
Terminals	Terminals	689		17		706		732		—		732		(26)		Terminals	491		—		491		473		—		473		18
CO2	CO2	599		(3)		596		(453)		938		485		111		CO2	404		15		419		436		6		442		(23)

Total Segment EBDA(a)	Total Segment EBDA(a)	4,682		1,704		6,386		3,282		1,981		5,263		1,123		Total Segment EBDA(a)	3,811		127		3,938		2,955		1,674		4,629		(691)
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments	(1,651)		—		(1,651)		(1,735)		—		(1,735)		84		DD&A and amortization of excess cost of equity investments	(1,119)		—		(1,119)		(1,104)		—		(1,104)		(15)
General and administrative and corporate charges(a)	General and administrative and corporate charges(a)	(465)		—		(465)		(472)		36		(436)		(29)		General and administrative and corporate charges(a)	(289)		—		(289)		(298)		—		(298)		9
Interest, net(a)	Interest, net(a)	(1,122)		(17)		(1,139)		(1,214)		(8)		(1,222)		83		Interest, net(a)	(688)		(61)		(749)		(754)		(9)		(763)		14
Income (loss) before income taxes		1,444		1,687		3,131		(139)		2,009		1,870		1,261
Income before income taxes																Income before income taxes	1,715		66		1,781		799		1,665		2,464		(683)
Income tax expense(b)	Income tax expense(b)	(248)		(439)		(687)		(304)		(114)		(418)		(269)		Income tax expense(b)	(378)		(15)		(393)		(114)		(427)		(541)		148
Net income (loss)		1,196		1,248		2,444		(443)		1,895		1,452		992
Net income																Net income	1,337		51		1,388		685		1,238		1,923		(535)
Net income attributable to noncontrolling interests(a)	Net income attributable to noncontrolling interests(a)	(49)		—		(49)		(45)		—		(45)		(4)		Net income attributable to noncontrolling interests(a)	(35)		—		(35)		(33)		—		(33)		(2)

Net income (loss) attributable to Kinder Morgan, Inc.		$	1,147	$	1,248	$	2,395	$	(488)	$	1,895	$	1,407	$	988
Net income attributable to Kinder Morgan, Inc.																Net income attributable to Kinder Morgan, Inc.	$	1,302	$	51	$	1,353	$	652	$	1,238	$	1,890	$	(537)

(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 by ~~$20 million and $988~~$105 million for the three ~~and nine~~ months ended ~~September~~June 30, ~~2021, respectively,~~2022 and decreased by $537 million for the six months ended June 30, 2022 as compared to the respective prior year periods. The ~~third~~second quarter increase was primarily due to higher earnings from our ~~Products Pipelines and~~ Natural Gas ~~Pipelines~~ Pipeline and CO2 business segments and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment.segments. The year-to-date ~~increase~~decrease was impacted by ~~higher~~lower earnings of $806 million from our Natural Gas Pipelines business segment’s Midstream region and $56 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,~~nonrecurring) partially offset by lower income tax expense and higher earnings from our Products Pipelines business segment and lower DD&A expense (including amortization of excess cost of equity investments) and interest expense partially offset by higher general and administrative and corporate charges expense and lower earnings from our Terminals business segment.

3937

Non-GAAP Financial Measures

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions)									(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	495	$	455	$	1,147	$	(488)	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)	$	635	$	(757)	$	1,302	$	652
Total Certain Items	Total Certain Items	10		30		1,248		1,895		Total Certain Items	(14)		1,273		51		1,238
Adjusted Earnings(a)	Adjusted Earnings(a)	505		485		2,395		1,407		Adjusted Earnings(a)	621		516		1,353		1,890
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)	612		662		1,854		2,012		DD&A and amortization of excess cost of equity investments for DCF(b)	627		604		1,250		1,242
Income tax expense for DCF(a)(b)	Income tax expense for DCF(a)(b)	165		171		754		484		Income tax expense for DCF(a)(b)	199		170		434		589
Cash taxes(b)	Cash taxes(b)	(12)		(49)		(56)		(57)		Cash taxes(b)	(47)		(45)		(48)		(44)
Sustaining capital expenditures(b)	Sustaining capital expenditures(b)	(241)		(177)		(558)		(477)		Sustaining capital expenditures(b)	(213)		(210)		(338)		(317)
Other items(c)	Other items(c)	(16)		(7)		(22)		(22)		Other items(c)	(11)		(10)		(20)		(6)
DCF	DCF	$	1,013	$	1,085	$	4,367	$	3,347	DCF	$	1,176	$	1,025	$	2,631	$	3,354

Adjusted Segment EBDA to Adjusted EBITDA to DCF


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions, except per share amounts)									(In millions, except per share amounts)
Natural Gas Pipelines	Natural Gas Pipelines	$	1,090	$	1,082	$	4,248	$	3,277	Natural Gas Pipelines	$	1,133	$	1,064	$	2,430	$	3,158
Products Pipelines	Products Pipelines	280		269		836		769		Products Pipelines	299		293		598		556
Terminals	Terminals	233		246		706		732		Terminals	253		246		491		473
CO2	CO2	154		154		596		485		CO2	211		151		419		442

Adjusted Segment EBDA(a)	Adjusted Segment EBDA(a)	1,757		1,751		6,386		5,263		Adjusted Segment EBDA(a)	1,896		1,754		3,938		4,629
General and administrative and corporate charges(a)	General and administrative and corporate charges(a)	(167)		(139)		(465)		(436)		General and administrative and corporate charges(a)	(144)		(150)		(289)		(298)
Joint venture DD&A and income tax expense(a)(b)	Joint venture DD&A and income tax expense(a)(b)	84		114		270		343		Joint venture DD&A and income tax expense(a)(b)	85		83		172		186
Net income attributable to noncontrolling interests(a)	Net income attributable to noncontrolling interests(a)	(16)		(17)		(49)		(45)		Net income attributable to noncontrolling interests(a)	(18)		(17)		(35)		(33)
Adjusted EBITDA	Adjusted EBITDA	1,658		1,709		6,142		5,125		Adjusted EBITDA	1,819		1,670		3,786		4,484
Interest, net(a)	Interest, net(a)	(376)		(391)		(1,139)		(1,222)		Interest, net(a)	(372)		(380)		(749)		(763)
Cash taxes(b)	Cash taxes(b)	(12)		(49)		(56)		(57)		Cash taxes(b)	(47)		(45)		(48)		(44)
Sustaining capital expenditures(b)	Sustaining capital expenditures(b)	(241)		(177)		(558)		(477)		Sustaining capital expenditures(b)	(213)		(210)		(338)		(317)

Other items(c)	Other items(c)	(16)		(7)		(22)		(22)		Other items(c)	(11)		(10)		(20)		(6)
DCF	DCF	$	1,013	$	1,085	$	4,367	$	3,347	DCF	$	1,176	$	1,025	$	2,631	$	3,354

Adjusted Earnings per share	Adjusted Earnings per share	$	0.22	$	0.21	$	1.05	$	0.62	Adjusted Earnings per share	$	0.27	$	0.23	$	0.59	$	0.83
Weighted average shares outstanding for dividends(d)	Weighted average shares outstanding for dividends(d)	2,279		2,276		2,278		2,276		Weighted average shares outstanding for dividends(d)	2,277		2,277		2,279		2,277
DCF per share	DCF per share	$	0.44	$	0.48	$	1.92	$	1.47	DCF per share	$	0.52	$	0.45	$	1.15	$	1.47
Declared dividends per share	Declared dividends per share	$	0.27	$	0.2625	$	0.81	$	0.7875	Declared dividends per share	$	0.2775	$	0.27	$	0.555	$	0.54

(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.

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

4038

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


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions)									(In millions)
Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)~~(a)~~	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)~~(a)~~	$	495	$	455	$	1,147	$	(488)	Net income (loss) attributable to Kinder Morgan, Inc. (GAAP)~~(a)~~	$	635	$	(757)	$	1,302	$	652
Certain Items:	Certain Items:									Certain Items:
Fair value amortization	Fair value amortization	(7)		(5)		(15)		(17)		Fair value amortization	(3)		(4)		(7)		(8)
Legal, environmental and taxes other than income tax reserves	Legal, environmental and taxes other than income tax reserves	—		46		112		38		Legal, environmental and taxes other than income tax reserves	—		28		—		112
Change in fair value of derivative contracts~~(b)~~(a)	Change in fair value of derivative contracts~~(b)~~(a)	22		(6)		64		(10)		Change in fair value of derivative contracts~~(b)~~(a)	(27)		28		55		42
Loss on impairments, divestitures and other write-downs, net~~(c)~~(b)	Loss on impairments, divestitures and other write-downs, net~~(c)~~(b)	4		11		1,515		382		Loss on impairments, divestitures and other write-downs, net~~(c)~~(b)	—		1,600		—		1,511
Loss on impairments of goodwill(d)		—		—		—		1,600

COVID-19 costs		—		11		—		11

Income tax Certain Items	Income tax Certain Items	(12)		(8)		(439)		(114)		Income tax Certain Items	5		(387)		(15)		(427)

Other	Other	3		(19)		11		5		Other	11		8		18		8
Total Certain Items~~(e)~~(c)	Total Certain Items~~(e)~~(c)	10		30		1,248		1,895		Total Certain Items~~(e)~~(c)	(14)		1,273		51		1,238
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735		DD&A and amortization of excess cost of equity investments	562		541		1,119		1,104
Income tax expense~~(f)~~(d)	Income tax expense~~(f)~~(d)	146		148		687		418		Income tax expense~~(f)~~(d)	179		150		393		541
Joint venture DD&A and income tax expense~~(g)~~(e)	Joint venture DD&A and income tax expense~~(g)~~(e)	84		114		270		343		Joint venture DD&A and income tax expense~~(g)~~(e)	85		83		172		186
Interest, net~~(f)~~(d)	Interest, net~~(f)~~(d)	376		391		1,139		1,222		Interest, net~~(f)~~(d)	372		380		749		763

Adjusted EBITDA	Adjusted EBITDA	$	1,658	$	1,709	$	6,142	$	5,125	Adjusted EBITDA	$	1,819	$	1,670	$	3,786	$	4,484

(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)Three and ~~nine~~six months ended ~~September~~June 30, 2021 amounts include a non-cash impairment of $14 million related to the reclassification of an asset to held for sale within our Terminals business segment, offset partially by a gain of $10 million on the sale of assets within our CO2 ~~business segment. Nine months ended September 30, 2021 amount also includes~~ a pre-tax non-cash impairment loss of $1,600 million related to our South Texas gathering and processing assets within our Natural Gas Pipelines business segment resulting from anticipated lower ~~expectations regarding the~~ volumes and rates ~~associated with re-contracting and a write-down of $117 million, reported within “Earnings from equity investments”~~ on ~~the accompanying consolidated statement of operations, on a long-term subordinated note receivable from an equity investee, Ruby, offset partially by~~contract renewals. Six months ended June 30, 2021 amount also includes a pre-tax gain of $206 million ~~reported within “Other, net” on the accompanying consolidated statement of operations,~~ associated with the sale of a partial interest in our equity investment in NGPL ~~Holdings. Nine months ended September 30, 2020 amount includes~~Holdings LLC, offset partially by a ~~pre-tax non-cash impairment loss~~write-down of ~~$350~~$117 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. Except as otherwise noted above, these amounts are~~on a long-term subordinated note receivable from an equity investee, Ruby, reported within ~~“Loss on impairments~~“Other, net” and ~~divestitures, net”~~“Earnings from equity investments,” respectively, on the accompanying consolidated statement of operations.

~~(d)~~(c)~~Nine~~Three and six months ended ~~September~~June 30, ~~2020 amount includes non-cash impairments of goodwill of $1,000 million and $600 million associated with our Natural Gas Pipelines Non-Regulated and our CO~~2 ~~reporting units, respectively.~~

~~(e)Three months ended September 30, 2021 and 2020~~2022 amounts include ~~$2 million~~no amount and ~~$(4)~~$5 million, respectively, and ~~nine~~three and six months ended ~~September~~June 30, 2021 ~~and 2020~~ amounts include ~~$129~~$10 million and ~~$(4)~~$127 million, respectively, reported within “Earnings from equity investments” on our consolidated statements of operations.

~~(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.

4139

Supplemental Information


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions)									(In millions)
DD&A (GAAP)	DD&A (GAAP)	$	526	$	539	$	1,595	$	1,636	DD&A (GAAP)	$	543	$	528	$	1,081	$	1,069
Amortization of excess cost of equity investments (GAAP)	Amortization of excess cost of equity investments (GAAP)	21		32		56		99		Amortization of excess cost of equity investments (GAAP)	19		13		38		35
DD&A and amortization of excess cost of equity investments	DD&A and amortization of excess cost of equity investments	547		571		1,651		1,735		DD&A and amortization of excess cost of equity investments	562		541		1,119		1,104
Joint venture DD&A	Joint venture DD&A	65		91		203		277		Joint venture DD&A	65		63		131		138

DD&A and amortization of excess cost of equity investments for DCF	DD&A and amortization of excess cost of equity investments for DCF	$	612	$	662	$	1,854	$	2,012	DD&A and amortization of excess cost of equity investments for DCF	$	627	$	604	$	1,250	$	1,242

Income tax expense (GAAP)		$	134	$	140	$	248	$	304
Income tax expense (benefit) (GAAP)										Income tax expense (benefit) (GAAP)	$	184	$	(237)	$	378	$	114
Certain Items	Certain Items	12		8		439		114		Certain Items	(5)		387		15		427
Income tax expense(a)	Income tax expense(a)	146		148		687		418		Income tax expense(a)	179		150		393		541
Unconsolidated joint venture income tax expense(a)(b)	Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66		Unconsolidated joint venture income tax expense(a)(b)	20		20		41		48

Income tax expense for DCF(a)	Income tax expense for DCF(a)	$	165	$	171	$	754	$	484	Income tax expense for DCF(a)	$	199	$	170	$	434	$	589

Additional joint venture information	Additional joint venture information									Additional joint venture information
Unconsolidated joint venture DD&A	Unconsolidated joint venture DD&A	$	76	$	101	$	236	$	306	Unconsolidated joint venture DD&A	$	76	$	74	$	153	$	160
Less: Consolidated joint venture partners’ DD&A	Less: Consolidated joint venture partners’ DD&A	11		10		33		29		Less: Consolidated joint venture partners’ DD&A	11		11		22		22
Joint venture DD&A	Joint venture DD&A	65		91		203		277		Joint venture DD&A	65		63		131		138
Unconsolidated joint venture income tax expense(a)(b)	Unconsolidated joint venture income tax expense(a)(b)	19		23		67		66		Unconsolidated joint venture income tax expense(a)(b)	20		20		41		48
Joint venture DD&A and income tax expense(a)	Joint venture DD&A and income tax expense(a)	$	84	$	114	$	270	$	343	Joint venture DD&A and income tax expense(a)	$	85	$	83	$	172	$	186

Unconsolidated joint venture cash taxes(b)	Unconsolidated joint venture cash taxes(b)	$	(13)	$	(41)	$	(47)	$	(51)	Unconsolidated joint venture cash taxes(b)	$	(39)	$	(34)	$	(39)	$	(34)

Unconsolidated joint venture sustaining capital expenditures	Unconsolidated joint venture sustaining capital expenditures	$	(29)	$	(32)	$	(81)	$	(84)	Unconsolidated joint venture sustaining capital expenditures	$	(39)	$	(32)	$	(51)	$	(52)
Less: Consolidated joint venture partners’ sustaining capital expenditures	Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(2)		(5)		(4)		Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(2)		(4)		(3)
Joint venture sustaining capital expenditures	Joint venture sustaining capital expenditures	$	(27)	$	(30)	$	(76)	$	(80)	Joint venture sustaining capital expenditures	$	(37)	$	(30)	$	(47)	$	(49)

(a)Amounts are adjusted for Certain Items.

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

4240

Segment Earnings Results

Natural Gas Pipelines


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions, except operating statistics)									(In millions, except operating statistics)
Revenues	Revenues	$	2,555	$	1,809	$	8,656	$	5,255	Revenues	$	3,356	$	1,976	$	6,169	$	6,101
Operating expenses	Operating expenses	(1,634)		(878)		(4,981)		(2,455)		Operating expenses	(2,374)		(1,077)		(4,158)		(3,347)
Loss on impairments and divestitures, net	Loss on impairments and divestitures, net	—		(11)		(1,599)		(1,011)		Loss on impairments and divestitures, net	—		(1,599)		—		(1,599)
Other income	Other income	—		—		2		1		Other income	1		1		2		2
Earnings from equity investments	Earnings from equity investments	144		169		311		484		Earnings from equity investments	149		126		303		167

Other, net	Other, net	4		2		213		10		Other, net	2		3		2		209
Segment EBDA	Segment EBDA	1,069		1,091		2,602		2,284		Segment EBDA	1,134		(570)		2,318		1,533
Certain Items(a)	Certain Items(a)	21		(9)		1,646		993		Certain Items(a)	(1)		1,634		112		1,625
Adjusted Segment EBDA	Adjusted Segment EBDA	$	1,090	$	1,082	$	4,248	$	3,277	Adjusted Segment EBDA	$	1,133	$	1,064	$	2,430	$	3,158

Change from prior period	Change from prior period	Increase/(Decrease)								Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA	$	8			$	971			Adjusted Segment EBDA	$	69			$	(728)

Volumetric data(b)	Volumetric data(b)									Volumetric data(b)
Transport volumes (BBtu/d)	Transport volumes (BBtu/d)	38,527		37,475		38,593		37,887		Transport volumes (BBtu/d)	37,822		38,408		38,771		38,627
Sales volumes (BBtu/d)	Sales volumes (BBtu/d)	2,616		2,382		2,480		2,330		Sales volumes (BBtu/d)	2,579		2,561		2,547		2,411
Gathering volumes (BBtu/d)	Gathering volumes (BBtu/d)	2,808		2,925		2,662		3,109		Gathering volumes (BBtu/d)	2,997		2,667		2,908		2,588
NGLs (MBbl/d)	NGLs (MBbl/d)	29		22		30		27		NGLs (MBbl/d)	30		30		31		30

Certain Items affecting Segment EBDA

(a)~~Includes Certain Item amounts~~Three months ended June 30, 2022 amount includes an increase in revenues of ~~$21~~$11 million and ~~$1,646~~a decrease in costs of sales of $1 million, ~~for the three~~ and ~~nine~~six months ended ~~September~~June 30, ~~2021, respectively, and $(9)~~2022 amount includes a decrease in revenues of $3 million and ~~$993~~an increase in costs of sales of $86 million ~~for the three~~related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and ~~nine~~NGL sales and purchases. Three and six months ended ~~September~~June 30, ~~2020, respectively.~~2022 amounts also include an increase in other operating expenses of $11 million and $18 million, respectively, related to costs associated with a pipeline rupture. Three and ~~nine~~six months ended ~~September~~June 30, 2021 amounts include a pre-tax non-cash asset impairment loss of $1,600 million resulting from anticipated lower volumes and rates on contract renewals related to our South Texas gathering and processing assets and decreases in revenues of ~~$14~~$16 million and ~~$36~~$22 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. ~~Nine~~Six months ended ~~September~~June 30, 2021 amount also includes a pre-tax ~~non-cash asset impairment loss~~gain of ~~$1,600~~$206 million ~~resulting from lower expectations regarding the volumes and rates~~ associated with ~~re-contracting related to~~the sale of a partial interest in our ~~South Texas gathering and processing assets,~~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 litigation reserve partially offset by a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings. Three and nine months ended September 30, 2020 amounts both include an increase in revenues of $(14) million of amortization of regulatory liabilities, largely offset by non-cash amounts related to mark-to-market derivative contracts. Nine months ended September 30, 2020 amount also includes a $1,000 million non-cash goodwill impairment on our Natural Gas Pipelines Non-Regulated reporting unit.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. Volumes for acquired pipelines are included~~ for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.

4341

Below are the changes in Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended ~~September~~June 30, ~~2021~~2022 versus Three Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
East						East	$	599	$	539	$	60
Midstream	Midstream	$	29	11%		Midstream	328		300		28
East Region		8		1%
West Region		(29)		(11)%
West						West	206		225		(19)

Total Natural Gas Pipelines	Total Natural Gas Pipelines	$	8	1	%	Total Natural Gas Pipelines	$	1,133	$	1,064	$	69

~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 versus ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
East						East	$	1,251	$	1,129	$	122
Midstream	Midstream	$	998	123%		Midstream	712		1,518		(806)
East Region		25		1%
West Region		(52)		(7)%
West						West	467		511		(44)

Total Natural Gas Pipelines	Total Natural Gas Pipelines	$	971	30	%	Total Natural Gas Pipelines	$	2,430	$	3,158	$	(728)

The changes in Segment EBDA for our Natural Gas Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

•$2960 million (11%) and ~~$998~~$122 million ~~(123%) increases, respectively, in Midstream~~ ~~were primarily due to (i) higher equity earnings due to the Permian Highway Pipeline being placed in service in January 2021; (ii) higher~~ ~~sales margins driven by higher commodity prices on our Texas intrastate natural gas pipeline operations~~; (iii) higher earnings on Kinder Morgan Altamont LLC primarily due to higher commodity prices and volumes; and (iv) higher volumes on our Hiland Midstream assets. The year-to-date increase was also impacted by higher commodity prices as a result of the February 2021 winter storm on our South Texas assets and Texas intrastate natural gas pipeline operations partially offset by the impacts of lower volumes on KinderHawk and certain purchase contract obligations on our Oklahoma assets. ~~Overall Midstream’s revenues increased primarily due to higher commodity prices which was partially offset by corresponding increases in costs of sales;~~

•~~$8 million (1%) and $25 million (1%~~(11%) increases, respectively, in the East Region ~~were~~was primarily due to our July 2021 acquisition of the Stagecoach assets ~~partially offset by lower~~and increased earnings ~~on Fayetteville Express~~from Kinder Morgan Louisiana Pipeline, LLC ~~driven by lower revenues resulting~~ from ~~contract expirations.~~a new customer contract. The year-to-date increase was also impacted by higher earnings from TGP primarily due to ~~weather-driven~~ increases in ~~reservation and park and loan~~transportation revenues ~~mostly during the first quarter~~as a result of ~~2021 and increased earnings from Elba Liquefaction Company, L.L.C. resulting from the liquefaction units~~new customer contracts partially offset by lower revenues as a result of the ~~Elba Liquefaction project being fully operational as of August 2020;~~February 2021 winter storm; and

•$2928 million ~~(11%~~(9%) increase and $806 million (53%) decrease, respectively, in Midstream. The second quarter increase was primarily due to higher NGL sales margins driven by higher prices on our South Texas and Altamont assets and higher volumes on Kinderhawk assets partially offset by lower gas sales margin on our Texas intrastate natural gas pipeline operations due to lower prices. The year-to-date decrease was primarily due to lower sales margins resulting in decreases of $846 million on our Texas intrastate natural gas pipeline operations and $71 million on our South Texas assets largely driven by higher 2021 commodity prices related to the February 2021 winter storm. These decreases were partially offset by higher earnings on our Oklahoma assets from higher 2021 commodity prices on certain purchase contracts as a result of the February 2021 winter storm, higher volumes on Kinderhawk assets, and higher NGL sales margins driven by higher prices on our Altamont asset. Overall, Midstream’s revenues are partially offset by corresponding changes in costs of sales; partially offset by

•$19 million (8%) and ~~$52~~$44 million ~~(7%~~(9%) decreases, respectively, in the West Region ~~were~~was primarily due to ~~lower earnings from Wyoming Interstate Company, LLC,~~ ~~Colorado Interstate Gas Company, L.L.C. and Cheyenne Plains Gas Pipeline Company, L.L.C.~~ ~~driven by lower revenues due to contract expirations and lower equity earnings from Ruby. The third quarter decrease was also impacted by~~ lower earnings from EPNG driven by lower commodity and park and loan ~~revenues.~~revenues resulting from a partial pipeline outage, and lower earnings from Colorado Interstate Gas Company, L.L.C. driven by lower revenues due to a rate case settlement.

4442

Products Pipelines


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions, except operating statistics)									(In millions, except operating statistics)
Revenues	Revenues	$	605	$	442	$	1,572	$	1,282	Revenues	$	996	$	514	$	1,762	$	967
Operating expenses	Operating expenses	(341)		(233)		(828)		(585)		Operating expenses	(717)		(268)		(1,214)		(487)
Loss on impairments and divestitures, net		—		—		—		(21)
Gain on divestitures and impairments, net										Gain on divestitures and impairments, net	—		—		12		—

Earnings from equity investments	Earnings from equity investments	15		14		48		42		Earnings from equity investments	20		19		38		33

Other, net		—		—		—		1

Segment EBDA	Segment EBDA	279		223		792		719		Segment EBDA	299		265		598		513
Certain Items(a)	Certain Items(a)	1		46		44		50		Certain Items(a)	—		28		—		43
Adjusted Segment EBDA	Adjusted Segment EBDA	$	280	$	269	$	836	$	769	Adjusted Segment EBDA	$	299	$	293	$	598	$	556

Change from prior period	Change from prior period	Increase/(Decrease)								Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA	$	11			$	67			Adjusted Segment EBDA	$	6			$	42

Volumetric data(b)	Volumetric data(b)									Volumetric data(b)
Gasoline(c)	Gasoline(c)	1,023		941		987		888		Gasoline(c)	1,017		1,046		979		969
Diesel fuel	Diesel fuel	389		383		395		371		Diesel fuel	372		418		371		398
Jet fuel	Jet fuel	250		160		217		184		Jet fuel	267		224		255		200
Total refined product volumes	Total refined product volumes	1,662		1,484		1,599		1,443		Total refined product volumes	1,656		1,688		1,605		1,567
Crude and condensate	Crude and condensate	491		530		503		570		Crude and condensate	478		510		482		508
Total delivery volumes (MBbl/d)	Total delivery volumes (MBbl/d)	2,153		2,014		2,102		2,013		Total delivery volumes (MBbl/d)	2,134		2,198		2,087		2,075

Certain Items affecting Segment EBDA

(a)~~Includes Certain Item amounts of $1 million~~Three and ~~$44 million for the three and nine months ended September 30, 2021, respectively, and $46 million and $50 million for the three and nine months ended September 30, 2020, respectively. Nine~~six month 2021 ~~amount includes increases~~amounts include an increase in expense of $28 ~~million and $15~~ million related to a litigation reserve ~~and~~adjustment. Six month 2021 amount also includes an increase in expense of $15 million related to an environmental reserve ~~adjustment, respectively. Three and nine month 2020 amounts both include a $46 million unfavorable rate case reserve~~ adjustment. Nine month 2020 amount also includes a non-cash loss on impairment of our Belton Terminal of $21 million partially offset by 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.

4543

Below are the changes in Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended ~~September~~June 30, ~~2021~~2022 versus Three Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
Southeast Refined Products						Southeast Refined Products	$	79	$	69	$	10
West Coast Refined Products	West Coast Refined Products	$	17	15	%	West Coast Refined Products	131		128		3
Southeast Refined Products		6		10	%
Crude and Condensate	Crude and Condensate	(12)		(12)	%	Crude and Condensate	89		96		(7)

Total Products Pipelines	Total Products Pipelines	$	11	4	%	Total Products Pipelines	$	299	$	293	$	6

~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 versus ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
Southeast Refined Products						Southeast Refined Products	$	152	$	134	$	18
West Coast Refined Products	West Coast Refined Products	$	38	11	%	West Coast Refined Products	268		238		30
Southeast Refined Products		39		25	%
Crude and Condensate	Crude and Condensate	(10)		(4)	%	Crude and Condensate	178		184		(6)

Total Products Pipelines	Total Products Pipelines	$	67	9	%	Total Products Pipelines	$	598	$	556	$	42

The changes in Segment EBDA for our Products Pipelines business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September 30, 2021~~June 20, 2022 and ~~2020:~~2021:

•$1710 million ~~(15%~~(14%) and ~~$38~~$18 million (11%) increases, respectively, in West Coast Refined Products were primarily due to increased earnings on Pacific (SFPP), and to a lesser extent, on Calnev Pipe Line LLC and West Coast terminals driven by higher ~~revenues from the continued recovery of volumes in 2021 compared to 2020 which was impacted by COVID-19, partially offset by higher operating expense primarily as a result of higher integrity management spending on SFPP;~~

•~~$6 million (10%) and $39 million (25%~~(13%) increases, respectively, in Southeast Refined Products ~~were~~was primarily due to ~~South East Terminals resulting from increased revenues from~~higher ~~volumes driven by continued recovery of volumes from 2020.~~ ~~The year-to-date increase was also driven by higher 2021~~ earnings at our Transmix processing operations primarily due to higher prices an~~d first quarter 2020 unfavorable inventory adjustments,~~ and ~~an increase in equity earnings from Products (SE) Pipe Line primarily due to~~ ~~product net gains resulting from higher prices;~~ volumes; and

•$123 million ~~(12%~~(2%) and ~~$10~~$30 million ~~(4%~~(13%) increases, respectively, in West Coast Refined Products was primarily due to increased earnings driven by higher revenues on Pacific operations (SFPP) resulting from higher jet fuel volumes and West Coast terminals resulting from higher volumes. The year-to-date increase was also impacted by a gain on sale of land at Calnev Pipe Line LLC; partially offset by

•$7 million (7%) and $6 million (3%) decreases, respectively, in Crude and Condensate ~~were~~was primarily due to ~~decreased~~lower earnings from ~~the Bakken~~Double H pipeline resulting from decreased revenues due to lower volumes. Crude ~~assets~~ and ~~KM Condensate Processing Facility (KMCC - Splitter) partially offset by increased earnings from Kinder Morgan Crude &~~ Condensate Pipeline ~~(KMCC).~~ ~~The Bakken Crude assets’ decreased earnings were driven by lower volumes, contracts renewed at lower average rates,~~also had higher revenues of $401 million and contract expirations partially offset by lower field operating expenses. KMCC - Splitter’s decreased earnings were driven by higher field maintenance expenses. KMCC’s increased earnings were primarily due to higher deficiency revenues and lower field operating expense partially offset by contract expirations. Bakken ~~Crude assets’ and KMCC’s year-to-date changes~~$623 million, respectively, were also impacted by first quarter 2020 unfavorable inventory valuation adjustments. In addition, increased marketing activities within KMCC have resulted in third quarter and year-to-date increases in revenues with corresponding increases in cost of ~~sales.~~sales, resulting from increased marketing activities.

4644

Terminals


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended June 30,						Six Months Ended June 30,
		2021			2020			2021			2020				2022			2021			2022			2021
		(In millions, except operating statistics)													(In millions, except operating statistics)
Revenues	Revenues	$	422		$	424		$	1,275		$	1,285		Revenues	$	450		$	433		$	880		$	853
Operating expenses	Operating expenses	(200)			(185)			(588)			(570)			Operating expenses	(216)			(191)			(415)			(388)
Loss on impairments and divestitures, net		(14)			—			(14)			(5)
Gain (loss) on divestitures and impairments, net														Gain (loss) on divestitures and impairments, net	12			(1)			9			—
Other income	Other income	4			—			4			—			Other income	—			—			4			—
Earnings from equity investments	Earnings from equity investments	3			7			10			19			Earnings from equity investments	4			4			8			7
Other, net	Other, net	1			—			2			3			Other, net	3			1			5			1
Segment EBDA	Segment EBDA	216			246			689			732			Segment EBDA	253			246			491			473
Certain Items~~(a)~~	Certain Items~~(a)~~	17			—			17			—			Certain Items~~(a)~~	—			—			—			—
Adjusted Segment EBDA	Adjusted Segment EBDA	$	233		$	246		$	706		$	732		Adjusted Segment EBDA	$	253		$	246		$	491		$	473

Change from prior period	Change from prior period	Increase/(Decrease)												Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA	$	(13)					$	(26)					Adjusted Segment EBDA	$	7					$	18

Volumetric data~~(b)~~(a)	Volumetric data~~(b)~~(a)													Volumetric data~~(b)~~(a)
Liquids leasable capacity (MMBbl)	Liquids leasable capacity (MMBbl)	79.9			79.6			79.9			79.6			Liquids leasable capacity (MMBbl)	78.9			79.0			78.9			79.0
Liquids utilization %~~(c)~~(b)	Liquids utilization %~~(c)~~(b)	94.2		%	96.3		%	94.2		%	96.3		%	Liquids utilization %~~(c)~~(b)	90.8		%	94.1		%	90.8		%	94.1		%
Bulk transload tonnage (MMtons)	Bulk transload tonnage (MMtons)	13.5			11.3			38.1			35.4			Bulk transload tonnage (MMtons)	13.7			13.6			26.7			24.5

~~Certain Items affecting Segment EBDA~~Other

(a)~~Includes Certain Item amounts of $17 million~~Volumes for ~~both three and nine months ended September 30, 2021 primarily resulting from a pre-tax non-cash impairment loss of $14 million related to the reclassification of an asset to~~facilities divested, idled and/or held for ~~sale.~~

~~Other~~

~~(b)Volumes for assets sold~~sale are excluded for all periods presented.

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

4745

For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical region and included within the All others group. Below are the changes in Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended ~~September~~June 30, ~~2021~~2022 versus Three Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
Mid Atlantic						Mid Atlantic	$	24	$	17	$	7
Gulf Liquids						Gulf Liquids	75		72		3
Gulf Central						Gulf Central	35		33		2
Northeast						Northeast	23		29		(6)
Marine operations	Marine operations	$	(15)	(29)	%	Marine operations	33		38		(5)
Gulf Central		5		19	%
Mid Atlantic		4		40	%
Northeast		(2)		(7)	%
All others (including intrasegment eliminations)	All others (including intrasegment eliminations)	(5)		(4)	%	All others (including intrasegment eliminations)	63		57		6
Total Terminals	Total Terminals	$	(13)	(5)	%	Total Terminals	$	253	$	246	$	7

~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 versus ~~Nine~~Six Months Ended ~~September~~June 30, ~~2020~~2021


		Adjusted Segment EBDA increase/(decrease)					Adjusted Segment EBDA
		(In millions, except percentages)					2022		2021		increase/ (decrease)
Mid Atlantic						Mid Atlantic	$	47	$	32	$	15
Gulf Liquids						Gulf Liquids	152		144		8
Gulf Central						Gulf Central	67		52		15
Northeast						Northeast	45		55		(10)
Marine operations	Marine operations	$	(39)	(25)	%	Marine operations	71		80		(9)
Gulf Central		(7)		(8)	%
Mid Atlantic		8		21	%
Northeast		9		13	%
All others (including intrasegment eliminations)	All others (including intrasegment eliminations)	3		1	%	All others (including intrasegment eliminations)	109		110		(1)
Total Terminals	Total Terminals	$	(26)	(4)	%	Total Terminals	$	491	$	473	$	18

The changes in Segment EBDA for our Terminals business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

•$157 million ~~(29%~~(41%) and ~~$39~~$15 million ~~(25%) decreases, respectively, in Marine operations were primarily due to lower fleet utilization and average charter rates;~~

•$5 million (19%) increase and $7 million (8%) decrease, respectively, in the Gulf Central terminals. The third quarter increase in earnings was primarily due to higher revenues resulting from higher ethanol, petroleum coke, and coal volumes. The year-to-date decrease in earnings was primarily driven by unfavorable petroleum coke volumes due to refinery outages associated with the February 2021 winter storm as well as an increase in property tax expense at Battleground Oil Specialty Terminal Company LLC;

•~~$4 million (40%) and $8 million (21%~~(47%) increases, respectively, in the Mid Atlantic terminals ~~were~~was primarily due to higher handling rates and coal volumes at our Pier IX facility; and

•$3 million (4%) and $8 million (6%) increases, respectively, in the Gulf Liquids region was primarily due to increased revenues from contractual rate escalations and higher volumes and associated ancillary fees; and

•$2 million ~~(7%~~(6%) ~~decrease~~ and $9$15 million ~~(13%~~(29%) increases, respectively, in the Gulf Central terminals was primarily due to higher volumes for petroleum coke handling activities, owing largely to refinery outages in the 2021 period associated with the February 2021 winter storm, increased revenues resulting from contractual rate escalations, and higher coal volumes. The year-to-date increase was also impacted by lower property tax expense at Battleground Oil Specialty Terminal Company LLC; partially offset by,

•$6 million (21%) and $10 million (18%) decreases, respectively, in the Northeast ~~terminals. The year-to-date increase~~terminals was primarily driven by ~~increased~~decreased revenues associated with lower utilization and rates on re-contracted tank positions at our Carteret and Perth Amboy facilities; and

•$5 million (13%) and $9 million (11%) decreases, respectively, in Marine operations was primarily due to lower average charter rates partially offset by higher ~~throughput levels and new contracts.~~fleet utilization.

4846

CO2


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended June 30,				Six Months Ended June 30,
		2021		2020		2021		2020			2022		2021		2022		2021
		(In millions, except operating statistics)									(In millions, except operating statistics)
Revenues	Revenues	$	257	$	251	$	729	$	792	Revenues	$	343	$	243	$	648	$	472
Operating expenses	Operating expenses	(112)		(99)		(161)		(312)		Operating expenses	(140)		(98)		(265)		(49)
Gain (loss) on impairments and divestitures, net	Gain (loss) on impairments and divestitures, net	11		—		8		(950)		Gain (loss) on impairments and divestitures, net	—		(3)		1		(3)

Earnings from equity investments	Earnings from equity investments	7		4		23		17		Earnings from equity investments	9		8		20		16

Segment EBDA	Segment EBDA	163		156		599		(453)		Segment EBDA	212		150		404		436
Certain Items(a)	Certain Items(a)	(9)		(2)		(3)		938		Certain Items(a)	(1)		1		15		6
Adjusted Segment EBDA	Adjusted Segment EBDA	$	154	$	154	$	596	$	485	Adjusted Segment EBDA	$	211	$	151	$	419	$	442

Change from prior period	Change from prior period	Increase/(Decrease)								Change from prior period	Increase/(Decrease)
Adjusted Segment EBDA	Adjusted Segment EBDA	$	—			$	111			Adjusted Segment EBDA	$	60			$	(23)

Volumetric data	Volumetric data									Volumetric data
SACROC oil production	SACROC oil production	20.1		21.2		19.9		22.1		SACROC oil production	19.7		20.2		19.5		19.8
Yates oil production	Yates oil production	6.5		6.4		6.5		6.7		Yates oil production	6.3		6.7		6.6		6.4
Katz and Goldsmith oil production	Katz and Goldsmith oil production	2.1		2.6		2.3		2.8		Katz and Goldsmith oil production	1.8		2.2		1.8		2.4
Tall Cotton oil production	Tall Cotton oil production	1.1		1.4		1.0		1.9		Tall Cotton oil production	1.0		1.0		1.0		1.0
Total oil production, net (MBbl/d)(b)	Total oil production, net (MBbl/d)(b)	29.8		31.6		29.7		33.5		Total oil production, net (MBbl/d)(b)	28.8		30.1		28.9		29.6
NGL sales volumes, net (MBbl/d)(b)	NGL sales volumes, net (MBbl/d)(b)	9.7		9.1		9.3		9.4		NGL sales volumes, net (MBbl/d)(b)	9.2		9.5		9.3		9.1

CO2 sales volumes, net (Bcf/d)	CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.5		CO2 sales volumes, net (Bcf/d)	0.4		0.4		0.4		0.4
Realized weighted average oil price ($ per Bbl)	Realized weighted average oil price ($ per Bbl)	$	53.03	$	54.83	$	52.21	$	53.28	Realized weighted average oil price ($ per Bbl)	$	68.92	$	52.50	$	67.91	$	51.79
Realized weighted average NGL price ($ per Bbl)	Realized weighted average NGL price ($ per Bbl)	$	28.01	$	17.65	$	23.73	$	17.77	Realized weighted average NGL price ($ per Bbl)	$	41.86	$	22.58	$	42.77	$	21.42

Certain Items affecting Segment EBDA

(a)Includes Certain Item amounts of ~~$(9)~~$(1) million and ~~$(3)~~$15 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021,~~2022, respectively, and ~~$(2)~~$1 million and ~~$938~~$6 million for the three and ~~nine~~six months ended ~~September~~June 30, ~~2020, respectively. Nine month 2020 amount primarily resulted from a $600 million goodwill impairment on our CO~~2 ~~reporting unit and~~2021, respectively, as changes in revenue related to non-cash ~~impairments of $350 million on our oil and gas producing assets.~~mark-to-market 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 and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

Three Months Ended ~~September~~June 30, ~~2021~~2022 versus Three Months Ended ~~September~~June 30, ~~2020~~2021

Adjusted Segment EBDA
increase/(decrease)
(In millions, except percentages)
Oil and Gas Producing activities $ (42) (40) %
Source and Transportation activities 40 82 %
Subtotal (2) (1) %
Energy Transition Ventures 2 n/a
Total CO2
$ — — %


	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Oil and Gas Producing activities	$	136	$	99	$	37
Source and Transportation activities	69		52		17

Subtotal	205		151		54
Energy Transition Ventures	6		—		6
Total CO2	$	211	$	151	$	60

~~Nine~~Six Months Ended ~~September~~June 30, ~~2021~~2022 versus ~~Nine~~Six Months Ended ~~September~~June 30, ~~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	$	73	23	%	Oil and Gas Producing activities	$	278	$	334	$	(56)
Source and Transportation activities	Source and Transportation activities	36		22	%	Source and Transportation activities	131		108		23

Subtotal	Subtotal	109		22	%	Subtotal	409		442		(33)
Energy Transition Ventures	Energy Transition Ventures	2		n/a		Energy Transition Ventures	10		—		10
Total CO2	Total CO2	$	111	23	%	Total CO2	$	419	$	442	$	(23)

~~n/a - not applicable~~

The changes in Segment EBDA for our CO2 business segment are further explained by the following discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and ~~nine-month~~six-month periods ended ~~September~~June 30, ~~2021~~2022 and ~~2020:~~2021:

•$4237 million ~~(40%~~(37%) increase and $56 million (17%) decrease, ~~and $73 million (23%) increase,~~ respectively, in Oil and Gas Producing activities. The ~~third~~second quarter ~~decrease~~increase was primarily due to ~~a settlement for a terminated affiliate~~ ~~purchase~~ ~~contract with Source and Transportation activities which increased operating expenses by $38 million and lower~~higher realized crude oil ~~sales revenues of $14 million due to lower volumes~~ and ~~realized prices partially offset by higher realized~~ NGL prices which increased revenues by ~~$12 million.~~$63 million partially offset by higher operating expenses. The year-to-date ~~increase~~decrease was primarily due to ~~lower~~higher operating expenses of ~~$118~~$172 million mainly driven by athe benefit realized in the 2021 period ~~realized~~ from returning power to the grid by curtailing oil production during the February 2021 winter storm ~~net of the impact of the terminated affiliate contract noted above, and~~partially offset by higher realized crude oil and NGL prices which increased revenues by $27 million, partially offset by lower crude oil volumes which decreased revenues by $45 million, driven in part, by the curtailed oil production and by lower realized crude oil prices which decreased revenues by $22approximately $123 million; and

•$4017 million ~~(82%~~(33%) and ~~$36~~$23 million ~~(22%~~(21%) increases, respectively, in Source and Transportation activities primarily due to ~~a settlement for a terminated affiliate sales contract with Oil and Gas Producing activities which resulted in an increase in~~increased revenues ~~of $38 million. The year-to-date increase was also impacted by a decrease in revenues of $19 million~~ related to ~~lower~~higher CO2 sales ~~volumes partially offset by an increase in equity earnings of $6 million and lower operating expenses of $5 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 ~~September~~June 30, ~~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	$	53.41	$	51.70	$	50.97	$	52.19	Price ($ per Bbl)	$	61.19	$	61.10	$	58.88	$	59.08	$	66.47
Volume (MBbl/d)	Volume (MBbl/d)	25.70		17.00		11.20		5.90		2.85		Volume (MBbl/d)	25.20		19.00		11.60		6.75		2.10
NGLs	NGLs											NGLs
Price ($ per Bbl)	Price ($ per Bbl)	$	36.39	$	47.76							Price ($ per Bbl)	$	55.36	$	61.12
Volume (MBbl/d)	Volume (MBbl/d)	6.03		2.56								Volume (MBbl/d)	4.76		1.27
Midland-to-Cushing Basis Spread	Midland-to-Cushing Basis Spread											Midland-to-Cushing Basis Spread
Price ($ per Bbl)	Price ($ per Bbl)	$	0.26	$	0.59							Price ($ per Bbl)	$	0.53	$	0.54
Volume (MBbl/d)	Volume (MBbl/d)	24.55		14.00								Volume (MBbl/d)	23.65		4.50

(a)Includes West Texas Intermediate hedges.

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


		Three Months Ended September 30,				Earnings increase/(decrease)					Three Months Ended June 30,				Earnings increase/(decrease)
		2021		2020							2022		2021
		(In millions, except percentages)									(In millions, except percentages)
DD&A (GAAP)	DD&A (GAAP)	$	(526)	$	(539)	$	13	2	%	DD&A (GAAP)	$	(543)	$	(528)	$	(15)	(3)	%

General and administrative (GAAP)	General and administrative (GAAP)	$	(174)	$	(153)	$	(21)	(14)	%	General and administrative (GAAP)	$	(152)	$	(160)	$	8	5	%
Corporate benefit	Corporate benefit	7		3		4		133	%	Corporate benefit	8		10		(2)		(20)	%
Certain Items~~(a)~~	Certain Items~~(a)~~	—		11		(11)		(100)	%	Certain Items~~(a)~~	—		—		—		—	%
General and administrative and corporate charges~~(b)~~(a)	General and administrative and corporate charges~~(b)~~(a)	$	(167)	$	(139)	$	(28)	(20)	%	General and administrative and corporate charges~~(b)~~(a)	$	(144)	$	(150)	$	6	4	%

Interest, net (GAAP)	Interest, net (GAAP)	$	(368)	$	(383)	$	15	4	%	Interest, net (GAAP)	$	(355)	$	(377)	$	22	6	%
Certain Items~~(c)~~(b)	Certain Items~~(c)~~(b)	(8)		(8)		—		—	%	Certain Items~~(c)~~(b)	(17)		(3)		(14)		(467)	%
Interest, net~~(b)~~(a)	Interest, net~~(b)~~(a)	$	(376)	$	(391)	$	15	4	%	Interest, net~~(b)~~(a)	$	(372)	$	(380)	$	8	2	%

Net income attributable to noncontrolling interests (GAAP)	Net income attributable to noncontrolling interests (GAAP)	$	(16)	$	(17)	$	1	6	%	Net income attributable to noncontrolling interests (GAAP)	$	(18)	$	(17)	$	(1)	(6)	%
Certain Items~~(d)~~(c)	Certain Items~~(d)~~(c)	—		—		—		—	%	Certain Items~~(d)~~(c)	—		—		—		—	%
Net income attributable to noncontrolling interests~~(b)~~(a)	Net income attributable to noncontrolling interests~~(b)~~(a)	$	(16)	$	(17)	$	1	6	%	Net income attributable to noncontrolling interests~~(b)~~(a)	$	(18)	$	(17)	$	(1)	(6)	%

Nine Months Ended September 30, Earnings
increase/(decrease)
2021 2020
(In millions, except percentages)
DD&A (GAAP) $ (1,595) $ (1,636) $ 41 3 %
General and administrative (GAAP) $ (490) $ (461) $ (29) (6) %
Corporate benefit (charges) 25 (11) 36 327 %
Certain Items(a) — 36 (36) (100) %
General and administrative and corporate charges(b) $ (465) $ (436) $ (29) (7) %
Interest, net (GAAP) $ (1,122) $ (1,214) $ 92 8 %
Certain Items(c) (17) (8) (9) (113) %
Interest, net(b) $ (1,139) $ (1,222) $ 83 7 %
Net income attributable to noncontrolling interests (GAAP) $ (49) $ (45) $ (4) (9) %
Certain Items(d) — — — — %
Net income attributable to noncontrolling interests(b) $ (49) $ (45) $ (4) (9) %


	Six Months Ended June 30,				Earnings increase/(decrease)
	2022		2021
	(In millions, except percentages)
DD&A (GAAP)	$	(1,081)	$	(1,069)	$	(12)	(1)	%

General and administrative (GAAP)	$	(308)	$	(316)	$	8	3	%
Corporate benefit	19		18		1		6	%
Certain Items	—		—		—		—	%
General and administrative and corporate charges(a)	$	(289)	$	(298)	$	9	3	%

Interest, net (GAAP)	$	(688)	$	(754)	$	66	9	%
Certain Items(b)	(61)		(9)		(52)		(578)	%
Interest, net(a)	$	(749)	$	(763)	$	14	2	%






Net income attributable to noncontrolling interests (GAAP)	$	(35)	$	(33)	$	(2)	(6)	%
Certain Items(c)	—		—		—		—	%
Net income attributable to noncontrolling interests(a)	$	(35)	$	(33)	$	(2)	(6)	%

Certain items

(a)Three and nine month 2020 amounts both include an increase in expense of $11 million related to costs incurred associated with COVID-19 mitigation. Nine month 2020 amount also includes an increase in expense of $23 million associated with the non-cash fair value adjustment of and the dividend accrual prior to the sale of our investment in Pembina common stock.

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

~~(c)~~(b)Three and ~~nine~~six month ~~2021~~2022 amounts include decreases in interest expense of $7$14 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine month 2020 amounts include (i) decreases in interest expense of $5 million and $17 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions and (ii) a decrease in expense of $3 million and an increase in expense of $11$54 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 LIBOR interest rate swaps which are not designated as accounting hedges and $3 million and $7 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and six month 2021 amounts include decreases of $4 million and $8 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions.

~~(d)~~(c)Three and ~~nine months ended September 30,~~six month 2021 ~~and 2020~~ amounts each include less than $1 million of noncontrolling interests associated with Certain Items.

General and administrative expenses and corporate charges adjusted for Certain Items for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 when compared with the respective prior year periods ~~increased $28~~decreased $6 million and ~~$29~~$9 million, respectively, primarily due to ~~lower~~higher capitalized costs of ~~$18~~$12 million and ~~$41~~$21 million, respectively, reflecting ~~reduced~~higher capital spending primarily by our Natural Gas Pipelines business segment, non-recurring cost savings realized in the 2020 period as a result of the global pandemic of $10 million and $17 million, respectively, and higher benefit-related costs of $10 million and $16 million, respectively, partially offset by ~~$12~~$6 million and ~~$36~~$11 million, respectively, of ~~cost savings in the 2021 period associated with organizational efficiency efforts,~~higher labor, travel and ~~lower pension costs of $4 million and $14 million, respectively.~~legal 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 for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 when compared with the respective prior year periods decreased ~~$15~~$8 million and ~~$83~~$14 million, respectively, primarily due to lower long-term ~~debt balances, lower LIBOR~~average interest rates and ~~lower~~ long-term ~~interest rates,~~debt balances, partially offset by ~~lower capitalized interest.~~higher short-term 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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, approximately ~~15%~~9% 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. ~~The percentage at September 30, 2021 includes our variable-to-fixed interest rate derivative contracts not designated as hedging instruments which hedge our exposure through 2021.~~ For more information on our interest rate swaps, see Note 6 5 “Risk Management—~~“Risk Management—~~Interest Rate Risk ~~Management”~~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 ~~September~~June 30, ~~2021~~2022 was approximately ~~$134~~$184 million as compared with ~~$140~~$237 million of ~~expense~~tax benefit for the same period of ~~2020.~~2021. The $6$421 million ~~decrease~~increase in tax expense ~~was~~is due primarily to ~~a slightly lower 2021 effective tax rate caused by multiple factors.~~federal and state taxes on higher pre-tax book income in the current year.

Our tax expense for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 was approximately ~~$248~~$378 million as compared with ~~$304~~$114 million ~~of expense~~ for the same period of ~~2020.~~2021. The ~~$56~~$264 million ~~decrease~~increase in tax expense was due primarily to ~~(i) the prior year disallowance of a tax benefit for the non-tax deductible goodwill impairment, (ii)~~federal and state taxes on higher ~~dividend-received deductions~~pre-tax book income in ~~2021, and (iii)~~ the current year and the release of the valuation allowance on our investment in NGPL Holdings ~~partially offset by federal and state taxes on higher pre-tax book income~~ in ~~2021 and~~ the ~~refund of alternative minimum tax sequestration credits in 2020.~~prior year.

Liquidity and Capital Resources

General

As of ~~September~~June 30, ~~2021,~~2022, we had ~~$102~~$100 million of “Cash and cash equivalents,” a decrease of ~~$1,082~~$1,040 million from December 31, ~~2020. We used $1.2 billion of cash on hand to complete the acquisition on July 9, 2021 of subsidiaries of Stagecoach.~~2021. Additionally, as of ~~September~~June 30, ~~2021,~~2022, we had borrowing capacity of approximately ~~$3.8~~$3.0 billion under our credit 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 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 ~~$4,440~~$2,648 million and ~~$3,282~~$3,311 million in the first ~~nine~~six 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; however, we may access the debt capital markets from time to time to refinance our maturing long-term ~~debt.~~debt and finance incremental investments, if any.

Our board of directors declared a quarterly dividend of ~~$0.27~~$0.2775 per share for the ~~third~~second quarter of ~~2021,~~2022, consistent with the dividend declared for the previous quarter. ~~We expect to fully fund our dividend payments as well as our discretionary spending for 2021 without funding from the capital 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~~after discount and issuance costs.

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

On ~~August 20, 2021,~~June 1, 2022, we ~~entered into a new $3.5~~repaid $1 billion ~~revolving credit facility (the “New Credit Facility”)~~of our 3.95% senior notes, due August 2026 and amended our existing facility (the “Existing Facility”) to reduce the borrowing capacity to $500 million and terminate the letter of credit commitments and the swing line capacity thereunder (together, the “Credit Facilities”).September 1, 2022 using short-term borrowings.

Short-term Liquidity

As of ~~September~~June 30, ~~2021,~~2022, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of ~~Credit Facilities~~credit facilities and associated commercial paper program. The loan commitments under our ~~Credit Facilities~~credit facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our ~~Credit Facilities~~credit facilities and letters of credit reduce borrowings allowed under our ~~New Credit Facility.~~$3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our ~~Credit Facilities~~credit 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 Facilities.~~

As of ~~September~~June 30, ~~2021,~~2022, our ~~$2,822~~$2,970 million of short-term debt consisted primarily of senior notes that mature in the next twelve ~~months.~~months and outstanding commercial paper borrowings. 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 ~~$3,139~~$3,284 million and ~~$1,871~~$1,992 million as of ~~September~~June 30, ~~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 ~~$1,268~~$1,292 million unfavorable change from year-end ~~2020~~2021 was primarily due to (i) a ~~$1,082~~$1,040 million decrease in cash and cash equivalents ~~primarily resulting from utilizing~~which includes $1,190 million related to repayments of senior notes that matured in the first quarter of 2022 using cash on ~~hand to acquire subsidiaries of Stagecoach;~~hand; (ii) a net unfavorable short-term fair value adjustment of $253 million on derivative contract assets and liabilities in 2021; (iii) an increase in accounts payable, net of change in accounts receivable, of $212 million; (iv) a $160$936 million increase in commercial paper borrowings; and ~~(iv) an increase~~(iii) net unfavorable short-term fair value adjustments on derivative contracts of ~~$104~~$422 million; partially offset by (i) a $613 million decrease in senior notes that mature in the next twelve ~~months, partially offset by (i)~~months; (ii) a ~~$193~~$310 million ~~decrease in accrued interest; (ii) an~~ increase ~~of $152 million~~ in restricted deposits primarily related to ~~margin calls in~~ our derivative ~~activities;~~activity; (iii) a ~~$109~~$128 million increase in inventories, primarily ~~storage gas and product inventories; and~~products inventory; (iv) a ~~$61~~$62 million decrease in accrued interest; and (v) a $58 million decrease in accrued contingencies. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

~~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 September 30, 2021 and December 31, 2020, was $2 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 ~~nine~~six months ended ~~September~~June 30, ~~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:


		Nine Months Ended September 30, 2021		2021 Remaining		Total 2021			Six Months Ended June 30, 2022		2022 Remaining		Total 2022
		(In millions)							(In millions)
Sustaining capital expenditures(a)(b)	Sustaining capital expenditures(a)(b)	$	558	$	300	$	858	Sustaining capital expenditures(a)(b)	$	338	$	592	$	930
Discretionary capital investments(b)(c)(d)	Discretionary capital investments(b)(c)(d)	2,049		256		2,305		Discretionary capital investments(b)(c)(d)	458		1,397		1,855

(a)~~Nine~~Six months ended ~~September~~June 30, ~~2021, 2021~~2022, 2022 Remaining, and Total ~~2021~~2022 amounts include ~~$76~~$47 million, ~~$31~~$81 million, and ~~$107~~$128 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Results of Operations—Non-GAAP Financial Measures—Supplemental Information.”

(b)~~Nine~~Six months ended ~~September~~June 30, ~~2021~~2022 amount excludes $6$53 million due to ~~increases~~decreases in accrued capital expenditures and contractor retainage and net changes in other.

(c)~~Nine~~Six months ended ~~September~~June 30, ~~2021~~2022 amount includes ~~$135~~$23 million of our contributions to certain unconsolidated joint ventures for capital investments. Both ~~Nine months ended September 30, 2021~~2022 Remaining and Total ~~2021~~2022 amounts ~~also~~ include ~~$1,508~~$358 million for our ~~acquisitions~~acquisition of ~~Stagecoach and Kinetrex.~~Mas CanAm, LLC.

(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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020~~2021 were ~~$201~~$392 million and ~~$141~~$209 million, respectively. The increase of ~~$60~~$183 million was primarily driven by an overall increase of capital ~~commitments related to our Terminals business segment.~~commitments.

Cash Flows

Operating Activities

Cash provided by operating activities ~~increased $1,158~~decreased $663 million in the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily due to:

•a ~~$1,206~~$617 million ~~increase~~decrease in cash after adjusting the ~~$1,639~~$652 million increase in net income by ~~$433~~$1,269 million for the combined effects of the period-to-period net changes in non-cash ~~items including~~items. This overall cash decrease primarily resulted from the ~~following: (i) loss from impairments and divestitures, net~~benefit recognized in the 2021 period for largely nonrecurring earnings related to the February 2021 winter storm (see discussion above in “—“—Results of ~~Operations~~”Operations”); ~~(ii) gain from the sale of a partial interest in our equity investment in NGPL Holdings (see discussion above in “~~and~~—General and Basis of Presentation”); (iii) DD&A expenses (including amortization of excess cost of equity investments); (iv) deferred~~

~~income taxes; and (v) earnings from equity investments (including a non-cash write-down of a related party note receivable from Ruby); partially offset by,~~

•a ~~$48~~$46 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 payments for litigation matters in the 2021 period which was partially offset by a net increase in working capital items and higher distributions from equity investment earnings in the 2021 period compared to the 2020 period.

Investing Activities

Cash used in investing activities increased ~~$1,135~~$561 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily attributable to:

•a $1,502 million increase in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by $1,197 million and $311 million of net cash used for the Stagecoach and the Kinetrex acquisitions, respectively, in the 2021 period. See Note 2 “~~Acquisitions” to our consolidated financial statements for further information regarding these transactions; and~~

•~~a $490~~$409 million decrease in ~~cash~~proceeds from sales of investments primarily due to ~~$412~~$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 $234 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 3 “Losses and Gains on Impairments, Divestitures 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 ~~$457~~combined $62 million ~~decrease in capital expenditures reflecting an overall reduction of expansion capital projects in the 2021 period over the comparative 2020 period; and~~

•~~a $329 million decrease~~increase in cash ~~used for~~related to distributions received from equity investments in excess of cumulative earnings and lower contributions to equity investees ~~driven primarily by lower contributions to Permian Highway Pipeline LLC and SNG~~ in the ~~2021~~2022 period compared with the ~~2020~~2021 period.

Financing Activities

Cash used in financing activities increased ~~$1,446~~$266 million for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 compared to the respective ~~2020~~2021 period primarily attributable to:

•$173 million cash used in repurchasing shares under our share buy-back program in the 2022 period; and

•a ~~$1,403~~$58 million net increase in cash used related to debt activity as a result of higher net debt payments in the ~~2021~~2022 period compared to 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

June 30, ~~2021~~2022

~~0.27~~0.2775

July ~~21, 2021~~20, 2022

August ~~2, 2021~~1, 2022

August ~~16, 2021~~

~~September 30, 2021~~

~~0.27~~

~~October 20, 2021~~

~~November 1, 2021~~

~~November~~ 15, ~~2021~~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 Part I, 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.

5553

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 ~~September~~June 30, ~~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 ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020,~~2021, the Obligated Group had ~~$30,994~~$30,312 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	September 30, 2021		December 31, 2020		Summarized Combined Balance Sheet Information	June 30, 2022		December 31, 2021
		(In millions)					(In millions)

Current assets	Current assets	$	2,412	$	2,957	Current assets	$	3,289	$	3,556
Current assets - affiliates	Current assets - affiliates	1,118		1,151		Current assets - affiliates	1,359		1,233
Noncurrent assets	Noncurrent assets	62,129		61,783		Noncurrent assets	60,978		61,754
Noncurrent assets - affiliates	Noncurrent assets - affiliates	507		616		Noncurrent assets - affiliates	509		508
Total Assets	Total Assets	$	66,166	$	66,507	Total Assets	$	66,135	$	67,051

Current liabilities	Current liabilities	$	5,390	$	4,528	Current liabilities	$	6,547	$	5,413
Current liabilities - affiliates	Current liabilities - affiliates	1,269		1,209		Current liabilities - affiliates	1,446		1,332
Noncurrent liabilities	Noncurrent liabilities	31,803		33,907		Noncurrent liabilities	30,491		32,310
Noncurrent liabilities - affiliates	Noncurrent liabilities - affiliates	1,006		1,078		Noncurrent liabilities - affiliates	1,046		1,047
Total Liabilities	Total Liabilities	39,468		40,722		Total Liabilities	39,530		40,102
Redeemable noncontrolling interest		661		728

Kinder Morgan, Inc.’s stockholders’ equity	Kinder Morgan, Inc.’s stockholders’ equity	26,037		25,057		Kinder Morgan, Inc.’s stockholders’ equity	26,605		26,949
Total Liabilities, Redeemable Noncontrolling Interest and Stockholders’ Equity		$	66,166	$	66,507
Total Liabilities and Stockholders’ Equity						Total Liabilities and Stockholders’ Equity	$	66,135	$	67,051


Summarized Combined Income Statement Information	Summarized Combined Income Statement Information	Three Months Ended September 30, 2021		Nine Months Ended September 30, 2021		Summarized Combined Income Statement Information	Three Months Ended June 30, 2022		Six Months Ended June 30, 2022
		(In millions)					(In millions)
Revenues	Revenues	$	3,472	$	11,211	Revenues	$	4,756	$	8,733
Operating income	Operating income	699		1,697		Operating income	889		1,795
Net income	Net income	373		937		Net income	537		1,105

5654

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 Part II, Item 7A in our ~~2020~~2021 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 6 ~~“Risk~~5 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of ~~September~~June 30, ~~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 ~~September~~June 30, ~~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 109 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 Part I, Item 1, Note ~~6 “Risk Management~~”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 Stock


Settlement 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
April 1 to April 30, 2022	1,336,132	$	18.45	1,336,132	$	1,399,723,550
May 1 to May 31, 2022	1,563,243	18.19		1,563,243	1,371,291,985
June 1 to June 30, 2022	7,037,626	16.98		7,037,626	1,251,805,298

Total	9,937,001	$	17.37	9,937,001	$	1,251,805,298

(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 includes any commission or other costs to repurchase shares.

Subsequent to June 30, 2022 and through July 21, 2022, we repurchased 6 million of our shares for $102 million at an average price of $16.63 per share.

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 ~~September~~June 30, ~~2021.~~2022.

Item 5. Other Information.

Effective October 20, 2021, our board of directors approved the Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (the “Amended Director Plan”), which amends and restates the previous Kinder Morgan, Inc. Amended and Restated Stock Compensation Plan for Non-Employee Directors dated January 1, 2015, asNone.

~~amended (the “Previous Plan”). The Amended Director Plan amends and restates the Previous Plan to increase the number of shares available for issuance under the Amended Director Plan.~~

The Amended Director Plan is administered by our Compensation Committee, and our board of directors has sole discretion to terminate the plan at any time. The Amended Director Plan recognizes that the compensation to be paid to each non-employee director is fixed by our board of directors, and that the compensation is payable in cash. Under the plan, in lieu of receiving some or all of the compensation in cash, non-employee directors, referred to as “eligible directors,” may elect to receive shares of our common stock. Each election generally will be at or around the first board of directors meeting in January of each year and will be effective for the entire calendar year. An eligible director may make a new election each year. The total number of shares of common stock authorized under the plan is 1,190,000.

Each annual election to receive shares of common stock will be evidenced by an agreement between us and the electing director that will contain the terms and conditions of such election. Shares issued under the plan pursuant to an election may be subject to forfeiture restrictions that lapse on the earlier of the director’s death or the date set forth in the agreement, which will be no later than the end of the calendar year to which the cash compensation relates. Until the forfeiture restrictions lapse, shares issued under the plan may not be sold, assigned, transferred, exchanged or pledged by an eligible director. In the event a director’s service as a director is terminated prior to the lapse of the forfeiture restrictions for any reason other than death or the director’s failure to be elected as a director at a stockholders meeting at which the director is considered for election, the director will, for no consideration, forfeit to us all shares then subject to the restrictions. If, prior to the lapse of the restrictions, the director is not elected as a director at a stockholders meeting at which the director is considered for election, the restrictions will lapse with respect to 50% of the director’s shares then subject to such restrictions, and the director will, for no consideration, forfeit to us the remaining shares.

The number of shares to be issued to an eligible director electing to receive any portion of annual compensation in the form of shares will equal the dollar amount elected to be received in the form of shares, divided by the closing price of our common stock on the NYSE on the day the cash compensation is awarded or, if the NYSE is not open for trading on such day, the most recent trading day (the fair market value), rounded up to the nearest ten shares. An eligible director electing to receive any portion of annual compensation in the form of shares will receive cash equal to the difference between:

•~~the total cash compensation awarded to such director and~~

•~~the number of shares to be issued to such director with respect to the amount determined by the director, multiplied by the fair market value of a share.~~

This cash payment will be payable in four equal installments, on or before March 31, June 30, September 30 and December 31 of the calendar year in which such cash compensation is awarded; provided that the installment payments will be adjusted to include dividend equivalent payments with respect to the shares during the period in which the shares are subject to forfeiture restrictions.

The foregoing is a summary of the principal provisions of the Amended Director Plan. The summary does not purport to be complete and is qualified in its entirety by reference to the full text of the Amended Director Plan, which is filed as Exhibit 10.4.

5856

Item 6. Exhibits.

~~Exhibit~~

~~NumberDescription~~


Exhibit Number		Description
10.1		Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of ~~September 30, 2021.~~

~~10.2~~	*	~~Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc.~~June 3 0 , as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.1 to KMI’s Current Report on Form 8-K filed August 25, 2021 (File No. 001-35081)).

~~10.3~~	*	First Amendment to Revolving Credit Agreement, dated August 20, 2021 among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto (filed as Exhibit 10.2 to KMI's Current Report on Form 8-K filed August 25, 2021 (File 001-35081)).

~~10.4~~		~~Second Amended and Restated Stock Compensation Plan for Non-Employee Directors.~~

~~10.5~~		~~2021 Form of Non-Employee Director Stock Compensation Agreement.~~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 for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020;~~2021; (ii) our Consolidated Statements of Comprehensive Income (Loss) for the three and ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020;~~2021; (iii) our Consolidated Balance Sheets as of ~~September~~June 30, ~~2021~~2022 and December 31, ~~2020;~~2021; (iv) our Consolidated Statements of Cash Flows for the ~~nine~~six months ended ~~September~~June 30, ~~2021~~2022 and ~~2020;~~2021; (v) our Consolidated Statements of Stockholders’ Equity for the three and ~~nine~~six months ended ~~September~~June 30, ~~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.

~~_______~~

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

5957

SIGNATURE

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


			KINDER MORGAN, INC.
						Registrant

Date:

~~October~~July 22, ~~2021~~2022

By:

/s/ David P. Michels

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

6058


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Deferred charges & other		Goodwill		Current liabilities		Long-term liabilities
			(In millions)
(1)	8/21	Kinetrex Energy	$	318	$	17	$	49	$	262	$	64	$	(6)	$	(68)
(2)	7/21	Stagecoach Gas Services LLC	1,228		52		1,041		23		118		(6)		—


	Natural Gas Pipelines Regulated		Natural Gas Pipelines Non-Regulated		CO2		Products Pipelines		Products Pipelines Terminals		Terminals		Energy Transition Ventures		Total
	(In millions)


Goodwill as of December 31, 2020	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	—	$	19,851
Acquisitions	118		—		—		—		—		—		64		182


Goodwill as of September 30, 2021	$	14,367	$	2,343	$	928	$	1,378	$	151	$	802	$	64	$	20,033


	Nine Months Ended September 30, 2020
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,479	$	215	$	563	$	1	$	(2)	$	3,256
Fee-based services	523		670		307		31		1		1,532
Total services	3,002		885��		870		32		(1)		4,788
Commodity sales
Natural gas sales	1,385		—		—		1		(5)		1,381
Product sales	396		255		11		546		(22)		1,186

Total commodity sales	1,781		255		11		547		(27)		2,567
Total revenues from contracts with customers	4,783		1,140		881		579		(28)		7,355
Other revenues(c)
Leasing services(d)	346		126		404		34		—		910
Derivatives adjustments on commodity sales	35		—		—		173		—		208
Other	91		16		—		6		(1)		112
Total other revenues	472		142		404		213		(1)		1,230
Total revenues	$	5,255	$	1,282	$	1,285	$	792	$	(29)	$	8,585


	Three Months Ended September 30,
	2021						2020
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,069	$	21	$	1,090	$	1,091	$	(9)	$	1,082	$	8
Products Pipelines	279		1		280		223		46		269		11
Terminals	216		17		233		246		—		246		(13)
CO2	163		(9)		154		156		(2)		154		—

Total Segment EBDA(a)	1,727		30		1,757		1,716		35		1,751		6
DD&A and amortization of excess cost of equity investments	(547)		—		(547)		(571)		—		(571)		24
General and administrative and corporate charges(a)	(167)		—		(167)		(150)		11		(139)		(28)
Interest, net(a)	(368)		(8)		(376)		(383)		(8)		(391)		15
Income before income taxes	645		22		667		612		38		650		17
Income tax expense(b)	(134)		(12)		(146)		(140)		(8)		(148)		2
Net income	511		10		521		472		30		502		19
Net income attributable to noncontrolling interests(a)	(16)		—		(16)		(17)		—		(17)		1

Net income attributable to Kinder Morgan, Inc.	$	495	$	10	$	505	$	455	$	30	$	485	$	20