UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

F O R M 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended ~~September 30, 2022~~March 31, 2023

☐ 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
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~~April 20, ~~2022,~~2023, the registrant had ~~2,247,742,071~~2,241,213,694 shares of Class P 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 Income - Three ~~and~~ ~~Nine~~Months Ended ~~September~~ ~~30, 2022~~March 31, 2023 and ~~202~~20221		4
	Consolidated Statements of Comprehensive Income - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 202~~1		5
	Consolidated Balance Sheets - as of ~~September~~ ~~30, 2022~~March 31, 2023 and December 31, ~~202~~20221		6
	Consolidated Statements of Cash Flows - ~~Nine~~Three Months Ended ~~September~~ ~~30, 2022~~March 31, 2023 and ~~202~~20221		7
	Consolidated Statements of Stockholders’ Equity - Three ~~and Nine~~ Months Ended ~~September 30,~~March 31, 2023 and 2022 ~~and 202~~1		9
	Notes to Consolidated Financial Statements		10
	Note 1 .	General	10
	Note 2.2 .	~~Acquisitions and Divestitures~~Losses on Impairments	11
	Note 3 .	~~Losses on Impairments and Other Write-downs~~Debt	1312
	Note 4 .	~~Debt~~	14
	~~Note~~ 5 .	Stockholders’ Equity	1513
	Note 5 .	Risk Management	14
	Note 6 .	~~Risk Management~~Revenue Recognition	1619
	Note 7 .	~~Revenue Recognition~~Reportable Segments	21
	Note 8 .	~~Reportable Segments~~Income Taxes	2422
	Note 9 .	~~Income Taxes~~	25
	~~Note~~ 10 .	Litigation and Environmental	2622
	Note 1 10 .	Recent Accounting Pronouncements	3026
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		3227
	Results of Operations		3227
	Overview		3227
	Consolidated Earnings Results ~~(GAAP)~~		3530
	Non-GAAP Financial Measures		3832
	Segment Earnings Results		41
	~~DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests~~		49
	~~Income Taxes~~		5135
	Liquidity and Capital Resources		5141
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		5546
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		5647
Item 4.	Controls and Procedures		5647
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		5647
Item 1A.	Risk Factors		5647
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		5648
Item 3.	Defaults Upon Senior Securities		5648
Item 4.	Mine Safety Disclosures		5748
Item 5.	Other Information		5749
Item 6.	Exhibits		5850
	Signature		5951

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

FERC

Federal Energy Regulatory Commission

Bbl

barrels

GAAP

U.S. Generally Accepted Accounting Principles

BBtu

billion British Thermal Units

LLC

limited liability company

Bcf

billion cubic feet

LIBOR

London Interbank Offered Rate

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

MBbl

thousand barrels

MMBbl

million barrels

CO2

carbon dioxide or our CO2 business segment

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

PHMSA

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

RNG

Renewable natural gas

ROU

Right-of-Use

~~U.S.~~

~~United States of America~~

EPA

U.S. Environmental Protection Agency

~~WTI~~U.S.

~~West Texas Intermediate~~United States of America

FASB

Financial Accounting Standards Board

WTI

West Texas Intermediate

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate sales, income or cash flow, service debt or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: the long-term demand for our assets and services, our anticipated dividends and capital projects, including expected completion timing and benefits of those projects.

Important factors that could cause actual results to differ materially from those expressed in or implied by the forward-looking statements in this report include: the 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” and Part II, Item 1A. “Risk Factors” 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, ~~2021~~2022 (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 INCOME

(In millions, except per share amounts, unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Revenues	Revenues									Revenues
Services	Services	$	2,028	$	1,928	$	6,089	$	5,734	Services		$	2,069	$	2,050
Commodity sales	Commodity sales	3,108		1,868		8,416		6,343		Commodity sales		1,785		2,208
Other	Other	41		28		116		108		Other		34		35
Total Revenues	Total Revenues	5,177		3,824		14,621		12,185		Total Revenues		3,888		4,293

Operating Costs, Expenses and Other	Operating Costs, Expenses and Other									Operating Costs, Expenses and Other
Costs of sales		2,717		1,559		7,294		4,504
Costs of sales (exclusive of items shown separately below)										Costs of sales (exclusive of items shown separately below)		1,215		1,894
Operations and maintenance	Operations and maintenance	712		614		1,960		1,710		Operations and maintenance		639		585
Depreciation, depletion and amortization	Depreciation, depletion and amortization	551		526		1,632		1,595		Depreciation, depletion and amortization		565		538
General and administrative	General and administrative	162		174		470		490		General and administrative		166		156
Taxes, other than income taxes	Taxes, other than income taxes	113		106		340		324		Taxes, other than income taxes		110		111

(Gain) loss on divestitures and impairments, net		(9)		4		(30)		1,602
Gain on divestitures and impairments, net										Gain on divestitures and impairments, net		—		(10)
Other income, net	Other income, net	—		(3)		(6)		(6)		Other income, net		(1)		(5)
Total Operating Costs, Expenses and Other	Total Operating Costs, Expenses and Other	4,246		2,980		11,660		10,219		Total Operating Costs, Expenses and Other		2,694		3,269

Operating Income	Operating Income	931		844		2,961		1,966		Operating Income		1,194		1,024

Other Income (Expense)	Other Income (Expense)									Other Income (Expense)
Earnings from equity investments	Earnings from equity investments	195		169		564		392		Earnings from equity investments		165		187

Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	(19)		(21)		(57)		(56)		Amortization of excess cost of equity investments		(17)		(19)
Interest, net	Interest, net	(399)		(368)		(1,087)		(1,122)		Interest, net		(445)		(333)
Other, net (Note 2)		21		21		63		264
Other, net										Other, net		2		19
Total Other Expense	Total Other Expense	(202)		(199)		(517)		(522)		Total Other Expense		(295)		(146)

Income Before Income Taxes	Income Before Income Taxes	729		645		2,444		1,444		Income Before Income Taxes		899		878

Income Tax Expense	Income Tax Expense	(134)		(134)		(512)		(248)		Income Tax Expense		(196)		(194)

Net Income	Net Income	595		511		1,932		1,196		Net Income		703		684

Net Income Attributable to Noncontrolling Interests	Net Income Attributable to Noncontrolling Interests	(19)		(16)		(54)		(49)		Net Income Attributable to Noncontrolling Interests		(24)		(17)

Net Income Attributable to Kinder Morgan, Inc.	Net Income Attributable to Kinder Morgan, Inc.	$	576	$	495	$	1,878	$	1,147	Net Income Attributable to Kinder Morgan, Inc.		$	679	$	667

Class P Common Stock	Class P Common Stock									Class P Common Stock
Basic and Diluted Earnings Per Share	Basic and Diluted Earnings Per Share	$	0.25	$	0.22	$	0.83	$	0.50	Basic and Diluted Earnings Per Share		$	0.30	$	0.29

Basic and Diluted Weighted Average Shares Outstanding	Basic and Diluted Weighted Average Shares Outstanding	2,253		2,267		2,262		2,265		Basic and Diluted Weighted Average Shares Outstanding		2,247		2,267

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions, unaudited)


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
Net income	Net income	$	595	$	511	$	1,932	$	1,196	Net income		$	703	$	684
Other comprehensive income (loss), net of tax	Other comprehensive income (loss), net of tax									Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(40), $41, $109 and $135, respectively)		123		(131)		(366)		(444)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $(29), $(28), $(118), and $(55), respectively)		104		92		396		181
Net unrealized gain (loss) from derivative instruments (net of taxes of $(32) and $125, respectively)										Net unrealized gain (loss) from derivative instruments (net of taxes of $(32) and $125, respectively)		106		(411)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $15 and $(41), respectively)										Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $15 and $(41), respectively)		(49)		135

Benefit plan adjustments (net of taxes of $(1), $(2), $(6) and $(7), respectively)		2		6		18		28
Benefit plan adjustments (net of taxes of $(1) and $(4), respectively)										Benefit plan adjustments (net of taxes of $(1) and $(4), respectively)		4		13
Total other comprehensive income (loss)	Total other comprehensive income (loss)	229		(33)		48		(235)		Total other comprehensive income (loss)		61		(263)

Comprehensive income	Comprehensive income	824		478		1,980		961		Comprehensive income		764		421
Comprehensive income attributable to noncontrolling interests	Comprehensive income attributable to noncontrolling interests	(19)		(16)		(54)		(49)		Comprehensive income attributable to noncontrolling interests		(24)		(17)
Comprehensive income attributable to KMI	Comprehensive income attributable to KMI	$	805	$	462	$	1,926	$	912	Comprehensive income attributable to KMI		$	740	$	404

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, 2022		December 31, 2021			March 31, 2023		December 31, 2022
ASSETS	ASSETS					ASSETS
Current Assets	Current Assets					Current Assets
Cash and cash equivalents	Cash and cash equivalents	$	483	$	1,140	Cash and cash equivalents	$	416	$	745
Restricted deposits	Restricted deposits	240		7		Restricted deposits	22		49
Accounts receivable	Accounts receivable	1,873		1,611		Accounts receivable	1,321		1,840
Fair value of derivative contracts	Fair value of derivative contracts	194		220		Fair value of derivative contracts	164		231
Inventories	Inventories	715		562		Inventories	589		634

Other current assets	Other current assets	314		289		Other current assets	184		304
Total current assets	Total current assets	3,819		3,829		Total current assets	2,696		3,803

Property, plant and equipment, net	Property, plant and equipment, net	35,534		35,653		Property, plant and equipment, net	35,639		35,599
Investments	Investments	7,465		7,578		Investments	7,616		7,653
Goodwill	Goodwill	19,965		19,914		Goodwill	19,965		19,965
Other intangibles, net	Other intangibles, net	1,875		1,678		Other intangibles, net	1,743		1,809
Deferred income taxes		—		115

Deferred charges and other assets	Deferred charges and other assets	1,334		1,649		Deferred charges and other assets	1,272		1,249
Total Assets	Total Assets	$	69,992	$	70,416	Total Assets	$	68,931	$	70,078

LIABILITIES 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	$	2,634	$	2,646	Current portion of debt	$	2,160	$	3,385
Accounts payable	Accounts payable	1,579		1,259		Accounts payable	1,087		1,444

Accrued interest	Accrued interest	327		504		Accrued interest	351		515
Accrued taxes		297		270

Fair value of derivative contracts	Fair value of derivative contracts	501		178		Fair value of derivative contracts	344		465

Other current liabilities	Other current liabilities	810		964		Other current liabilities	833		1,121
Total current liabilities	Total current liabilities	6,148		5,821		Total current liabilities	4,775		6,930

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	29,000		29,772		Outstanding	29,139		28,288

Debt fair value adjustments	Debt fair value adjustments	107		902		Debt fair value adjustments	207		115
Total long-term debt	Total long-term debt	29,107		30,674		Total long-term debt	29,346		28,403
Deferred income taxes	Deferred income taxes	442		—		Deferred income taxes	831		623

Other long-term liabilities and deferred credits	Other long-term liabilities and deferred credits	2,160		2,000		Other long-term liabilities and deferred credits	1,865		2,008

Total long-term liabilities and deferred credits	Total long-term liabilities and deferred credits	31,709		32,674		Total long-term liabilities and deferred credits	32,042		31,034
Total Liabilities	Total Liabilities	37,857		38,495		Total Liabilities	36,817		37,964
Commitments and contingencies (Notes 4 and 10)
Commitments and contingencies (Notes 3 and 9)						Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity	Stockholders’ Equity					Stockholders’ Equity

Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,249,727,830 and 2,267,391,527 shares, respectively, issued and outstanding		23		23
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,241,158,000 and 2,247,681,626 shares, respectively, issued and outstanding						Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,241,158,000 and 2,247,681,626 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	Additional paid-in capital	41,689		41,806		Additional paid-in capital	41,575		41,673
Accumulated deficit	Accumulated deficit	(10,593)		(10,595)		Accumulated deficit	(10,499)		(10,551)
Accumulated other comprehensive loss	Accumulated other comprehensive loss	(363)		(411)		Accumulated other comprehensive loss	(341)		(402)
Total Kinder Morgan, Inc.’s stockholders’ equity	Total Kinder Morgan, Inc.’s stockholders’ equity	30,756		30,823		Total Kinder Morgan, Inc.’s stockholders’ equity	30,757		30,742
Noncontrolling interests	Noncontrolling interests	1,379		1,098		Noncontrolling interests	1,357		1,372
Total Stockholders’ Equity	Total Stockholders’ Equity	32,135		31,921		Total Stockholders’ Equity	32,114		32,114
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	69,992	$	70,416	Total Liabilities and Stockholders’ Equity	$	68,931	$	70,078

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


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

		Nine Months Ended September 30,					Three Months Ended March 31,
		2022		2021			2023		2022
Cash Flows From Operating Activities	Cash Flows From Operating Activities					Cash Flows From Operating Activities
Net income	Net income	$	1,932	$	1,196	Net income	$	703	$	684
Adjustments to reconcile net income to net cash provided by operating activities	Adjustments to reconcile net income to net cash provided by operating activities					Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	Depreciation, depletion and amortization	1,632		1,595		Depreciation, depletion and amortization	565		538
Deferred income taxes	Deferred income taxes	499		236		Deferred income taxes	190		190
Amortization of excess cost of equity investments	Amortization of excess cost of equity investments	57		56		Amortization of excess cost of equity investments	17		19

Change in fair market value of derivative contracts		45		60
(Gain) loss on divestitures and impairments, net		(30)		1,602
Gain on sale of interest in equity investment (Note 2)		—		(206)
Change in fair value of derivative contracts						Change in fair value of derivative contracts	(66)		77
Gain on divestitures and impairments, net						Gain on divestitures and impairments, net	—		(10)

Earnings from equity investments	Earnings from equity investments	(564)		(392)		Earnings from equity investments	(165)		(187)
Distributions from equity investment earnings	Distributions from equity investment earnings	548		535		Distributions from equity investment earnings	188		165
Changes in components of working capital	Changes in components of working capital					Changes in components of working capital
Accounts receivable	Accounts receivable	(260)		(119)		Accounts receivable	536		(51)
Inventories	Inventories	(165)		(89)		Inventories	88		(34)
Other current assets	Other current assets	(60)		(90)		Other current assets	93		(14)
Accounts payable	Accounts payable	347		362		Accounts payable	(368)		55
Accrued interest, net of interest rate swaps	Accrued interest, net of interest rate swaps	(160)		(177)		Accrued interest, net of interest rate swaps	(162)		(188)
Accrued taxes		27		15

Other current liabilities	Other current liabilities	2		71		Other current liabilities	(236)		(98)
Rate reparations, refunds and other litigation reserve adjustments	Rate reparations, refunds and other litigation reserve adjustments	(189)		(97)		Rate reparations, refunds and other litigation reserve adjustments	2		(68)
Other, net	Other, net	(98)		(118)		Other, net	(52)		6
Net Cash Provided by Operating Activities	Net Cash Provided by Operating Activities	3,563		4,440		Net Cash Provided by Operating Activities	1,333		1,084

Cash Flows From Investing Activities	Cash Flows From Investing Activities					Cash Flows From Investing Activities

Acquisitions of assets and investments, net of cash acquired (Note 2)		(488)		(1,518)

Capital expenditures	Capital expenditures	(1,144)		(894)		Capital expenditures	(507)		(407)
Proceeds from sales of investments (Note 2)		4		417

Contributions to investments	Contributions to investments	(60)		(36)		Contributions to investments	(45)		(11)
Distributions from equity investments in excess of cumulative earnings	Distributions from equity investments in excess of cumulative earnings	126		121		Distributions from equity investments in excess of cumulative earnings	61		50

Other, net	Other, net	17		(1)		Other, net	(17)		(3)
Net Cash Used in Investing Activities	Net Cash Used in Investing Activities	(1,545)		(1,911)		Net Cash Used in Investing Activities	(508)		(371)

Cash Flows From Financing Activities	Cash Flows From Financing Activities					Cash Flows From Financing Activities
Issuances of debt	Issuances of debt	8,898		4,950		Issuances of debt	2,794		1,588
Payments of debt	Payments of debt	(9,569)		(6,459)		Payments of debt	(3,180)		(2,453)
Debt issue costs	Debt issue costs	(21)		(20)		Debt issue costs	(13)		(4)
Dividends	Dividends	(1,876)		(1,828)		Dividends	(627)		(616)

Repurchases of shares	Repurchases of shares	(333)		—		Repurchases of shares	(113)		(1)

Proceeds from sale of noncontrolling interests (Note 2)		557		—
Contributions from noncontrolling interests		1		4
Distributions to investment partner		—		(67)

Distributions to noncontrolling interests	Distributions to noncontrolling interests	(85)		(14)		Distributions to noncontrolling interests	(39)		(26)
Other, net	Other, net	(14)		(25)		Other, net	(3)		—
Net Cash Used in Financing Activities	Net Cash Used in Financing Activities	(2,442)		(3,459)		Net Cash Used in Financing Activities	(1,181)		(1,512)

Net Decrease in Cash, Cash Equivalents and Restricted Deposits	Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(424)		(930)		Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(356)		(799)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period		1,147		1,209
Cash, Cash Equivalents, and Restricted Deposits, end of period		$	723	$	279
Cash, Cash Equivalents and Restricted Deposits, beginning of period						Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147
Cash, Cash Equivalents and Restricted Deposits, end of period						Cash, Cash Equivalents and Restricted Deposits, end of period	$	438	$	348

Cash and Cash Equivalents, beginning of period		$	1,140	$	1,184
Restricted Deposits, beginning of period		7		25
Cash, Cash Equivalents, and Restricted Deposits, beginning of period		1,147		1,209


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,					Three Months Ended March 31,
		2022		2021			2023		2022
Cash and Cash Equivalents, beginning of period						Cash and Cash Equivalents, beginning of period	$	745	$	1,140
Restricted Deposits, beginning of period						Restricted Deposits, beginning of period	49		7
Cash, Cash Equivalents and Restricted Deposits, beginning of period						Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147

Cash and Cash Equivalents, end of period	Cash and Cash Equivalents, end of period	483		102		Cash and Cash Equivalents, end of period	416		84
Restricted Deposits, end of period	Restricted Deposits, end of period	240		177		Restricted Deposits, end of period	22		264
Cash, Cash Equivalents, and Restricted Deposits, end of period		723		279
Cash, Cash Equivalents and Restricted Deposits, end of period						Cash, Cash Equivalents and Restricted Deposits, end of period	438		348

Net Decrease in Cash, Cash Equivalents and Restricted Deposits	Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(424)	$	(930)	Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(356)	$	(799)

Non-cash Investing and Financing Activities	Non-cash Investing and Financing Activities					Non-cash Investing and Financing Activities
Assets contributed to equity investment						Assets contributed to equity investment	$	16	$	—
ROU assets and operating lease obligations recognized including adjustments	ROU assets and operating lease obligations recognized including adjustments	$	19	$	35	ROU assets and operating lease obligations recognized including adjustments	11		3

Increase in property, plant and equipment from both accruals and contractor retainage	Increase in property, plant and equipment from both accruals and contractor retainage	23		4		Increase in property, plant and equipment from both accruals and contractor retainage	15
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)	1,278		1,313		Cash paid during the period for interest (net of capitalized interest)	617		561
Cash paid during the period for income taxes, net	Cash paid during the period for income taxes, net	12		8		Cash paid during the period for income taxes, net	1		1

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)


		Common stock			Additional paid-in capital				Accumulated deficit		Accumulated other comprehensive loss					Stockholders’ equity attributable to KMI			Non-controlling interests				Total			Common stock				Additional paid-in capital				Accumulated deficit				Accumulated other comprehensive loss				Stockholders’ equity attributable to KMI				Non- controlling interests				Total
		Issued shares	Par value												Issued shares						Par value
Balance at June 30, 2022		2,257	$	23			$	41,654					$	(10,540)				$	(592)			$	30,545			$	1,080	$	31,625
Balance at December 31, 2022																									Balance at December 31, 2022	2,248		$	22			$	41,673			$	(10,551)			$	(402)			$	30,742			$	1,372			$	32,114

Repurchases of shares	Repurchases of shares	(9)			(160)											(160)							(160)		Repurchases of shares	(7)				(113)												(113)								(113)

Restricted shares	Restricted shares	2			5											5							5		Restricted shares					15												15								15
Net income	Net income								576							576			19				595		Net income									679								679				24				703
Dividends																									Dividends									(627)								(627)								(627)
Distributions	Distributions															—			(32)				(32)		Distributions																	—				(39)				(39)
Contributions																—			1				1
Impact of change in ownership interest in subsidiary					190											190			311				501
Dividends									(629)							(629)							(629)

Other comprehensive income	Other comprehensive income										229					229							229		Other comprehensive income													61				61								61
Balance at September 30, 2022		2,250	$	23	$	41,689			$	(10,593)	$	(363)				$	30,756		$	1,379			$	32,135
Balance at March 31, 2023																									Balance at March 31, 2023	2,241		$	22	$	41,575			$	(10,499)			$	(341)			$	30,757			$	1,357			$	32,114

Common stock Additional
paid-in
capital Accumulated
deficit Accumulated
other
comprehensive
loss Stockholders’
equity
attributable
to KMI Non-controlling
interests Total
Issued shares Par value
Balance at June 30, 2021 2,265 $ 23 $ 41,793 $ (10,496) $ (609) $ 30,711 $ 429 $ 31,140
Restricted shares 2 (5) (5) (5)
Net income 495 495 16 511
Distributions — (6) (6)
Contributions — 1 1
Dividends (616) (616) (616)
Other comprehensive loss (33) (33) (33)
Balance at September 30, 2021 2,267 $ 23 $ 41,788 $ (10,617) $ (642) $ 30,552 $ 440 $ 30,992

Common stock Additional
paid-in
capital Accumulated
deficit Accumulated
other
comprehensive
loss Stockholders’
equity
attributable
to KMI Non-controlling
interests Total
Issued shares Par value
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 5) (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 (19) (333) (333) (333)
EP Trust I Preferred security conversions 1 1 1
Restricted shares 2 36 36 36
Net income 1,878 1,878 54 1,932
Distributions — (85) (85)
Contributions — 1 1
Impact of change in ownership interest in subsidiary 190 190 311 501
Dividends (1,876) (1,876) (1,876)
Other comprehensive income 48 48 48
Balance at September 30, 2022 2,250 $ 23 $ 41,689 $ (10,593) $ (363) $ 30,756 $ 1,379 $ 32,135


		Common stock			Additional paid-in capital				Accumulated deficit		Accumulated other comprehensive loss					Stockholders’ equity attributable to KMI			Non-controlling interests				Total			Common stock				Additional paid-in capital				Accumulated deficit				Accumulated other comprehensive loss				Stockholders’ equity attributable to KMI				Non- controlling interests				Total
		Issued shares	Par value												Issued shares						Par value
Balance at December 31, 2020		2,264	$	23			$	41,756					$	(9,936)				$	(407)			$	31,436			$	402	$	31,838
Balance at December 31, 2021																									Balance at December 31, 2021	2,267		$	23			$	41,806			$	(10,595)			$	(411)			$	30,823			$	1,098			$	31,921
Impact of adoption of ASU 2020-06 (Note 4)																									Impact of adoption of ASU 2020-06 (Note 4)					(11)												(11)								(11)
Balance at January 1, 2022																									Balance at January 1, 2022	2,267		23		41,795				(10,595)				(411)				30,812				1,098				31,910

Repurchases of shares																									Repurchases of shares					(1)												(1)								(1)
EP Trust I Preferred security conversions																									EP Trust I Preferred security conversions					1												1								1
Restricted shares																									Restricted shares					18												18								18
Net income																									Net income									667								667				17				684
Dividends																									Dividends									(616)								(616)								(616)
Distributions																									Distributions																	—				(26)				(26)

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	Other comprehensive loss										(235)					(235)							(235)		Other comprehensive loss													(263)				(263)								(263)
Balance at September 30, 2021		2,267	$	23	$	41,788			$	(10,617)	$	(642)				$	30,552		$	440			$	30,992
Balance at March 31, 2022																									Balance at March 31, 2022	2,267		$	23	$	41,813			$	(10,544)			$	(674)			$	30,618			$	1,089			$	31,707

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~~82,000 miles of pipelines, ~~141~~140 terminals, 700 Bcf of working natural gas storage capacity and ~~2.2~~2.3 Bcf per year of ~~renewable natural gas~~RNG generation 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 ~~2021~~2022 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.

~~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, 2022 evaluation, we grouped our businesses into seven 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 (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, 2022 annual impairment 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 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 include dividend equivalent payments, do not participate in excess distributions over earnings.

The following table sets forth the allocation of net income available to shareholders of Class P common stock and participating securities:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2022		2021		2022		2021					2023		2022
		(In millions, except per share amounts)										(In millions, except per share amounts)
Net Income Available to Stockholders	Net Income Available to Stockholders	$	576	$	495	$	1,878	$	1,147	Net Income Available to Stockholders			$	679	$	667
Participating securities:	Participating securities:									Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	Less: Net Income Allocated to Restricted Stock Awards(a)	(4)		(4)		(9)		(10)		Less: Net Income Allocated to Restricted Stock Awards(a)			(4)		(4)
Net Income Allocated to Class P Stockholders	Net Income Allocated to Class P Stockholders	$	572	$	491	$	1,869	$	1,137	Net Income Allocated to Class P Stockholders			$	675	$	663

Basic Weighted Average Shares Outstanding	Basic Weighted Average Shares Outstanding	2,253		2,267		2,262		2,265		Basic Weighted Average Shares Outstanding			2,247		2,267
Basic Earnings Per Share	Basic Earnings Per Share	$	0.25	$	0.22	$	0.83	$	0.50	Basic Earnings Per Share			$	0.30	$	0.29

(a)As of ~~September 30, 2022,~~March 31, 2023, there were 13 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. 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 March 31,
		2022	2021	2022	2021				2023	2022
		(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			13	13
Convertible trust preferred securities	Convertible trust preferred securities	3	3	3	3	Convertible trust preferred securities			3	3

2. ~~2. Acquisitions and Divestitures~~Losses on Impairments

~~Business Combinations~~Impairments

AsDuring the first quarter of ~~September 30, 2022, our preliminary allocation~~2023, we recognized an impairment of ~~the purchase price for significant acquisitions completed during the nine months ended September 30, 2022 are detailed below.~~

Assignment of Purchase Price
Ref Date Acquisition Purchase price Current assets Property, plant & equipment Other long-term assets Goodwill Current liabilities
(In millions)
(1) 8/22 North American Natural Resources, Inc. $ 132 $ 2 $ 5 $ 64 $ 61 $ —
(2) 7/22 Mas CanAm, LLC 358 9 31 319 — (1)

~~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 CO~~2 ~~business segment.~~

~~(1) North American Natural Resources Acquisition~~

On August 11, 2022, we completed the acquisition of seven landfill assets from North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of gas-to-power facilities in Michigan and Kentucky for $132$67 million including a preliminary purchase price adjustment for working capital. Other long-term assets within the purchase price allocation consists of intangibles related to gas rights and customer contracts with a weighted average amortization period of approximately 13 years. While our analysis of this transaction is ongoing, we currently believe the goodwill associated with this acquisition is tax deductible.

~~(2) Mas CanAm Acquisition~~

On July 19, 2022, we completed an acquisition of three 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 $358 million including a preliminary purchase price adjustment for working capital. Other long-term assets within the purchase price allocation reflects an intangible related to a customer contract with an amortization period of approximately 17 years.

~~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, 2022 is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

~~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/or our expected ability to grow the business we acquired by leveraging our pre-existing business experience. 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, 2022 are summarized by reporting unit as follows:~~

Natural Gas Pipelines Regulated Natural Gas Pipelines Non-Regulated
CO2
Products Pipelines Products Pipelines Terminals Terminals
CO2 – Energy Transition Ventures
Total
(In millions)
Goodwill as of December 31, 2021 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 63 $ 19,914
Acquisitions(a) — — — — — — 51 51
Goodwill as of September 30, 2022 $ 14,249 $ 2,343 $ 928 $ 1,378 $ 151 $ 802 $ 114 $ 19,965

~~(a)Includes goodwill arising from our acquisition of NANR and a $10 million purchase price adjustment~~ related to our ~~2021 acquisition~~investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expire in the second half of ~~Kinetrex that was attributed to long-term deferred tax liabilities.~~

~~Divestitures~~

~~Sale of Interest in Elba Liquefaction Company L.L.C.~~

On September 26, 2022, we completed the sale of a 25.5% ownership interest in Elba Liquefaction Company L.L.C. (ELC). We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which2023. The impairment is ~~reflected on our accompanying consolidated statements of stockholders’ equity for the three and nine months ended September 30, 2022. We continue to own a 25.5% interest in and operate ELC.~~

We continue to consolidate ELC. We have determined that ELC is a variable interest entity and Southern Liquefaction Company, LLC (SLC), which is indirectly controlled by us, is the primary beneficiary because it has the ability to direct the activities that most significantly impact ELC’s economic performance and the right to receive benefits and the obligation to absorb losses. In addition to being the operator of ELC, the evaluation of ELC as a variable interest entity and SLC as the primary beneficiary included consideration of the following: (i) a liquefaction service agreement between ELC and its customer was designed for recovery by ELC of actual costs for operating and maintaining ELC’s facilities, which reduces the risk for all equity owners to absorb losses resulting from cost variability; and (ii) substantially all ELC’s activities involve KMI subsidiaries under common control that provide services for and benefit from the operations of ELC.

~~The following table shows the carrying amount and classification of ELC’s assets and liabilities in our consolidated balance sheet:~~


	~~September 30, 2022~~
	~~(In millions)~~
~~Assets~~
~~Current assets~~	$	43
~~Property, plant and equipment, net~~	~~1,207~~
~~Deferred charges and other assets~~	6

~~Liabilities~~
~~Current liabilities~~	$	28
~~Other long-term liabilities and deferred credits~~	5

We receive distributions from ELC, indirectly, through our interest in SLC, but otherwise, the assets of ELC cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and the obligations of ELC may only be settled using the assets of ELC. ELC does not guarantee our debt or other similar commitments.

~~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 million for our proportionate share of the interests sold. We recognized ~~a pre-tax gain of $206 million for our proportionate share, which is included within “Other, net”~~ on our accompanying consolidated statement of income for the ~~nine~~three months ended ~~September 30, 2021. We and Brookfield now each hold a 37.5% interest in NGPL Holdings.~~

3. ~~Losses on Impairments and Other Write-downs~~

~~Long-lived Asset Impairment~~

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. We utilized an income approach to estimate fair value and compared it to the carrying value. The significant assumptions made in calculating fair value include estimates of future cash flows and discount rates, a Level 3 input. ~~As a result of our evaluation, we recognized a non-cash, long-lived asset impairment of $1,600 million during the nine months ended September 30, 2021.~~

~~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~~March 31, 2023 within “Earnings from equity ~~investments” on~~investments.” Our investment in Double Eagle and associated earnings is included within our ~~accompanying consolidated statement of income for the nine months ended September 30, 2021. The write-down was driven by the impairment recognized by Ruby of its assets.~~Products Pipelines business segment.

Ruby Chapter 11 Bankruptcy ~~Filing~~

~~The balance~~On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby ~~Pipeline, L.L.C.’s 2022 unsecured notes matured~~to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on ~~April 1, 2022~~hand. Our payment to the bankruptcy estate, net of payments received in ~~the principal amount~~respect of ~~$475 million. Although~~a long-term subordinated note receivable from Ruby, ~~has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date~~was approximately $28.5 million which was accrued for as of ~~April 1,~~December 31, 2022. ~~Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11~~Consummation of the ~~United States Bankruptcy Code in~~settlement and the ~~United States Bankruptcy Court for the District~~sale of ~~Delaware.~~ Ruby ~~as the debtor, will continue~~ to ~~operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court.~~Tallgrass occurred on January 13, 2023. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. ~~We had no amounts included in our “Investments” on our accompanying consolidated balance sheets associated with Ruby as of September 30, 2022 or December 31, 2021.~~

1311

4.3. Debt

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


		September 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(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		$	—	$	—
$3.5 billion credit facility due August 20, 2027						$3.5 billion credit facility due August 20, 2027	$	—	$	—
$500 million credit facility due November 16, 2023	$500 million credit facility due November 16, 2023	—		—		$500 million credit facility due November 16, 2023	—		—
Commercial paper notes	Commercial paper notes	—		—		Commercial paper notes	—		—
Current portion of senior notes	Current portion of senior notes					Current portion of senior notes
8.625%, due January 2022(a)		—		260
4.15%, due March 2022(a)		—		375
1.50%, due March 2022(a)(b)		—		853
3.95% due September 2022(c)		—		1,000
3.15% due January 2023	3.15% due January 2023	1,000		—		3.15% due January 2023	—		1,000
Floating rate, due January 2023(d)		250		—
Floating rate, due January 2023						Floating rate, due January 2023	—		250
3.45% due February 2023	3.45% due February 2023	625		—		3.45% due February 2023	—		625
3.50% due September 2023	3.50% due September 2023	600		—		3.50% due September 2023	600		600
Trust I preferred securities, 4.75%, due March 2028		111		111
5.625% due November 2023						5.625% due November 2023	750		750
4.15% due February 2024						4.15% due February 2024	650		—
Trust I preferred securities, 4.75%, due March 2028(a)						Trust I preferred securities, 4.75%, due March 2028(a)	111		111
Current portion of other debt	Current portion of other debt	48		47		Current portion of other debt	49		49
Total current portion of debt	Total current portion of debt	2,634		2,646		Total current portion of debt	2,160		3,385

Long-term debt (excluding current portion)	Long-term debt (excluding current portion)					Long-term debt (excluding current portion)
Senior notes	Senior notes	28,343		29,097		Senior notes	28,495		27,638
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	336		348		EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	326		330

Trust I preferred securities, 4.75%, due March 2028	Trust I preferred securities, 4.75%, due March 2028	109		110		Trust I preferred securities, 4.75%, due March 2028	109		109
Other	Other	212		217		Other	209		211
Total long-term debt	Total long-term debt	29,000		29,772		Total long-term debt	29,139		28,288
Total debt(e)		$	31,634	$	32,418
Total debt(b)						Total debt(b)	$	31,299	$	31,673

(a)~~We repaid~~Reflects the ~~principal amount~~portion of ~~these senior notes during~~cash consideration payable if all the ~~first quarter~~outstanding securities as of ~~2022.~~the end of the reporting period were converted by the holders.

(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars. The December 31, 2021 balance is reported above at the exchange rate of 1.1370 U.S. dollars per Euro. As of 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 $38 million related to these notes, which was offset by a corresponding change in the value of cross-currency swaps reflected in “Current Assets—~~Fair value of derivative contracts” and “Current Liabilities~~—Fair value of derivative contracts” on our accompanying consolidated balance 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 “Risk Management~~—Foreign Currency Risk Management”).~~

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

~~(d)These senior notes have an associated floating-to-fixed interest rate swap agreement which is designated as a cash flow hedge (see Note 6 “Risk Management—Interest Rate Risk Management”).~~

~~(e)~~Excludes our “Debt fair value adjustments” which, as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, increased our total debt balances by ~~$107~~$207 million and ~~$902~~$115 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 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs. These notes are guaranteed through the cross guarantee agreement discussed above.

~~On August 3, 2022,~~January 31, 2023, we issued in a registered offering ~~two series of senior notes consisting of $750~~$1,500 million aggregate principal amount of ~~4.80%~~5.20% senior notes due 2033 ~~and $750 million aggregate principal amount of 5.45% senior notes due 2052 and received combined~~for net proceeds of ~~$1,484 million. We~~$1,485 million, which were used ~~a portion of the proceeds~~ to repay short-term borrowings, maturing debt and for general corporate purposes.

Credit Facilities and Restrictive Covenants

As of ~~September 30, 2022,~~March 31, 2023, we had no borrowings outstanding under our credit facilities, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of ~~September 30, 2022~~March 31, 2023 was $3.9 billion. ~~As of September 30, 2022,~~For the period ended March 31, 2023, 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, 2022 December 31, 2021
Carrying
value Estimated
fair value(a) Carrying
value Estimated
fair value(a)
(In millions)
Total debt $ 31,741 $ 29,188 $ 33,320 $ 37,775


	March 31, 2023				December 31, 2022
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,506	$	30,483	$	31,788	$	30,070

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of ~~$203~~$198 million and ~~$218~~$195 million as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021.~~2022.

5.4. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. During the ~~nine~~three months ended ~~September 30, 2022,~~March 31, 2023, we repurchased ~~approximately 19~~7 million of our shares for ~~$333~~$113 million at an average price of ~~$16.97~~$16.62 per share. Subsequent to September 30, 2022 and through October 20, 2022, we repurchased 2 million of our shares for $34 million at an average price of $16.75 per share, and since December 2017, in total, we have repurchased 54 million of our shares under the program at an average price of $17.40 per share for $942 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 March 31,
		2022		2021		2022		2021				2023		2022
Per share cash dividend declared for the period	Per share cash dividend declared for the period	$	0.2775	$	0.27	$	0.8325	$	0.81	Per share cash dividend declared for the period		$	0.2825	$	0.2775
Per share cash dividend paid in the period	Per share cash dividend paid in the period	0.2775		0.27		0.8250		0.8025		Per share cash dividend paid in the period		0.2775		0.27

On ~~October~~April 19, ~~2022,~~2023, our board of directors declared a cash dividend of ~~$0.2775~~$0.2825 per share for the quarterly period ended ~~September 30, 2022,~~March 31, 2023, which is payable on ~~November~~May 15, ~~2022~~2023 to shareholders of record as of the close of business on ~~October 31, 2022.~~May 1, 2023.

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~~Subtopic 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 ~~nine~~three months ended ~~September 30,~~March 31, 2022.

Accumulated Other Comprehensive Loss

Changes in the components of our “Accumulated other comprehensive loss” not including noncontrolling interests are summarized as follows:

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 (366) 18 (348)
Loss reclassified from accumulated other comprehensive loss 396 — 396
Net current-period change in accumulated other comprehensive loss 30 18 48
Balance as of September 30, 2022 $ (142) $ (221) $ (363)


	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, 2022	$	(164)	$	(238)	$	(402)
Other comprehensive gain before reclassifications	106		4		110
Gain reclassified from accumulated other comprehensive loss	(49)		—		(49)
Net current-period change in accumulated other comprehensive loss	57		4		61
Balance as of March 31, 2023	$	(107)	$	(234)	$	(341)


		Net unrealized gains/(losses) on cash flow hedge derivatives		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, 2020		$	(13)	$	(394)		$	(407)
Balance as of December 31, 2021									Balance as of December 31, 2021	$	(172)	$	(239)	$	(411)
Other comprehensive (loss) gain before reclassifications	Other comprehensive (loss) gain before reclassifications	(444)		28			(416)		Other comprehensive (loss) gain before reclassifications	(411)		13		(398)
Loss reclassified from accumulated other comprehensive loss	Loss reclassified from accumulated other comprehensive loss	181		—			181		Loss reclassified from accumulated other comprehensive loss	135		—		135
Net current-period change in accumulated other comprehensive loss	Net current-period change in accumulated other comprehensive loss	(263)		28			(235)		Net current-period change in accumulated other comprehensive loss	(276)		13		(263)
Balance as of September 30, 2021		$	(276)	$	(366)		$	(642)
Balance as of March 31, 2022									Balance as of March 31, 2022	$	(448)	$	(226)	$	(674)

6.5. 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 30, 2022,~~March 31, 2023, 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	~~(19.4)~~(17.9)	MMBbl
Crude oil basis	~~(6.0)~~(3.2)	MMBbl
Natural gas fixed price	~~(50.8)~~(76.7)	Bcf
Natural gas basis	~~(28.0)~~(64.0)	Bcf
NGL fixed price	(0.7)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.2)	MMBbl
Crude oil basis	~~(9.0)~~(10.8)	MMBbl
Natural gas fixed price	~~(7.5)~~(7.1)	Bcf
Natural gas basis	~~(37.8)~~(49.8)	Bcf

NGL fixed price	~~(0.8)~~(0.9)	MMBbl

1614

As of ~~September 30, 2022,~~March 31, 2023, 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 ~~2026.~~2027.

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 30, 2022:~~March 31, 2023:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

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

~~7,500~~7,400

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

~~5,100~~3,445

Mark-to-Market

December ~~2022~~2023

(a)The principal amount of hedged senior notes consisted of ~~$700~~$1,450 million included in “Current portion of debt” and ~~$6,800~~$5,950 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three ~~and nine~~ months ended ~~September 30, 2022,~~March 31, 2023, 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 ~~11 “Recent Accounting Pronouncements”~~10 for further information on Topic 848.

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 30, 2022:~~March 31, 2023:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

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

543

Cash flow hedge

March 2027

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

1715

Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included on 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, 2022		December 31, 2021		September 30, 2022		December 31, 2021				March 31, 2023		December 31, 2022		March 31, 2023		December 31, 2022
		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/(Fair value of derivative contracts)	$	104	$	61	$	(229)	$	(141)	Energy commodity derivative contracts
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	29		3		(67)		(94)			Fair value of derivative contracts/(Fair value of derivative contracts)	$	119	$	150	$	(132)	$	(156)
Subtotal			133		64		(296)		(235)
												Deferred charges and other assets/(Other long-term liabilities and deferred credits)	13		6		(58)		(91)
												Subtotal	132		156		(190)		(247)
Interest rate contracts	Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	3		101		(115)		(3)		Interest rate contracts
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	36		284		(307)		(15)			Fair value of derivative contracts/(Fair value of derivative contracts)	1		—		(138)		(144)
Subtotal			39		385		(422)		(18)
												Deferred charges and other assets/(Other long-term liabilities and deferred credits)	48		39		(160)		(261)
												Subtotal	49		39		(298)		(405)
Foreign currency contracts	Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(6)		(3)		Foreign currency contracts
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(62)		—			Fair value of derivative contracts/(Fair value of derivative contracts)	—		—		(12)		(3)
Subtotal			—		41		(68)		(3)
Total			172		490		(786)		(256)
												Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(19)		(32)
												Subtotal	—		—		(31)		(35)
												Total	181		195		(519)		(687)

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/(Fair value of derivative contracts)	48		11		(151)		(31)		Energy commodity derivative contracts
		Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		1		(22)		(6)			Fair value of derivative contracts/(Fair value of derivative contracts)	37		80		(62)		(162)
Subtotal			68		12		(173)		(37)
												Deferred charges and other assets/(Other long-term liabilities and deferred credits)	13		23		(4)		(19)
												Subtotal	50		103		(66)		(181)
Interest rate contracts	Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	39		12		—		—		Interest rate contracts
												Fair value of derivative contracts/(Fair value of derivative contracts)	7		1		—		—

Total			107		24		(173)		(37)

												Total	57		104		(66)		(181)
Total derivatives	Total derivatives		$	279	$	514	$	(959)	$	(293)	Total derivatives		$	238	$	299	$	(585)	$	(868)

1816

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								Contracts available for netting				Cash collateral held(b)									Balance sheet asset fair value measurements by level																Contracts available for netting			Cash collateral held(a)
		Level 1		Level 2		Level 3		Gross amount								Net amount				Level 1					Level 2				Level 3				Gross amount								Net amount
		(In millions)																					(In millions)
As of September 30, 2022
As of March 31, 2023																					As of March 31, 2023
Energy commodity derivative contracts~~(a)~~(b)	Energy commodity derivative contracts~~(a)~~(b)	$	63	$	138	$	—	$	201			$	(169)			$	—				$	32		Energy commodity derivative contracts~~(a)~~(b)	$	110			$	72			$	—			$	182				$	(87)	$	—	$	95
Interest rate contracts	Interest rate contracts	—		78		—		78		—				—				78			Interest rate contracts		—				56				—				56				—			—		56

As of December 31, 2021
As of December 31, 2022																					As of December 31, 2022
Energy commodity derivative contracts~~(a)~~(b)	Energy commodity derivative contracts~~(a)~~(b)	$	56	$	20	$	—	$	76	$	(53)			$	(20)			$	3		Energy commodity derivative contracts~~(a)~~(b)		$	115			$	144			$	—			$	259			$	(186)		$	—	$	73
Interest rate contracts	Interest rate contracts	—		397		—		397		(9)				—				388			Interest rate contracts		—				40				—				40				—			—		40
Foreign currency contracts		—		41		—		41		(3)				—				38


		Balance sheet liability fair value measurements by level								Contracts available for netting				Cash collateral posted(b)									Balance sheet liability fair value measurements by level											Contracts available for netting				Cash collateral posted(a)
		Level 1		Level 2		Level 3		Gross amount								Net amount				Level 1					Level 2			Level 3			Gross amount					Net amount
		(In millions)																					(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)		$	(127)	$	(342)	$	—	$	(469)			$	169			$	135				$	(165)
As of March 31, 2023																					As of March 31, 2023
Energy commodity derivative contracts(b)																					Energy commodity derivative contracts(b)		$	(25)		$	(231)		$	—		$	(256)			$	87			$	(43)			$	(212)
Interest rate contracts	Interest rate contracts	—		(422)		—		(422)		—				—				(422)			Interest rate contracts		—			(298)			—			(298)		—				—				(298)
Foreign currency contracts	Foreign currency contracts	—		(68)		—		(68)		—				—				(68)			Foreign currency contracts		—			(31)			—			(31)		—				—				(31)
As of December 31, 2021
Energy commodity derivative contracts(a)		$	(15)	$	(257)	$	—	$	(272)	$	53			$	—			$	(219)
As of December 31, 2022																					As of December 31, 2022
Energy commodity derivative contracts(b)																					Energy commodity derivative contracts(b)		$	(23)		$	(405)		$	—		$	(428)	$	186			$	(30)			$	(272)
Interest rate contracts	Interest rate contracts	—		(18)		—		(18)		9				—				(9)			Interest rate contracts		—			(405)			—			(405)		—				—				(405)
Foreign currency contracts	Foreign currency contracts	—		(3)		—		(3)		3				—				—			Foreign currency contracts		—			(35)			—			(35)		—				—				(35)

(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.

(b)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps and crude oil basis swaps.

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


Derivatives in fair value hedging relationships	Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income on derivative and related hedged item								Derivatives in fair value hedging relationships	Location		Gain/(loss) recognized in income on derivative and related hedged item
			Three Months Ended September 30,				Nine Months Ended September 30,						Three Months Ended March 31,
			2022		2021		2022		2021					2023		2022
			(In millions)											(In millions)
Interest rate contracts	Interest rate contracts	Interest, net	$	(278)	$	(39)	$	(754)	$	(228)	Interest rate contracts	Interest, net		$	118	$	(317)

Hedged fixed rate debt(a)	Hedged fixed rate debt(a)	Interest, net	$	279	$	39	$	761	$	229	Hedged fixed rate debt(a)	Interest, net		$	(118)	$	320

(a)As of ~~September 30, 2022,~~March 31, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of ~~$385~~$249 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

Derivatives in cash flow hedging relationships Gain/(loss)
recognized in OCI on derivative(a) Location Gain/(loss) reclassified from Accumulated OCI
into income(b)
Three Months Ended
September 30, Three Months Ended
September 30,
2022 2021 2022 2021
(In millions) (In millions)
Energy commodity derivative contracts $ 195 $ (140) Revenues—Commodity sales $ (116) $ (94)
Costs of sales 17 8
Interest rate contracts — 1 Interest, net — —
Foreign currency contracts (32) (33) Other, net (34) (34)
Total $ 163 $ (172) Total $ (133) $ (120)


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
		Nine Months Ended September 30,					Nine Months Ended September 30,					Three Months Ended March 31,					Three Months Ended March 31,
		2022		2021			2022		2021			2023		2022			2023		2022
		(In millions)					(In millions)					(In millions)					(In millions)
Energy commodity derivative contracts	Energy commodity derivative contracts	$	(375)	$	(514)	Revenues—Commodity sales	$	(433)	$	(167)	Energy commodity derivative contracts	$	135	$	(499)	Revenues—Commodity sales	$	64	$	(132)

						Costs of sales	34		10							Costs of sales	(7)		9
Interest rate contracts	Interest rate contracts	7		3		Interest, net	—		—		Interest rate contracts	—		3		Interest, net	—		—

Foreign currency contracts	Foreign currency contracts	(107)		(68)		Other, net	(115)		(79)		Foreign currency contracts	3		(40)		Other, net	7		(53)
Total	Total	$	(475)	$	(579)	Total	$	(514)	$	(236)	Total	$	138	$	(536)	Total	$	64	$	(176)

(a)We expect to reclassify approximately ~~$124~~$66 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of ~~September 30, 2022~~March 31, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

~~(b)~~During the nine months ended September 30, 2022 and 2021, we recognized approximate gains of $34 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).


Derivatives not designated as accounting hedges	Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives								Derivatives not designated as accounting hedges	Location		Gain/(loss) recognized in income on derivatives
			Three Months Ended September 30,				Nine Months Ended September 30,						Three Months Ended March 31,
			2022		2021		2022		2021						2023		2022
			(In millions)											(In millions)
Energy commodity derivative contracts	Energy commodity derivative contracts	Revenues—Commodity sales	$	44	$	(40)	$	18	$	(703)	Energy commodity derivative contracts	Revenues—Commodity sales			$	22	$	(9)
		Costs of sales	(30)		(7)		(129)		154			Costs of sales			69		(91)
		Earnings from equity investments	(7)		(2)		(11)		(4)			Earnings from equity investments			1		(5)
Interest rate contracts	Interest rate contracts	Interest, net	(20)		—		28		—		Interest rate contracts	Interest, net			5		36
Total(a)	Total(a)		$	(13)	$	(49)	$	(94)	$	(553)	Total(a)				$	97	$	(69)

(a)The three ~~and nine~~ months ended ~~September 30,~~March 31, 2023 and 2022 amounts include approximate ~~losses~~gains of ~~$19~~$28 million and ~~$39 million, respectively, and the three and nine months ended September 30, 2021 amounts include approximate losses of $24 million and $480~~$18 million, respectively, associated with natural gas, crude and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of ~~September 30, 2022,~~March 31, 2023, we had cash margins of ~~$223~~$5 million posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheet. As of December 31, ~~2021,~~2022, we had cash margins of ~~$14~~$1 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The cash margin balance at ~~September 30, 2022~~March 31, 2023 represents our initial margin requirements of ~~$88~~$48 million and variation margin requirements of ~~$135~~$43 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 30, 2022,~~March 31, 2023, 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 ~~$100~~$88 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, 2022													Three Months Ended March 31, 2023
		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 customers(a)
Revenues from contracts with customers(a)														Revenues from contracts with customers(a)
Services	Services													Services
Firm services(b)	Firm services(b)	$	845	$	57	$	199	$	—	$	—	$	1,101	Firm services(b)	$	917	$	40	$	207	$	—	$	(1)	$	1,163
Fee-based services	Fee-based services	243		247		106		11		—		607		Fee-based services	236		240		98		10		—		584
Total services	Total services	1,088		304		305		11		—		1,708		Total services	1,153		280		305		10		(1)		1,747
Commodity sales	Commodity sales													Commodity sales
Natural gas sales	Natural gas sales	1,902		—		—		24		(7)		1,919		Natural gas sales	799		—		—		20		(2)		817
Product sales	Product sales	389		511		11		353		(1)		1,263		Product sales	274		336		4		268		(1)		881

Total commodity sales	Total commodity sales	2,291		511		11		377		(8)		3,182		Total commodity sales	1,073		336		4		288		(3)		1,698
Total revenues from customers		3,379		815		316		388		(8)		4,890
Total revenues from contracts with customers														Total revenues from contracts with customers	2,226		616		309		298		(4)		3,445
Other revenues(c)	Other revenues(c)													Other revenues(c)
Leasing services(d)	Leasing services(d)	120		51		141		16		—		328		Leasing services(d)	117		47		152		14		—		330
Derivatives adjustments on commodity sales	Derivatives adjustments on commodity sales	(12)		—		—		(60)		—		(72)		Derivatives adjustments on commodity sales	107		(1)		—		(20)		—		86
Other	Other	18		6		—		7		—		31		Other	16		6		—		5		—		27
Total other revenues	Total other revenues	126		57		141		(37)		—		287		Total other revenues	240		52		152		(1)		—		443
Total revenues	Total revenues	$	3,505	$	872	$	457	$	351	$	(8)	$	5,177	Total revenues	$	2,466	$	668	$	461	$	297	$	(4)	$	3,888


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

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

2119

Three Months Ended September 30, 2021
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from customers(a)
Services
Firm services(b) $ 836 $ 66 $ 181 $ 1 $ (2) $ 1,082
Fee-based services 190 244 93 10 — 537
Total services 1,026 310 274 11 (2) 1,619
Commodity sales
Natural gas sales 1,097 — — 7 (3) 1,101
Product sales 372 247 8 279 (11) 895
Total commodity sales 1,469 247 8 286 (14) 1,996
Total revenues from customers 2,495 557 282 297 (16) 3,615
Other revenues(c)
Leasing services(d) 119 42 140 15 — 316
Derivatives adjustments on commodity sales (71) — — (63) — (134)
Other 12 6 — 8 1 27
Total other revenues 60 48 140 (40) 1 209
Total revenues $ 2,555 $ 605 $ 422 $ 257 $ (15) $ 3,824

Nine Months Ended September 30, 2022
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from customers(a)
Services
Firm services(b) $ 2,633 $ 176 $ 585 $ 1 $ (2) $ 3,393
Fee-based services 690 723 300 35 — 1,748
Total services 3,323 899 885 36 (2) 5,141
Commodity sales
Natural gas sales 4,938 — — 68 (17) 4,989
Product sales 1,141 1,577 22 1,105 (4) 3,841
Total commodity sales 6,079 1,577 22 1,173 (21) 8,830
Total revenues from customers 9,402 2,476 907 1,209 (23) 13,971
Other revenues(c)
Leasing services(d) 355 144 430 44 — 973
Derivatives adjustments on commodity sales (132) (3) — (280) — (415)
Other 49 17 — 26 — 92
Total other revenues 272 158 430 (210) — 650
Total revenues $ 9,674 $ 2,634 $ 1,337 $ 999 $ (23) $ 14,621

Nine Months Ended September 30, 2021
Natural Gas Pipelines Products Pipelines Terminals
CO2
Corporate and Eliminations Total
(In millions)
Revenues from 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 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

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

(b)Includes non-cancellable firm service customer contracts with take-or-pay or minimum volume commitment elements, including those contracts where both the price and quantity amount are fixed. Excludes service contracts with index-based pricing, which along with revenues from other customer service contracts are reported as “Fee-based services.”

(c)Amounts recognized as revenue under guidance prescribed in Topics of the ASC other than in Topic 606 were primarily from leases and derivative contracts. See Note ~~6 “Risk Management”~~5 for additional information related to our derivative contracts.

(d)Our revenues from leasing services are predominantly comprised of specific assets that we lease to customers under operating leases where one customer obtains substantially all of the economic benefit from the asset and has the right to direct the use of that asset. These leases primarily consist of specific tanks, treating facilities, marine vessels and gas equipment and pipelines with separate control locations. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, our contract asset balances were ~~$57~~$26 million and ~~$39~~$33 million, respectively. Of the contract asset balance at December 31, ~~2021, $29~~2022, $14 million was transferred to accounts receivable during the ~~nine~~three months ended ~~September 30, 2022.~~March 31, 2023. As of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, our contract liability balances were ~~$204~~$228 million and ~~$212~~$204 million, respectively. Of the contract liability balance at December 31, ~~2021, $77~~2022, $35 million was recognized as revenue during the ~~nine~~three months ended ~~September 30, 2022.~~March 31, 2023.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of ~~September 30, 2022~~March 31, 2023 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, 2022		$	1,157
2023		4,055
Nine months ended December 31, 2023				Nine months ended December 31, 2023	$	3,260
2024	2024	3,244		2024	3,633
2025	2025	2,685		2025	2,967
2026	2026	2,357		2026	2,581
2027				2027	2,215
Thereafter	Thereafter	14,007		Thereafter	13,095
Total	Total	$	27,505	Total	$	27,751

Our contractually committed revenue, for purposes of the tabular presentation above, is generally limited to service or commodity sale customer contracts which have fixed pricing and fixed volume terms and conditions, generally including contracts with take-or-pay or minimum volume commitment payment obligations. Our contractually committed revenue amounts generally exclude, based on the following practical expedient that we elected to apply, remaining performance obligations for contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

7. Reportable Segments

Financial information by segment follows:


		Three Months Ended September 30,				Nine Months Ended September 30,					Three Months Ended March 31,
		2022		2021		2022		2021				2023		2022
		(In millions)										(In millions)
Revenues	Revenues									Revenues
Natural Gas Pipelines	Natural Gas Pipelines									Natural Gas Pipelines
Revenues from external customers	Revenues from external customers	$	3,497	$	2,541	$	9,653	$	8,611	Revenues from external customers		$	2,463	$	2,793
Intersegment revenues	Intersegment revenues	8		14		21		45		Intersegment revenues		3		20

Products Pipelines	Products Pipelines	872		605		2,634		1,572		Products Pipelines		668		766

Terminals	Terminals									Terminals
Revenues from external customers	Revenues from external customers	457		421		1,335		1,273		Revenues from external customers		460		429
Intersegment revenues	Intersegment revenues	—		1		2		2		Intersegment revenues		1		1
CO2	CO2	351		257		999		729		CO2		297		305

Corporate and intersegment eliminations	Corporate and intersegment eliminations	(8)		(15)		(23)		(47)		Corporate and intersegment eliminations		(4)		(21)
Total consolidated revenues	Total consolidated revenues	$	5,177	$	3,824	$	14,621	$	12,185	Total consolidated revenues		$	3,888	$	4,293


	Three Months Ended March 31,
		2023		2022
		(In millions)
Segment EBDA(a)
Natural Gas Pipelines		$	1,495	$	1,184
Products Pipelines		184		299
Terminals		254		238
CO2		172		192


Total Segment EBDA		2,105		1,913
DD&A		(565)		(538)
Amortization of excess cost of equity investments		(17)		(19)

General and administrative and corporate charges		(179)		(145)
Interest, net		(445)		(333)

Income tax expense		(196)		(194)

Total consolidated net income		$	703	$	684

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions)
Segment EBDA(a)
Natural Gas Pipelines $ 1,135 $ 1,069 $ 3,453 $ 2,602
Products Pipelines 257 279 855 792
Terminals 240 216 731 689
CO2
215 163 619 599
Total Segment EBDA 1,847 1,727 5,658 4,682
DD&A (551) (526) (1,632) (1,595)
Amortization of excess cost of equity investments (19) (21) (57) (56)
General and administrative and corporate charges (149) (167) (438) (465)
Interest, net (399) (368) (1,087) (1,122)
Income tax expense (134) (134) (512) (248)
Total consolidated net income $ 595 $ 511 $ 1,932 $ 1,196


		September 30, 2022		December 31, 2021			March 31, 2023		December 31, 2022
		(In millions)					(In millions)
Assets	Assets					Assets
Natural Gas Pipelines	Natural Gas Pipelines	$	47,872	$	47,746	Natural Gas Pipelines	$	47,351	$	47,978
Products Pipelines	Products Pipelines	8,994		9,088		Products Pipelines	8,836		8,985
Terminals	Terminals	8,362		8,513		Terminals	8,328		8,357
CO2	CO2	3,470		2,843		CO2	3,465		3,449

Corporate assets(b)	Corporate assets(b)	1,294		2,226		Corporate assets(b)	951		1,309

Total consolidated assets	Total consolidated assets	$	69,992	$	70,416	Total consolidated assets	$	68,931	$	70,078

(a)Includes revenues, earnings from equity investments, operating expenses, ~~(gain) loss~~gain on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income 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 included on our accompanying consolidated statements of income is as follows:


		Three Months Ended September 30,						Nine Months Ended September 30,							Three Months Ended March 31,
		2022			2021			2022			2021						2023			2022
		(In millions, except percentages)														(In millions, except percentages)
Income tax expense	Income tax expense	$	134		$	134		$	512		$	248		Income tax expense			$	196		$	194
Effective tax rate	Effective tax rate	18.4		%	20.8		%	20.9		%	17.2		%	Effective tax rate			21.8		%	22.1		%

The effective tax ~~rate~~rates for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2023 and 2022 ~~is lower~~are higher than the statutory federal rate of 21% primarily due to ~~the recognition of additional 2021 enhanced oil recovery credits from our initial estimate, the adjustment to the deferred tax liability as a result of the reduction in the~~ state ~~tax rate and~~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), partially offset by state income taxes.~~

The effective tax rate for the three months ended September 30, 2021 is lower than the statutory federal rate of 21% primarily due to 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, 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.Company.

~~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.

~~EPNG FERC Proceeding~~

On April 21, 2022, EPNG was notified by the FERC of the commencement of a rate proceeding against it pursuant to Section 5 of the Natural Gas Act. This proceeding sets the matter for hearing to determine whether EPNG’s current rates remain just and reasonable. A proceeding under Section 5 of the Natural Gas Act is prospective in nature such that a change in rates charged to customers, if any, would likely only occur after the FERC has issued a final order. Unless a settlement is reached sooner, an initial Administrative Law Judge decision is anticipated in the second quarter of 2023. We are engaged actively in settlement discussions and anticipate joining with FERC Trial Staff and other active participants in the proceeding in filing an unopposed motion to suspend the procedural schedule to enable the parties to prepare documents necessary to document a settlement in principle that would fully resolve the proceeding. We do not believe that the ultimate resolution of this proceeding will have a material adverse impact to 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. The Notice of Arbitration sought declaratory and monetary relief based upon 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 “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. 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 (Guarantee) entered into by Eni S.p.A. on December 10, 2007 in connection with ~~the~~a contemporaneous terminal use ~~agreement. In response~~agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). The suit to enforce the ~~foregoing lawsuit,~~Guarantee against Eni S.p.A. was filed ~~counterclaims under~~after an arbitration tribunal delivered an award on June 29, 2018 which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit to enforce the Guarantee, Eni S.p.A. filed counterclaims and other claims ~~under~~based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing ~~claims~~counterclaims asserted by Eni S.p.A seek unspecified damages and involve the same substantive allegations ~~as the claims~~ which were ~~resolved conclusively~~dismissed with prejudice in ~~the~~previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer ~~as described below.~~Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A. On January 4, 2022, the trial court entered a decision granting Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the ~~Guarantee Agreement.~~Guarantee. GLNG filed an ~~interlocutory~~ appeal of the ~~decision.~~trial court’s decision to the state Appellate Division. On February 9, 2023, the Appellate Division denied GLNG’s appeal. GLNG is seeking rehearing from the Appellate Division. If necessary, further recourse may be pursued to the state Court of Appeals, which is the state’s highest appellate court. 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~~based on the terminal use agreement and parent direct agreement remain pending in the trial court.

~~On December 20, 2019, GLNG’s~~ We vigorously dispute that the foregoing counterclaims and other claims asserted by Eni S.p.A. have any merit, particularly since they were dismissed with prejudice in previous arbitrations involving both Eni USA and ALSS. We intend to vigorously pursue our appeal to enforce the Guarantee and are seeking summary judgment on any remaining ~~customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including~~counterclaims or other claims asserted by 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. On July 15, 2021, the arbitration tribunal delivered 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 filed an amended petition in which it asserted that Hiland Partners’ failure to construct certain facilities by specific dates nullified the release contained in the settlement agreement. CLR’s amended petition asserted 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 was not allowed to deduct third-party processing fees from the gas purchase price. CLR sought damages in excess of $276 million. On September 14, 2022, the parties entered into a confidential settlement agreement, including an unconditional release and dismissal of the litigation with prejudice.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed ~~suit~~a lawsuit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human

needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of intent to appeal the trial court’s decision. We believe that our declaration of force majeure was valid and we intend to vigorously defend this case.

Pension Plan Litigation

On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and Beverly Leutloff filed a purported class action lawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the late 1970s. Following a series of corporate acquisitions, plaintiffs became participants in pension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The lawsuit, which was filed initially in federal court in Michigan and then transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590), alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a purported class-wide basis in the lawsuit. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III all seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. These claims challenge plan provisions which are alleged to constitute impermissible “backloading” or “cutback” of benefits. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. The complaint alleges that the purported class includes over 10,000 individuals. The lawsuit is in the early stages of discovery and no class has been certified. Plaintiffs seek to recover early retirement benefits as well as declaratory and injunctive relief, but have not pleaded, disclosed or otherwise specified a calculation of alleged damages. Accordingly, the extent of our potential liability for past or future benefits, if any, remains to be determined. We believe that none of the claims are valid and intend to vigorously defend this case.

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~~EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline ~~segment is currently out of service.~~to commercial service in February 2023. While no litigation is pending at this time, we notified our insurers of the incident and do not expect that the resolution of claims will have a material adverse impact to our business.

General

As of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, our total reserve for legal matters was ~~$42~~$43 million and ~~$231~~$70 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 except as disclosed herein 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., including natural resource damage (NRD) claims.

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~~alleged violations of Department of Transportation ~~regulations. The NOPV proposes~~regulations, proposed a penalty of approximately $455,000 and ~~seeks~~sought a compliance agreement relating to ~~three~~certain of the alleged violations. ~~The alleged violations are predominately procedural~~On February 3, 2023, PHMSA and KMLT entered into a Consent Agreement resolving the allegations in ~~nature. On September 1, 2022, we submitted a Request for Hearing, Statement of Issues and Response to~~ the NOPV. AtAlso on February 3, 2023, PHMSA issued a Consent Order approving the ~~same time we initiated settlement discussions with PHMSA which are ongoing. We do not anticipate the costs to resolve~~Consent Agreement, thereby concluding this ~~matter, including any costs to implement a compliance agreement, will have a material adverse impact to our business.~~matter.

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 to be more than $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 two facilities) and KMBT (in connection with its ownership or operation of two 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.~~December 2024. 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)~~NRD claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.

~~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 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 eight 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 eight 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 nine miles of the Site. ~~The~~At that time, the cleanup plan in the ROD iswas estimated to cost $440 million. No timeline for the cleanup has been established. ~~Certain~~On December 16, 2022, the United States Department of

Justice (DOJ) and EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, ~~are engaged in discussions with~~to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA ~~concerning~~filed a Complaint against the ~~upper nine miles. There remains significant uncertainty as to the implementation~~85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and ~~associated costs of the remedy set forth~~a Consent Decree in the ~~upper nine mile ROD. Until~~U.S. District Court for the ~~ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent~~District of ~~our potential liability.~~New Jersey. We ~~do not anticipate that~~believe our share of the costs to resolve this matter, including our share of the settlement with EPA and the costs ~~of any remediation of~~to remediate the Site, if any, will not 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, one of which is against TGP and one of which is against SNG, both described further below.

On November 8, 2013, the Parish of Plaquemines, Louisiana filed a petition for damages in the state district court for Plaquemines Parish, Louisiana against TGP and 17 other energy companies, alleging that 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 December 2013, the~~The case was removed to the U.S. District Court for the Eastern District of Louisiana. In April 2015, the U.S. District Court ordered the case to be remanded to the state district court for Plaquemines Parish. In May 2018, the case was removed for a 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 has been 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~~subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. The defendants to those consolidated cases pursued 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. On October 17, 2022, the United States Court of Appeals ordered those consolidated cases to be remanded to the state district courts. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend 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,~~At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.

Products Pipeline Incident, Walnut Creek, California

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

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

environmental improvement project funding, and for enforcement training in the State of California, and was placed on informal, unsupervised probation for a term of 18 months.

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

General

Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our business. As of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, we have accrued a total reserve for environmental liabilities in the amount of ~~$227~~$218 million and ~~$243~~$221 million, respectively. In addition, as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, we had receivables of $11 million and $12 million, respectively, 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 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 (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~~Topic 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.

On December 21, 2022, the FASB issued ASU No. 2022-06, “Reference Rate Reform (Topic 848): Deferral of the Sunset Date of Topic 848.” This ASU defers the sunset date of Topic 848 from December 31, 2022, to December 31, 2024, after which entities will no longer be permitted to apply the optional expedients and exceptions in Topic 848.

The guidance was effective upon ~~issuance and generally can be applied through December 31, 2022.~~issuance.

During the ~~nine~~three months ended ~~September 30, 2022~~March 31, 2023 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 ~~$1,725~~$1,225 million and convert a portion of our fixed rate debt to variable rates through ~~March 2035.~~February 2028. Concurrent with these amendments, we elected certain of the optional expedients provided in 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 any of the optional expedients in Topic 848 and, should they qualify, whether we wish to elect any such optional expedients. See Note 6“~~Risk~~5 “Risk Management—Interest Rate Risk ~~Management”~~Management” for more information on our interest rate 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 ~~2021~~2022 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our ~~2021~~2022 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our ~~2021~~2022 Form 10-K; and (iv) “Risk Factors” in Part I,II, Item 1A of this report and Part I, Item 1 in our ~~2021~~2022 Form 10-K.

~~Sale of Interest in Elba Liquefaction Company L.L.C.~~

On September 27, 2022, we completed the sale of a 25.5% ownership interest in Elba Liquefaction Company L.L.C. (ELC). We received net proceeds of $557 million which were used to reduce short-term borrowings. As we continue to have a controlling financial interest in and consolidate ELC, we recorded an increase of $190 million to “Additional paid in capital” for the impact of the change in our ownership interest in ELC, which is reflected on our accompanying consolidated statements of stockholders’ equity for the three and nine months ended September 30, 2022. We continue to own a 25.5% interest in and operate ELC. See Note 2 “~~Acquisitions and Divestitures” for additional information regarding ELC.~~

~~North American Natural Resources Acquisition~~

On August 11, 2022, we completed the acquisition of seven landfill assets from North American Natural Resources, Inc. and, its sister companies, North American Biofuels, LLC and North American-Central, LLC (NANR) consisting of gas-to-power facilities in Michigan and Kentucky for $132 million, including a preliminary purchase price adjustment for working capital. We plan to convert three of the seven gas-to-power facilities to renewable natural gas facilities with a capital spend of approximately $145 million. We expect these facilities to be in service by mid-2024 and, once complete, are expected to generate approximately 1.7 Bcf per year of renewable natural gas. The remaining four NANR assets, projected to produce 8.0 megawatt-hours in 2023 ~~further diversify KMI’s renewable portfolio by adding electricity generation to its landfill gas-to-power operations.~~

~~Mas CanAm Acquisition~~

On July 19, 2022, we completed an acquisition of three 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 $358 million including a preliminary purchase price adjustment for working capital. The Arlington facility is expected to produce 1.4 Bcf of renewable natural gas in 2023 and has the potential to grow significantly over the next decade.

~~2022~~ Dividends and Discretionary Capital

We expect to declare dividends of ~~$1.11~~$1.13 per share for ~~2022,~~2023, a 3%2% increase from the ~~2021~~2022 declared dividends of ~~$1.08~~$1.11 per share. We ~~now~~ expect to invest ~~$1.8~~$2.2 billion in expansion projects, acquisitions, and contributions to joint ventures ~~or discretionary capital expenditures~~ during ~~2022.~~2023.

The expectations for ~~2022~~2023 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~~Net income attributable to Kinder Morgan, Inc. and Segment EBDA (as presented in Note 87 “Reportable Segments”) ~~and Net income 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~~ months ended ~~September 30,~~March 31, 2023 and 2022 ~~and 2021~~ present ~~Segment EBDA and~~ Net income attributable to Kinder Morgan, Inc. ~~which are~~, as prepared and presented in accordance with ~~GAAP.~~GAAP, and Segment EBDA, which is disclosed in Note 7 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. 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 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~~our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its ~~decision making~~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 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~~most cases 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~~(See the tables included in~~“—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,”~~ “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. ~~(GAAP)~~ to Adjusted ~~EBITDA”~~Earnings,” “—Non-GAAP Financial Measures—Reconciliation of Net Income

Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—~~Supplemental Information”~~Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). ~~In addition,~~We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the three months ended March 31, 2023 and 2022, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.


	Three Months Ended March 31,
	2023		2022
	(In millions)
Certain Items
Fair value amortization	$	(4)	$	(4)

Change in fair value of derivative contracts(a)	(68)		82
Loss on impairment	67		—

Income tax Certain Items(b)	1		(20)
Other	—		7
Total Certain Items(c)(d)	$	(4)	$	65

(a)Gains or losses are reflected when realized.

(b)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.

(c)~~“—DD&A, General~~2023 and ~~Administrative~~2022 amounts include the following amounts included within “Earnings from equity investments” on our accompanying consolidated statements of income: (i) $(2) million and ~~Corporate Charges, Interest, net,~~$5 million, respectively, included within “Change in fair value of derivative contracts” and ~~Noncontrolling Interests”~~(ii) for the 2023 period only, $67 million included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 2 “Losses on Impairments ~~below.~~—Impairments”).

(d)2023 and 2022 amounts include, in the aggregate, $(8) million and $(44) million, respectively, included within “Interest, net” on the accompanying consolidated statements of income which consist of $(4) million in each period of “Fair value amortization” and $(4) million and $(40) million, respectively, of “Change in fair value of derivative contracts.”

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us, investors and ~~certain~~other external users of our financial statements ~~to assess the earnings of~~as a supplemental measure that provides decision-useful information regarding our ~~business excluding Certain Items as another reflection of our~~period-over-period performance and ability to generate ~~earnings.~~earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income 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 per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. ~~(GAAP)~~ to Adjusted ~~Earnings to DCF”~~Earnings” below.

DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, ~~(Adjusted Earnings),~~ and further byfor DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also ~~include~~adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure ~~useful to management~~used by us, investors and other external users of our financial statements ~~in evaluating~~to evaluate our performance and ~~in measuring~~to measure and ~~estimating~~estimate the ability of our assets to generate ~~cash~~economic earnings after ~~servicing our debt,~~paying interest expense, paying cash taxes and expending sustaining ~~capital, that could be~~capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for ~~discretionary~~ purposes ~~such as dividends, stock repurchases, retirement~~ of ~~debt, or expansion capital expenditures.~~annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. 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 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 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.

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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, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate ~~cash~~ earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. 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~~Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment ~~EBDA by business segment.~~EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting ~~EBITDA~~Net income attributable to Kinder Morgan, Inc. for Certain ~~Items.~~Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. 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, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate ~~certain leverage metrics. Therefore, we believe~~our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is ~~useful to investors.~~used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—~~Adjusted Segment EBDA to Adjusted EBITDA to DCF”~~ ~~and~~ ~~“—Non-GAAP Financial Measures—~~Reconciliation of Net Income 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.~~subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—~~Supplemental Information”~~Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” 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 30, 2022,~~March 31, 2023, by subtracting the following amounts from our debt balance of ~~$31,741~~$31,506 million: (i) cash and cash equivalents of ~~$483~~$416 million; ~~and~~ (ii) debt fair value adjustments of ~~$107~~$207 million; and ~~excluding~~(iii) the foreign exchange impact on Euro-denominated bonds of ~~$(53)~~$(1) million ~~for~~for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that ~~management believes~~ is ~~useful to~~used by management, investors and other external users of our financial information ~~in evaluating~~to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is ~~debt net of cash and cash equivalents.~~total debt.

3429

Consolidated Earnings Results ~~(GAAP)~~

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

Three Months Ended
September 30,
2022 2021 Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines $ 1,135 $ 1,069 $ 66 6%
Products Pipelines 257 279 (22) (8)%
Terminals 240 216 24 11%
CO2
215 163 52 32%
Total Segment EBDA 1,847 1,727 120 7%
DD&A (551) (526) (25) (5)%
Amortization of excess cost of equity investments (19) (21) 2 10%
General and administrative and corporate charges (149) (167) 18 11%
Interest, net (399) (368) (31) (8)%
Income before income taxes 729 645 84 13%
Income tax expense (134) (134) — —%
Net income 595 511 84 16%
Net income attributable to noncontrolling interests (19) (16) (3) (19)%
Net income attributable to Kinder Morgan, Inc. $ 576 $ 495 $ 81 16%


	Three Months Ended March 31,
	2023		2022		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	3,888	$	4,293	$	(405)	(9)	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(1,215)		(1,894)		679		36	%
Operations and maintenance	(639)		(585)		(54)		(9)	%
DD&A	(565)		(538)		(27)		(5)	%
General and administrative	(166)		(156)		(10)		(6)	%
Taxes, other than income taxes	(110)		(111)		1		1	%
Gain on divestitures and impairments, net	—		10		(10)		(100)	%
Other income, net	1		5		(4)		(80)	%
Total Operating Costs, Expenses and Other	(2,694)		(3,269)		575		18	%
Operating Income	1,194		1,024		170		17	%
Other Income (Expense)
Earnings from equity investments	165		187		(22)		(12)	%
Amortization of excess cost of equity investments	(17)		(19)		2		11	%
Interest, net	(445)		(333)		(112)		(34)	%
Other, net	2		19		(17)		(89)	%
Total Other Expense	(295)		(146)		(149)		(102)	%
Income Before Income Taxes	899		878		21		2	%
Income Tax Expense	(196)		(194)		(2)		(1)	%
Net Income	703		684		19		3	%
Net Income Attributable to Noncontrolling Interests	(24)		(17)		(7)		(41)	%
Net Income Attributable to Kinder Morgan, Inc.	$	679	$	667	$	12	2	%
Basic and diluted earnings per share	$	0.30	$	0.29	$	0.01	3	%
Basic and diluted weighted average shares outstanding	2,247		2,267		(20)		(1)	%
Declared dividends per share	$	0.2825	$	0.2775	$	0.005	2	%

Nine Months Ended
September 30,
2022 2021 Earnings
increase/(decrease)
(In millions, except percentages)
Segment EBDA(a)
Natural Gas Pipelines $ 3,453 $ 2,602 $ 851 33 %
Products Pipelines 855 792 63 8 %
Terminals 731 689 42 6 %
CO2
619 599 20 3 %
Total Segment EBDA 5,658 4,682 976 21 %
DD&A (1,632) (1,595) (37) (2) %
Amortization of excess cost of equity investments (57) (56) (1) (2) %
General and administrative and corporate charges (438) (465) 27 6 %
Interest, net (1,087) (1,122) 35 3 %
Income before income taxes 2,444 1,444 1,000 69 %
Income tax expense (512) (248) (264) (106) %
Net income 1,932 1,196 736 62 %
Net income attributable to noncontrolling interests (54) (49) (5) (10) %
Net income attributable to Kinder Morgan, Inc. $ 1,878 $ 1,147 $ 731 64 %
Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable three-month periods ended March 31, 2023 and 2022:

Revenues

Revenues decreased $405 million in 2023 compared to 2022. The decrease was primarily due to lower commodity sales driven by lower commodity prices and volumes.

Operating Costs, Expenses and Other

Costs of sales

Costs of sales decreased $679 million in 2023 compared to 2022. The decrease was primarily due to lower commodity prices and volumes. The decrease was further impacted by the period-over-period change related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity purchases.

Other Income (Expense)

Interest, net

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 interest expense, net increased $112 million in 2023 compared to 2022. The increase was primarily due to higher realized SOFR rates associated with interest rate swaps and changes in fair value of interest rate swaps.

Non-GAAP Financial Measures

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings


	Three Months Ended March 31,
		2023		2022
		(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.		$	679	$	667
Certain Items(a)
Fair value amortization		(4)		(4)

Change in fair value of derivative contracts		(68)		82
Loss on impairment		67		—

Income tax Certain Items		1		(20)
Other		—		7
Total Certain Items		(4)		65
Adjusted Earnings		$	675	$	732

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF

Net income attributable to Kinder Morgan, Inc.		$	679	$	667








Total Certain Items(b)		(4)		65
DD&A		565		538
Amortization of excess cost of equity investments		17		19
Income tax expense(c)		195		214
Cash taxes		(1)		(1)
Sustaining capital expenditures		(156)		(115)
Amounts from joint ventures
Unconsolidated joint venture DD&A		81		77
Remove consolidated joint venture partners’ DD&A		(16)		(11)
Unconsolidated joint venture income tax expense(d)(e)		26		21
Unconsolidated joint venture cash taxes(d)		—		—
Unconsolidated joint venture sustaining capital expenditures		(29)		(12)
Remove consolidated joint venture partners’ sustaining capital expenditures		2		2
Other items(f)		15		(9)
DCF		$	1,374	$	1,455

Adjusted Earnings per share		$	0.30	$	0.32
Weighted average shares outstanding for dividends(g)		2,260		2,280
DCF per share		$	0.61	$	0.64
Declared dividends per share		$	0.2825	$	0.2775

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings” for a detailed listing.

(c)To avoid duplication, 2023 and 2022 adjustments for income tax expense exclude $1 million and $(20) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(d)Associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments.

(e)Includes the tax provision on Certain Items recognized by the investees that are taxable entities. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

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

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

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA


	Three Months Ended March 31,
		2023		2022
		(In millions)
Net income attributable to Kinder Morgan, Inc.		$	679	$	667
Certain Items(a)
Fair value amortization		(4)		(4)

Change in fair value of derivative contracts		(68)		82
Loss on impairment		67		—

Income tax Certain Items		1		(20)
Other		—		7
Total Certain Items		(4)		65
DD&A		565		538
Amortization of excess cost of equity investments		17		19
Income tax expense(b)		195		214
Interest, net(c)		453		377
Amounts from joint ventures
Unconsolidated joint venture DD&A		81		77
Remove consolidated joint venture partners’ DD&A		(16)		(11)
Unconsolidated joint venture income tax expense(d)		26		21
Adjusted EBITDA		$	1,996	$	1,967

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(b)To avoid duplication, 2023 and 2022 adjustments for income tax expense exclude $1 million and $(20) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(c)To avoid duplication, 2023 and 2022 adjustments for interest, net exclude $(8) million and $(44) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.

(d)Includes that tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.

Below is a discussion of significant changes in our Adjusted Earnings, DCF and Adjusted EBITDA for the comparable three-month periods ended March 31, 2023 and 2022:


Change from prior period	Increase/(Decrease)
	(In millions)
Adjusted Earnings	$	(57)
DCF	$	(81)
Adjusted EBITDA	$	29

Adjusted Earnings decreased $57 million in 2023 compared to 2022 and was driven by an increase in interest expense partially offset by favorable margins primarily from our Natural Gas Pipelines business segment. These items also affected DCF. The $81 million decrease in DCF in 2023 compared to 2022 was further impacted by an increase in sustaining capital expenditures. Adjusted EBITDA increased $29 million in 2023 compared to 2022, which was also driven by favorable margins from our Natural Gas Pipelines business segment.

General and Administrative and Corporate Charges


	Three Months Ended March 31,				Earnings increase/(decrease)
	2023		2022
	(In millions, except percentages)
General and administrative	$	(166)	$	(156)	$	(10)	(6)	%
Corporate (charges) benefit	(13)		11		(24)		(218)	%

General and administrative and corporate charges	$	(179)	$	(145)	$	(34)	(23)	%

We had unfavorable changes of $10 million in general and administrative expenses and $24 million in our corporate (charges) benefit for the three months ended March 31, 2023 when compared with the respective prior year period. The combined changes were primarily due to higher pension costs of $22 million and higher labor and benefit-related costs of $9 million.

Reconciliation of Segment EBDA to Adjusted Segment EBDA


	Three Months Ended March 31,
	2023		2022
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA	$	1,495	$	1,184
Certain Items(b)

Change in fair value of derivative contracts	(65)		106

Other	—		7

Natural Gas Pipelines Adjusted Segment EBDA	$	1,430	$	1,297

Products Pipelines Segment EBDA	$	184	$	299
Certain Items(b)
Loss on impairment	67		—

Products Pipelines Adjusted Segment EBDA	$	251	$	299

Terminals Segment EBDA	$	254	$	238






CO2 Segment EBDA	$	172	$	192
Certain Items(b)
Change in fair value of derivative contracts	1		16


CO2 Adjusted Segment EBDA	$	173	$	208

~~Net income attributable to Kinder Morgan, Inc.~~ See “~~increased $81 million and $731 million for th~~—Overview—GAAP Financial Measures~~e three and nine months ended September 30, 2022, respectively, as compared to the respective prior year periods. The third quarter increase was~~

~~primarily due to higher earnings from our Natural Gas Pipelines and~~ CO2 business segments. The year-to-date increase was primarily due to the $1,600 million pre-tax non-cash impairment loss in 2021 related to South Texas gathering and processing assets within our Natural Gas Pipeline segment and ~~higher earnings from our Products Pipelines business segment with our West Coast Refined Products and Southeast Refined Products assets pa~~rtially offset by the benefit in the 2021 period of $1,097 million for largely nonrecurring earnings related to the February 2021 winter storm, mostly impacting the earnings from our Natural Gas Pipelines and CO2 ~~business segments.~~

~~Certain Items Affecting Consolidated Earnings Results~~

Three Months Ended September 30,
2022 2021
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 1,135 $ 24 $ 1,159 $ 1,069 $ 21 $ 1,090 $ 69
Products Pipelines 257 — 257 279 1 280 (23)
Terminals 240 — 240 216 17 233 7
CO2
215 (20) 195 163 (9) 154 41
Total Segment EBDA(a) 1,847 4 1,851 1,727 30 1,757 94
DD&A and amortization of excess cost of equity investments (570) — (570) (547) — (547) (23)
General and administrative and corporate charges(a) (149) — (149) (167) — (167) 18
Interest, net(a) (399) 15 (384) (368) (8) (376) (8)
Income before income taxes 729 19 748 645 22 667 81
Income tax expense(b) (134) (20) (154) (134) (12) (146) (8)
Net income 595 (1) 594 511 10 521 73
Net income attributable to noncontrolling interests (19) — (19) (16) — (16) (3)
Net income attributable to Kinder Morgan, Inc. $ 576 $ (1) $ 575 $ 495 $ 10 $ 505 $ 70

Nine Months Ended September 30,
2022 2021
GAAP Certain Items Adjusted GAAP Certain Items Adjusted Adjusted amounts increase/(decrease) to earnings
(In millions)
Segment EBDA
Natural Gas Pipelines $ 3,453 $ 136 $ 3,589 $ 2,602 $ 1,646 $ 4,248 $ (659)
Products Pipelines 855 — 855 792 44 836 19
Terminals 731 — 731 689 17 706 25
CO2
619 (5) 614 599 (3) 596 18
Total Segment EBDA(a) 5,658 131 5,789 4,682 1,704 6,386 (597)
DD&A and amortization of excess cost of equity investments (1,689) — (1,689) (1,651) — (1,651) (38)
General and administrative and corporate charges(a) (438) — (438) (465) — (465) 27
Interest, net(a) (1,087) (46) (1,133) (1,122) (17) (1,139) 6
Income before income taxes 2,444 85 2,529 1,444 1,687 3,131 (602)
Income tax expense(b) (512) (35) (547) (248) (439) (687) 140
Net income 1,932 50 1,982 1,196 1,248 2,444 (462)
Net income attributable to noncontrolling interests(a) (54) — (54) (49) — (49) (5)
Net income attributable to Kinder Morgan, Inc. $ 1,878 $ 50 $ 1,928 $ 1,147 $ 1,248 $ 2,395 $ (467)

~~(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.~~” above.

(b)~~The combined net effect of the income tax~~ See “—Overview—Non-GAAP Financial Measures—Certain ~~Items represents the income tax provision on Certain Items plus discrete income tax items.~~

~~Net income attributable to Kinder Morgan, Inc. adjusted for Certain Items (Adjusted Earnings)~~ ~~increased by $70 million for the three months ended September 30, 2022 and decreased by $467 million for the nine months ended September 30, 2022 as compared to the respective prior year periods. The third quarter increase was primarily due to~~ ~~higher earnings from our Natural Gas Pipeline and CO~~2 ~~business segments.~~ ~~The year-to-date decrease was impacted b~~y lower earnings of $744 million from our Natural Gas Pipelines business segment’s Midstream region (primarily related to the February 2021 winter storm, and therefore largely nonrecurring) partially offset by lower income tax expense.

Items” above.

~~Non-GAAP Financial Measures~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP) $ 576 $ 495 $ 1,878 $ 1,147
Total Certain Items (1) 10 50 1,248
Adjusted Earnings(a) 575 505 1,928 2,395
DD&A and amortization of excess cost of equity investments for DCF(b) 647 612 1,897 1,854
Income tax expense for DCF(a)(b) 167 165 601 754
Cash taxes(b) (15) (12) (63) (56)
Sustaining capital expenditures(b) (243) (241) (581) (558)
Other items(c) (9) (16) (29) (22)
DCF $ 1,122 $ 1,013 $ 3,753 $ 4,367

~~Adjusted Segment EBDA to Adjusted EBITDA to DCF~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions, except per share amounts)
Natural Gas Pipelines $ 1,159 $ 1,090 $ 3,589 $ 4,248
Products Pipelines 257 280 855 836
Terminals 240 233 731 706
CO2
195 154 614 596
Adjusted Segment EBDA(a) 1,851 1,757 5,789 6,386
General and administrative and corporate charges(a) (149) (167) (438) (465)
Joint venture DD&A and income tax expense(a)(b) 90 84 262 270
Net income attributable to noncontrolling interests(a) (19) (16) (54) (49)
Adjusted EBITDA 1,773 1,658 5,559 6,142
Interest, net(a) (384) (376) (1,133) (1,139)
Cash taxes(b) (15) (12) (63) (56)
Sustaining capital expenditures(b) (243) (241) (581) (558)
Other items(c) (9) (16) (29) (22)
DCF $ 1,122 $ 1,013 $ 3,753 $ 4,367
Adjusted Earnings per share $ 0.25 $ 0.22 $ 0.85 $ 1.05
Weighted average shares outstanding for dividends(d) 2,267 2,279 2,275 2,278
DCF per share $ 0.49 $ 0.44 $ 1.65 $ 1.92
Declared dividends per share $ 0.2775 $ 0.27 $ 0.8325 $ 0.81

~~(a)Amounts are adjusted for Certain Items. See tables included in~~ ~~“—Reconciliation of Net Income 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.~~

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

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions)
Net income attributable to Kinder Morgan, Inc. (GAAP) $ 576 $ 495 $ 1,878 $ 1,147
Certain Items:
Fair value amortization (4) (7) (11) (15)
Legal, environmental and taxes other than income tax reserves 23 — 23 112
Change in fair value of derivative contracts(a) (6) 22 49 64
Loss on impairments, divestitures and other write-downs, net(b) — 4 — 1,515
Income tax Certain Items (20) (12) (35) (439)
Other 6 3 24 11
Total Certain Items(c) (1) 10 50 1,248
DD&A and amortization of excess cost of equity investments 570 547 1,689 1,651
Income tax expense(d) 154 146 547 687
Joint venture DD&A and income tax expense(d)(e) 90 84 262 270
Interest, net(d) 384 376 1,133 1,139
Adjusted EBITDA $ 1,773 $ 1,658 $ 5,559 $ 6,142

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

~~(b)~~Nine months ended September 30, 2021 amount 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 reported within “(Gain) loss on divestitures and impairments, net” and a pre-tax gain of $206 million associated with the sale of a partial interest in our equity investment in NGPL Holdings LLC, offset partially by a write-down of $117 million on a long-term subordinated note receivable from an equity investee, Ruby, reported within “Other, net” and “Earnings from equity investments,” respectively, on the accompanying consolidated statement of income.

~~(c)Three months ended September 30, 2022 and 2021 amounts include less than $1 million and $2 million, res~~pectively, and nine months ended September 30, 2022 and 2021 amounts include $4 million and $129 million, respectively, reported within “Earnings from equity investments” on our consolidated statements of income.

~~(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.~~

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

~~Supplemental Information~~

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions)
DD&A (GAAP) $ 551 $ 526 $ 1,632 $ 1,595
Amortization of excess cost of equity investments (GAAP) 19 21 57 56
DD&A and amortization of excess cost of equity investments 570 547 1,689 1,651
Joint venture DD&A 77 65 208 203
DD&A and amortization of excess cost of equity investments for DCF $ 647 $ 612 $ 1,897 $ 1,854
Income tax expense (GAAP) $ 134 $ 134 $ 512 $ 248
Certain Items 20 12 35 439
Income tax expense(a) 154 146 547 687
Unconsolidated joint venture income tax expense(a)(b) 13 19 54 67
Income tax expense for DCF(a) $ 167 $ 165 $ 601 $ 754
Additional joint venture information
Unconsolidated joint venture DD&A $ 89 $ 76 $ 242 $ 236
Less: Consolidated joint venture partners’ DD&A 12 11 34 33
Joint venture DD&A 77 65 208 203
Unconsolidated joint venture income tax expense(a)(b) 13 19 54 67
Joint venture DD&A and income tax expense(a) $ 90 $ 84 $ 262 $ 270
Unconsolidated joint venture cash taxes(b) $ (12) $ (13) $ (51) $ (47)
Unconsolidated joint venture sustaining capital expenditures $ (38) $ (29) $ (89) $ (81)
Less: Consolidated joint venture partners’ sustaining capital expenditures (2) (2) (6) (5)
Joint venture sustaining capital expenditures $ (36) $ (27) $ (83) $ (76)

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

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

4034

Segment Earnings Results

Natural Gas Pipelines

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions, except operating statistics)
Revenues $ 3,505 $ 2,555 $ 9,674 $ 8,656
Operating expenses (2,548) (1,634) (6,706) (4,981)
Gain (loss) on divestitures and impairments, net 8 — 8 (1,599)
Other income — — 2 2
Earnings from equity investments 168 144 471 311
Other, net 2 4 4 213
Segment EBDA 1,135 1,069 3,453 2,602
Certain Items(a) 24 21 136 1,646
Adjusted Segment EBDA $ 1,159 $ 1,090 $ 3,589 $ 4,248
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ 69 $ (659)
Volumetric data(b)
Transport volumes (BBtu/d) 38,637 38,527 38,726 38,593
Sales volumes (BBtu/d) 2,469 2,616 2,521 2,480
Gathering volumes (BBtu/d) 3,179 2,808 2,999 2,662
NGLs (MBbl/d) 24 29 29 30

~~Certain Items affecting Segment EBDA~~


	Three Months Ended March 31,
		2023		2022
		(In millions, except operating statistics)
Revenues		$	2,466	$	2,813
Operating expenses		(1,177)		(1,784)

Other income		1		1
Earnings from equity investments		200		154

Other, net		5		—
Segment EBDA		1,495		1,184
Certain Items:
Change in fair value of derivative contracts		(65)		106
Other		—		7
Certain Items(a)		(65)		113
Adjusted Segment EBDA		$	1,430	$	1,297

Change from prior period		Increase/(Decrease)
Segment EBDA		$	311
Adjusted Segment EBDA		$	133

Volumetric data(b)
Transport volumes (BBtu/d)		40,400		39,319
Sales volumes (BBtu/d)		2,117		2,515
Gathering volumes (BBtu/d)		3,325		2,817
NGLs (MBbl/d)		35		32

(a)~~Three months ended September 30, 2022 amount includes a~~See table included in “~~n increase in revenues~~—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 Certain Items of ~~$51~~$(63) million and ~~an increase in costs~~$(2) million are associated with our Midstream and East businesses, respectively. 2022 Certain Items of ~~sales of $47~~$101 million, $7 million and ~~nine months ended September 30, 2022 amount includes an increase in revenues of $48~~$5 million ~~and an increase in costs of sales of $133 million rel~~ated to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales and purchases. Three and nine months ended September 30, 2022 amounts also include an increase in other operating expenses of $23 million related to a certain litigation matter and ~~$6 million and $24~~ ~~million, respectively, related to costs~~are associated with ~~a pipeline rupture. Three~~our Midstream, West and ~~nine months ended September 30, 2021 amounts include decreases~~East businesses, respectively. For more detail of significant Certain Items, see the discussion of changes in revenues of $14 million and $36 million, respectively, related to non-cash mark-to-market derivative contracts used to hedge forecasted natural gas and NGL sales. Nine months ended September 30, 2021 amount also includes a pre-tax non-cash asset impairment loss of $1,600 million related to our South Texas gathering and processing assets, 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.Segment EBDA below.

~~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, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition.~~presented.

4135

Below are the changes in ~~Adjusted~~ Segment EBDA in the comparable ~~three and nine-month~~three-month periods ended ~~September 30, 2022~~March 31, 2023 and ~~2021:~~2022:

Three Months Ended ~~September 30, 2022~~March 31, 2023 versus Three Months Ended ~~September 30, 2021~~March 31, 2022

Adjusted Segment EBDA
2022 2021 increase/
(decrease)
Midstream $ 351 $ 289 $ 62
East 595 577 18
West 213 224 (11)
Total Natural Gas Pipelines $ 1,159 $ 1,090 $ 69

~~Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021~~


		Adjusted Segment EBDA							2023		2022		increase/ (decrease)
		2022		2021		increase/ (decrease)			(In millions)
Midstream	Midstream	$	1,063	$	1,807	$	(744)	Midstream	$	540	$	283	$	257
East	East	1,846		1,706		140		East	696		647		49
West	West	680		735		(55)		West	259		254		5

Total Natural Gas Pipelines		$	3,589	$	4,248	$	(659)
Total Natural Gas Pipelines Segment EBDA								Total Natural Gas Pipelines Segment EBDA	$	1,495	$	1,184	$	311

The changes in Segment EBDA for our Natural Gas Pipelines business segment in the comparable three-month periods ended March 31, 2023 and 2022 are ~~further~~ explained by the following ~~discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:~~discussion:

•~~$62~~A $257 million ~~(21%~~(91%) increase in Midstream was affected by period-over-period decreases in costs of sales and, ~~$744 million (41%) decrease, respectively,~~to a lesser extent, in ~~Midstream. The third quarter increase~~revenues related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which we treated as Certain Items.

In addition, Midstream was ~~primarily due to~~ favorably impacted by~~higher volumes on our KinderHawk assets,~~ higher sales ~~margins due to higher prices~~margins on our Texas intrastate natural gas pipeline operations ~~and~~ ~~Altamont asset.~~ ~~The year-to-date decrease was primarily due to lower sales margins of $840 million on our Texas intrastate natural gas pipeline operations and $65 million on our South Texas assets~~ largely driven by ~~higher 2021 commodity prices related to the February 2021 winter storm. These decreases were partially~~realized gains on sales hedges partially offset by lower sales volumes, higher volumes on our KinderHawk assets and higher ~~NGL~~gas sales margins driven by higher weather-related prices on our Altamont asset, partially offset by lower deficiency revenues and ~~higher earnings on our Oklahoma assets from higher 2021 commodity prices on certain purchase contracts~~lower service fee revenues as a result of ~~the February 2021 winter storm.~~a renegotiated contract at a lower price on our South Texas assets. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of ~~sales;~~sales.

•~~$18 million (3%) and $140~~A $49 million (8%) ~~increases, respectively,~~increase in the East Region ~~were~~was primarily due to higher ~~capacity sales associated with our Stagecoach assets, higher~~ equity earnings from ~~SNG~~Midcontinent Express Pipeline LLC, driven by new customer contracts entered into in the later part of 2022, and higher revenues as a result of increased ~~revenues~~demand in park and loan services due to favorable pricing on our Stagecoach assets.

•A $5 million (2%) increase in the West Region was primarily due to higher earnings from EPNG due to an increase in ~~demand for services~~gas sales margin and ~~increased earnings from Kinder Morgan Louisiana Pipeline, LLC reflecting~~the return of a ~~new LNG customer contract~~pipeline to service, partially offset by ~~decreased earnings on TGP driven by higher operating expenses~~lower revenues from Cheyenne Plains Gas Pipeline Company, L.L.C. due to the expiration of a customer contract in ~~part to higher~~December 2022 ~~property taxes~~ and ~~pipeline integrity costs. The year-to-date increase was further impacted by our July 2021 acquisition of the Stagecoach assets; and~~

•lower revenues from Col~~$11 million (5%) and $55 million (7%) decreases, respectively, in the West Region were primarily due~~ ~~to lower earnings from Colorado~~orado Interstate Gas Company, L.L.C. ~~driven by lower revenues~~and Wyoming Interstate Company, L.L.C. resulting from a rate case ~~settleme~~settlements effective April 2022.

~~nt and a decrease in revenues from EPNG driven by lower commodity and park and loan volumes that resulted from~~ ~~a partial pipeline outage.~~

4236

Products Pipelines

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions, except operating statistics)
Revenues $ 872 $ 605 $ 2,634 $ 1,572
Operating expenses (632) (341) (1,846) (828)
Gain on divestitures and impairments, net — — 12 —
Earnings from equity investments 17 15 55 48
Segment EBDA 257 279 855 792
Certain Items(a) — 1 — 44
Adjusted Segment EBDA $ 257 $ 280 $ 855 $ 836
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ (23) $ 19
Volumetric data(b)
Gasoline(c) 989 1,023 982 987
Diesel fuel 368 389 370 395
Jet fuel 278 250 262 217
Total refined product volumes 1,635 1,662 1,614 1,599
Crude and condensate 467 491 477 503
Total delivery volumes (MBbl/d) 2,102 2,153 2,091 2,102

~~Certain Items affecting Segment EBDA~~


	Three Months Ended March 31,
		2023		2022
		(In millions, except operating statistics)
Revenues		$	668	$	766
Operating expenses		(440)		(497)
Gain on divestitures and impairments, net		—		12

(Loss) earnings from equity investments		(44)		18


Segment EBDA		184		299
Certain Items:
Loss on impairment		67		—
Certain Items(a)		67		—
Adjusted Segment EBDA		$	251	$	299

Change from prior period		Increase/(Decrease)
Segment EBDA		$	(115)
Adjusted Segment EBDA		$	(48)

Volumetric data(b)
Gasoline(c)		948		940
Diesel fuel		328		369
Jet fuel		271		242
Total refined product volumes		1,547		1,551
Crude and condensate		460		486
Total delivery volumes (MBbl/d)		2,007		2,037

(a)~~Nine months ended September 30, 2021 amount includes increases~~See table included in ~~expenses~~“—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 Certain Item of ~~$28~~$67 million is associated with our Crude and ~~$15 million related to a litigation reserve and an environmental reserve adjustment, respectively.~~Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

~~Other~~

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

(c)Volumes include ethanol pipeline volumes.

Below are the changes in ~~Adjusted~~ Segment EBDA in the comparable ~~three and nine-month~~three-month periods ended ~~September 30, 2022~~March 31, 2023 and ~~2021:~~2022:

Three Months Ended ~~September 30, 2022~~March 31, 2023 versus Three Months Ended ~~September 30, 2021~~March 31, 2022

Adjusted Segment EBDA
2022 2021 increase/
(decrease)
Crude and Condensate $ 72 $ 85 $ (13)
Southeast Refined Products 57 64 (7)
West Coast Refined Products 128 131 (3)
Total Products Pipelines $ 257 $ 280 $ (23)

~~Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021~~


		Adjusted Segment EBDA							2023		2022		increase/ (decrease)
		2022		2021		increase/ (decrease)			(In millions)
Crude and Condensate	Crude and Condensate	$	250	$	269	$	(19)	Crude and Condensate	$	5	$	89	$	(84)
West Coast Refined Products								West Coast Refined Products	108		137		(29)
Southeast Refined Products	Southeast Refined Products	209		198		11		Southeast Refined Products	71		73		(2)
West Coast Refined Products		396		369		27

Total Products Pipelines		$	855	$	836	$	19
Total Products Pipelines Segment EBDA								Total Products Pipelines Segment EBDA	$	184	$	299	$	(115)

The changes in Segment EBDA for our Products Pipelines business segment in the comparable three-month periods ended March 31, 2023 and 2022 are ~~further~~ explained by the following ~~discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:~~discussion:

•~~$13~~An $84 million ~~(15%~~(94%) ~~and $19 million (7%) decreases, respectively,~~decrease in Crude and Condensate ~~were~~was ~~primarily due~~affected by a $67 million reduction to equity earnings for a non-cash impairment related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.

In addition, Crude and Condensate was unfavorably impacted by lower earnings from ~~our Bakken Crude assets due to~~ lower volumes ~~from~~on our Double H pipeline ~~and an unfavorable inventory valuation adjustment due to a decline in commodity prices~~ and from our Kinder Morgan Crude & Condensate pipeline driven primarily by a decrease in revenues as a result of re-contracting at lower rates and lower deficiency ~~revenues, partially offset by higher earnings from our KM Condensate Processing facility reflecting increased revenues due to higher volumes and rate escalations.~~revenues. Our Crude and Condensate ~~pipeline~~business also had ~~higher~~lower revenues ~~of $209 million and $832 million, respectively,~~ with a corresponding ~~increases~~decrease in ~~cost~~costs of sales, resulting from ~~increased marketing activities;~~decreased commodity pricing.

•$7A $29 million ~~(11%~~(21%) decrease in West Coast Refined Products was primarily due to lower earnings on our Pacific operations resulting from net changes in product gains and ~~$11~~losses affecting operating costs and a gain on sale of land in the 2022 period at Calnev.

•A $2 million ~~(6%~~(3%) ~~increase, respectively,~~decrease in Southeast Refined ~~Products.~~Products ~~The third quarter decrease~~ was primarily due to lower earnings at our Transmix processing operations as a result of an unfavorable inventory valuation adjustment due to a decline in commodity prices. The year-to-date increase was primarily due to higher earnings at our Transmix processing operations primarily due to higher prices and volumes; and

•~~$3 million (2%) decrease and $27 million (7%) increase, respectively, in West Coast Refined Products. The third quarter decrease was~~ primarily due to lower ~~earnings on our Pacific operations (SFPP) as a result of higher integrity management spending and lower revenues due to an overall decrease in volumes~~prices, partially offset by ~~an increase in regulated rates. The year-to-date increase was primarily due to a gain on sale of land at Calnev Pipe Line LLC, increased earnings driven by~~ higher ~~revenues on our West Coast terminals from higher volume~~svolumes and SF~~PP resulting from higher revenues driven by increased regulatory rates.~~rate escalations across numerous assets.

Terminals

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions, except operating statistics)
Revenues $ 457 $ 422 $ 1,337 $ 1,275
Operating expenses (222) (200) (637) (588)
(Loss) gain on divestitures and impairments, net
— (14) 9 (14)
Other income 1 4 5 4
Earnings from equity investments 3 3 11 10
Other, net 1 1 6 2
Segment EBDA 240 216 731 689
Certain Items(a) — 17 — 17
Adjusted Segment EBDA $ 240 $ 233 $ 731 $ 706
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ 7 $ 25
Volumetric data(b)
Liquids leasable capacity (MMBbl) 78.9 79.0 78.9 79.0
Liquids utilization %(c) 91.1 % 94.7 % 91.1 % 94.7 %
Bulk transload tonnage (MMtons) 13.4 13.4 40.0 37.9

~~Certain Items affecting Segment EBDA~~


	Three Months Ended March 31,
		2023			2022
		(In millions, except operating statistics)
Revenues		$	461		$	430
Operating expenses		(210)			(199)
Loss on divestitures and impairments, net		—			(3)
Other income		—			4
Earnings from equity investments		2			4
Other, net		1			2
Segment EBDA		$	254		$	238



Change from prior period		Increase/(Decrease)
Segment EBDA		$	16


Volumetric data(a)
Liquids leasable capacity (MMBbl)		78.3			78.2
Liquids leased capacity %(b)		92.8		%	90.6		%
Bulk transload tonnage (MMtons)		13.4			13.0

(a)~~Three and nine months ended September 30, 2021 amounts each include a pre-tax non-cash impairment loss of $14 million related to the reclassification of an asset to held for sale.~~

~~Other~~

~~(b)~~Volumes for facilities divested, idled and/or held for sale are excluded for all periods presented.

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

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~~business grouping below and included within the All others group.

Below are the changes in ~~Adjusted~~ Segment EBDA in the comparable ~~three and nine-month~~three-month periods ended ~~September 30, 2022~~March 31, 2023 and ~~2021:~~2022:

Three Months Ended ~~September 30, 2022~~March 31, 2023 versus Three Months Ended ~~September 30, 2021~~March 31, 2022

Adjusted Segment EBDA
2022 2021 increase/
(decrease)
Mid Atlantic $ 30 $ 15 $ 15
Gulf Central 35 31 4
Gulf Liquids 65 76 (11)
Northeast 22 25 (3)
Marine operations 34 37 (3)
All others (including intrasegment eliminations) 54 49 5
Total Terminals $ 240 $ 233 $ 7

~~Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021~~


		Adjusted Segment EBDA							2023		2022		increase/ (decrease)
		2022		2021		increase/ (decrease)			(In millions)
Gulf Central								Gulf Central	$	38	$	32	$	6
Marine operations								Marine operations	41		38		3
Mid Atlantic	Mid Atlantic	$	77	$	47	$	30	Mid Atlantic	26		23		3
Gulf Central		102		83		19
Gulf Liquids		217		220		(3)
Northeast	Northeast	67		80		(13)		Northeast	25		22		3
Marine operations		105		117		(12)

All others (including intrasegment eliminations)	All others (including intrasegment eliminations)	163		159		4		All others (including intrasegment eliminations)	124		123		1
Total Terminals		$	731	$	706	$	25
Total Terminals Segment EBDA								Total Terminals Segment EBDA	$	254	$	238	$	16

The changes in Segment EBDA for our Terminals business segment in the comparable three-month periods ended March 31, 2023 and 2022 are ~~further~~ explained by the following ~~discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:~~discussion:

•~~$15~~A $6 million ~~(100%~~(19%) increase in the Gulf Central terminals was primarily due to higher revenues resulting from contractual rate escalationsand ~~$30~~higher volumes for petroleum coke handling activities.

•A $3 million ~~(64%~~(8%) ~~increases, respectively,~~increase in Marine operations was primarily due to higher average charter rates.

•A $3 million (13%) increase in the Mid Atlantic terminals wewasre primarily due to higher revenues resulting from increased effective handling rates ~~and~~on export coal volumes at our Pier IX ~~facility;~~facility.

•~~$4 million (13%) and $19 million (23%) increases, respectively, in the Gulf Central terminals were primarily due to~~ lower property tax expense at our Battleground Oil Specialty Terminal Company LLC. The year-to-date increase was also impacted by higher volumes for petroleum coke handling activities, owing largely to refinery outages in the 2021 period associated with the February 2021 winter storm;

•~~$11~~A $3 million (14%) ~~and $3 million (1%) decreases, respectively, in the Gulf Liquids~~ ~~region were primarily~~ ~~due to higher property tax expense at Pasadena and Galena Park terminals.~~ ~~The year-to-date decrease was partially offset by~~ ~~increased revenues from contractual rate escalations and higher volumes and associated ancillary fees;~~

•~~$3 million (12%) and $13 million (16%) decreases, respectively,~~increase in the Northeast terminals ~~were~~was primarily driven by in~~decreased~~creased revenues associated with ~~lower~~higher utilization ~~and rates on re-contracted tank positions~~ at our Carteret ~~and Perth Amboy facilities;~~ ~~and~~

•~~$3 million (8%) and $12 million (10%) decreases, respectively, in Marine operations were~~ ~~primarily due to lower average charter rates partially offset by higher fleet utilization.~~

facility.

4639

CO2

Three Months Ended
September 30, Nine Months Ended
September 30,
2022 2021 2022 2021
(In millions, except operating statistics)
Revenues $ 351 $ 257 $ 999 $ 729
Operating expenses (143) (112) (408) (161)
Gain on divestitures and impairments, net — 11 1 8
Earnings from equity investments 7 7 27 23
Segment EBDA 215 163 619 599
Certain Items(a) (20) (9) (5) (3)
Adjusted Segment EBDA $ 195 $ 154 $ 614 $ 596
Change from prior period Increase/(Decrease)
Adjusted Segment EBDA $ 41 $ 18
Volumetric data
SACROC oil production 19.9 20.1 19.6 19.9
Yates oil production 6.4 6.5 6.5 6.5
Katz and Goldsmith oil production 1.8 2.1 1.9 2.3
Tall Cotton oil production 1.0 1.1 1.0 1.0
Total oil production, net (MBbl/d)(b) 29.1 29.8 29.0 29.7
NGL sales volumes, net (MBbl/d)(b) 9.7 9.7 9.5 9.3
CO2 sales volumes, net (Bcf/d)
0.3 0.4 0.4 0.4
Realized weighted average oil price ($ per Bbl) $ 66.34 $ 53.03 $ 67.91 $ 52.21
Realized weighted average NGL price ($ per Bbl) $ 37.68 $ 28.01 $ 41.01 $ 23.73

~~Certain Items affecting Segment EBDA~~


	Three Months Ended March 31,
		2023		2022
		(In millions, except operating statistics)
Revenues		$	297	$	305
Operating expenses		(132)		(125)
Gain on divestitures and impairments, net		—		1

Earnings from equity investments		7		11

Segment EBDA		172		192
Certain Items:
Change in fair value of derivative contracts		1		16
Certain Items(a)		1		16
Adjusted Segment EBDA		$	173	$	208

Change from prior period		Increase/(Decrease)
Segment EBDA		$	(20)
Adjusted Segment EBDA		$	(35)

Volumetric data
SACROC oil production		18.90		19.27
Yates oil production		6.74		6.79
Other		2.61		2.91
Total oil production, net (MBbl/d)(b)		28.25		28.97
NGL sales volumes, net (MBbl/d)(b)		8.16		9.41

CO2 sales volumes, net (Bcf/d)		0.36		0.37
Realized weighted average oil price ($ per Bbl)		$	67.15	$	66.90
Realized weighted average NGL price ($ per Bbl)		$	34.06	$	43.68

(a)~~Three~~See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 and ~~nine months ended September 30,~~ 2022 ~~amounts include $(20) million~~Certain Items are associated with our Oil and ~~$(5) million, respectively, and three and nine months ended September 30, 2021 amounts include $1 million and $7 million, respectively,~~Gas Producing activities. For more detail of significant Certain Items, see the discussion of changes in ~~revenue related to non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales.~~Segment EBDA below.

~~Other~~

(b)Net of royalties and outside working interests.

Below are the changes in ~~Adjusted~~ Segment EBDA in the comparable ~~three and nine-month~~three-month periods ended ~~September 30, 2022~~March 31, 2023 and ~~2021:~~2022:

Three Months Ended ~~September 30, 2022~~March 31, 2023 versus Three Months Ended ~~September 30, 2021~~March 31, 2022


		Adjusted Segment EBDA							2023		2022		increase/ (decrease)
		2022		2021		increase/ (decrease)			(In millions)
Source and Transportation activities								Source and Transportation activities	$	49	$	62	$	(13)
Oil and Gas Producing activities	Oil and Gas Producing activities	$	132	$	63	$	69	Oil and Gas Producing activities	118		126		(8)
Source and Transportation activities		59		89		(30)

Subtotal	Subtotal	191		152		39		Subtotal	167		188		(21)
Energy Transition Ventures	Energy Transition Ventures	4		2		2		Energy Transition Ventures	5		4		1
Total CO2		$	195	$	154	$	41
Total CO2 Segment EBDA								Total CO2 Segment EBDA	$	172	$	192	$	(20)

~~Nine Months Ended September 30, 2022 versus Nine Months Ended September 30, 2021~~

Adjusted Segment EBDA
2022 2021 increase/
(decrease)
Oil and Gas Producing activities $ 410 $ 397 $ 13
Source and Transportation activities 190 197 (7)
Subtotal 600 594 6
Energy Transition Ventures 14 2 12
Total CO2
$ 614 $ 596 $ 18

The changes in Segment EBDA for our CO2 business segment in the comparable three-month periods ended March 31, 2023 and 2022 are ~~further~~ explained by the following ~~discussion of the significant factors driving Adjusted Segment EBDA in the comparable three and nine-month periods ended September 30, 2022 and 2021:~~discussion:

•~~$69 million (110%) and~~A $13 million ~~(3%~~(21%) ~~increases, respectively,~~decrease in Source and Transportation activities primarily due to higher operating expenses and a decrease in revenues related to lower CO2 sales prices and volumes.

•An $8 million (6%) decrease in Oil and Gas Producing activities primarily due to ~~higher~~a decrease in revenues related to lower realized NGL prices and lower NGL and crude oil ~~and NGL prices~~volumes which increased revenues by $44 million and $173 million, respectively and a third quarter 2021 settlement of $38 million for a terminated affiliate purchase contract with Source and Transportation activities. The year-to-date increase was ~~also impacted by higher operating expenses of $179 million mainly~~largely driven by ~~the benefit realized in the 2021 period from returning power to the grid by curtailing oil production during the February 2021 winter storm; and~~an extended outage at SACROC.

•
$30 million (34%) and $7 million (4%) decreases, respectively, in Source and Transportation activities primarily due to a third quarter 2021 settlement of $38 million for a terminated affiliate sales contract with

In addition, Oil and Gas Producing activities ~~offset~~was affected by ~~increased revenues of $12 million and $46 million, respectively, related to higher CO~~2 ~~sales prices. The year-to-date decrease was also impacted by decreased~~a favorable change period-over-period in revenues related to ~~lower CO~~2 ~~sales volumes.~~non-cash mark-to-market derivative hedge contracts which we treated as Certain Items.

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 a lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of ~~September 30, 2022:~~March 31, 2023:


		Remaining 2022		2023		2024		2025		2026			Remaining 2023		2024		2025		2026		2027
Crude Oil(a)	Crude Oil(a)											Crude Oil(a)
Price ($ per Bbl)	Price ($ per Bbl)	$	62.42	$	63.28	$	61.04	$	61.08	$	65.67	Price ($ per Bbl)	$	64.67	$	62.45	$	61.98	$	65.32	$	62.23
Volume (MBbl/d)	Volume (MBbl/d)	26.40		21.10		13.40		8.95		3.00		Volume (MBbl/d)	23.57		15.50		10.05		5.30		0.50
NGLs	NGLs											NGLs
Price ($ per Bbl)	Price ($ per Bbl)	$	56.02	$	61.39							Price ($ per Bbl)	$	55.11	$	36.23
Volume (MBbl/d)	Volume (MBbl/d)	4.57		2.04								Volume (MBbl/d)	3.82		0.04
Midland-to-Cushing Basis Spread	Midland-to-Cushing Basis Spread											Midland-to-Cushing Basis Spread
Price ($ per Bbl)	Price ($ per Bbl)	$	0.53	$	0.87							Price ($ per Bbl)	$	1.00	$	1.15
Volume (MBbl/d)	Volume (MBbl/d)	23.65		14.50								Volume (MBbl/d)	21.00		2.75
Argus Calendar Month Average Basis Spread												Argus Calendar Month Average Basis Spread
Price ($ per Bbl)												Price ($ per Bbl)	$	0.91	$	0.43
Volume (MBbl/d)												Volume (MBbl/d)	21.25		2.50

(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)
2022 2021
(In millions, except percentages)
DD&A (GAAP) $ (551) $ (526) $ (25) (5) %
General and administrative (GAAP) $ (162) $ (174) $ 12 7 %
Corporate benefit 13 7 6 86 %
Certain Items(a) — — — — %
General and administrative and corporate charges(b) $ (149) $ (167) $ 18 11 %
Interest, net (GAAP) $ (399) $ (368) $ (31) (8) %
Certain Items(c) 15 (8) 23 288 %
Interest, net(b) $ (384) $ (376) $ (8) (2) %
Net income attributable to noncontrolling interests (GAAP) $ (19) $ (16) $ (3) (19) %
Certain Items — — — — %
Net income attributable to noncontrolling interests(b) $ (19) $ (16) $ (3) (19) %

Nine Months Ended
September 30, Earnings
increase/(decrease)
2022 2021
(In millions, except percentages)
DD&A (GAAP) $ (1,632) $ (1,595) $ (37) (2) %
General and administrative (GAAP) $ (470) $ (490) $ 20 4 %
Corporate benefit 32 25 7 28 %
Certain Items(a) — — — — %
General and administrative and corporate charges(b) $ (438) $ (465) $ 27 6 %
Interest, net (GAAP) $ (1,087) $ (1,122) $ 35 3 %
Certain Items(c) (46) (17) (29) (171) %
Interest, net(b) $ (1,133) $ (1,139) $ 6 1 %
Net income attributable to noncontrolling interests (GAAP) $ (54) $ (49) $ (5) (10) %
Certain Items(d) — — — — %
Net income attributable to noncontrolling interests(b) $ (54) $ (49) $ (5) (10) %

~~Certain items~~

~~(a)Three and nine months ended September 30, 2022 amounts include less than $1 million of general and administrative and corporate charges associated with Certain Items.~~

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

~~(c)~~Three and nine months ended September 30, 2022 amounts include an increase of $19 million and a decrease of $35 million in interest expense, respectively, related to non-cash mismatches between the change in fair value of interest rate swaps and change in fair value of hedged debt, primarily related to our floating-to-fixed LIBOR interest rate swaps which are not designated as accounting hedges and decreases in expense of $4 million and $11 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions. Three and nine months September 30, 2021 amounts include decreases of $7 million and $15 million, respectively, related to non-cash debt fair value adjustments associated with acquisitions.

~~(d)Nine months ended September 30, 2021 amount includes 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 months ended September 30, 2022 when compared with the respective prior year periods decreased $18 million and $27 million, respectively, primarily due to higher capitalized costs of $10 million and $31 million, respectively, reflecting higher capital spending and lower benefit-related and pension costs of $5 million and $9 million, respectively, partially offset by $1 million and $12 million, respectively, of higher labor, travel and 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 months ended September 30, 2022 when compared with the respective prior year periods increased $8 million and decreased $6 million, respectively, primarily ~~due to lower long-term average interest rates and long-term debt balances, partially offset by higher short-term debt 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 30, 2022 and December 31, 2021, approximately ~~8% an~~d 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 September 30, 2022 rate was lower because we entered into variable-to-fixed interest rate hedges that expire at the end of 2022. Without those hedges, as of September 30, 2022, our debt subject to variable interest rates would have been approximately 24%. For more information on our interest rate swaps, see Note 6 “Risk Management—~~Interest Rate Risk Management” to our consolidated financial statements.~~

Net income attributable to noncontrolling interests represents the allocation of our consolidated net income attributable to all outstanding ownership interests in our consolidated subsidiaries that are not owned by us.

~~Income Taxes~~

Our tax expense for the three months ended September 30, 2022 was approximately $134 million as compared with $134 million for the same period of 2021. The tax expense was the same due primarily to federal taxes on higher pre-tax book income, partially offset by state income taxes as a result of the reduction of the state tax rate in current period.

Our tax expense for the nine months ended September 30, 2022 was approximately $512 million as compared with $248 million for the same period of 2021. The $264 million increase in tax expense was due primarily to federal and state taxes on higher pre-tax book income in the current year and the release of the valuation allowance on our investment in NGPL Holdings in the prior year.

On August 16, 2022, the U.S. government enacted the Inflation Reduction Act of 2022 (IRA) into law. The IRA includes a new corporate alternative minimum tax (Corporate AMT) of 15% on the adjusted financial statement income (AFSI) of corporations with average AFSI exceeding $1.0 billion over a three-year period. The Corporate AMT is effective for tax years beginning after December 31, 2022. We are evaluating the Corporate AMT and its potential impact on our current income tax expense and cash taxes. However, we currently do not believe this will have an impact on our cash taxes for the 2023 tax year.

Liquidity and Capital Resources

General

As of ~~September 30, 2022,~~March 31, 2023, we had ~~$483~~$416 million of “Cash and cash equivalents,” a decrease of ~~$657~~$329 million from December 31, ~~2021.~~2022. Additionally, as of ~~September 30, 2022,~~March 31, 2023, we had borrowing capacity of approximately $3.9 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 ~~$3,563~~$1,333 million and ~~$4,440~~$1,084 million in the first ~~nine~~three months of ~~2022~~2023 and ~~2021,~~2022, respectively. The period-to-period ~~decrease~~increase 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~~expansion capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any.

2022 includes $3,445 million and $1,250 million, respectively, of variable-to-fixed interest rate derivative contracts which expire in December 2023. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Our board of directors declared a quarterly dividend of ~~$0.2775~~$0.2825 per share for the ~~third~~first quarter of ~~2022, consistent with~~2023, a 2% increase over the dividend declared for the ~~previous quarter.~~first quarter of 2022.

On ~~February 23, 2022, EPNG issued in a private offering $300 million aggregate principal amount of 3.50% senior notes due 2032 and received net proceeds of $298 million after discount and issuance costs.~~

During the first quarter, upon maturity, we repaid ~~EPNG’s 8.625%~~our 3.15% senior notes, our ~~4.15% corporate~~floating rate senior notes and ~~the 1.50% series of~~ our ~~Euro denominated debt. During the second quarter 2022, we repaid $1 billion of our 3.95%~~3.45% senior ~~notes using short-term borrowings. The short-term borrowings were repaid in the third quarter 2022 with proceeds from the August 2022 senior note issuances.~~notes.

Short-term Liquidity

As of ~~September 30, 2022,~~March 31, 2023, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities with an available capacity of approximately $3.9 billion and an associated $3.5 billion commercial paper program. The loan commitments under our 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 and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of ~~September 30, 2022,~~March 31, 2023, our ~~$2,634~~$2,160 million of short-term debt consisted primarily of senior notes that mature in the next twelve months. We intend to fund our debt, as it becomes due, primarily through 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, ~~2021~~2022 was ~~$2,646~~$3,385 million.

We had working capital (defined as current assets less current liabilities) deficits of ~~$2,329~~$2,079 million and ~~$1,992~~$3,127 million as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, 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 ~~$337~~$1,048 million ~~unfavorable~~favorable change from year-end ~~2021~~2022 was primarily due to (i) a ~~$657~~$1,225 million decrease in senior notes that mature in the next twelve months; (ii) a $288 million decrease in other current liabilities, primarily related to reductions in property tax and bonus accruals and exchange gas payables; (iii) a $164 million decrease in accrued interest; and (iv) favorable short-term fair value adjustments on derivative contracts of $54 million; partially offset by (i) a $329 million decrease in cash and cash equivalents which ~~includes $1,190 million related~~was used to ~~repayments~~repay a portion of senior notes that matured in the first quarter of ~~2022 using cash on hand (while the change in our current maturities of senior notes remains flat);~~2023; (ii) ~~unfavorable short-term fair value adjustments on derivative contracts of $349 million; and (iii)~~ a ~~$58~~$162 million net unfavorable change in our accounts receivables and payables; ~~partially offset by (i)~~(iii) a ~~$233 million increase in restricted deposits related to our derivative activity; (ii) a $192~~$120 million decrease in ~~accrued contingencies; (iii)~~other current assets, primarily in exchange gas receivables and regulatory assets; and (iv) a ~~$177~~$45 million decrease in ~~accrued interest; and (iv) a $153 million increase in~~ inventories, primarily associated with gas in underground storage. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. ~~We also~~Additionally, we 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 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 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.follows:


Type of Expenditure						Physical Determination of Expenditure
Sustaining capital expenditures						•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)						•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements

Budgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those ~~maintenance~~sustaining 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~~sustaining 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~~occurs 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. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal, but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.

Generally, the determination of whether a capital expenditure is classified as ~~maintenance/~~sustaining or as expansion ~~capital expenditures~~ is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as ~~maintenance~~sustaining 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~~in calculating DCF, while those classified as ~~maintenance~~sustaining capital expenditures are.

Our capital expenditures for the ~~nine~~three months ended ~~September 30, 2022,~~March 31, 2023, and the amount we expect to spend for the remainder of ~~2022~~2023 to sustain our assets and ~~grow~~expand our business are as follows:

Nine Months Ended September 30, 2022 2022 Remaining Total 2022
(In millions)
Sustaining capital expenditures(a)(b) $ 581 $ 317 $ 898
Discretionary capital investments(b)(c)(d) 1,214 632 1,846


	Three Months Ended March 31, 2023		2023 Remaining		Total 2023
	(In millions)
Capital expenditures:
Sustaining capital expenditures	$	156	$	718	$	874
Expansion capital expenditures	368		1,617		1,985
Accrued capital expenditures, contractor retainage and other	(17)		—		—
Capital expenditures	$	507	$	2,335	$	2,859
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)	$	29	$	130	$	159
Investments in unconsolidated joint ventures(b)	44		200		244
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(9)		(11)

Accrued capital expenditures, contractor retainage and other	17		—		—
Total capital investments	$	595	$	2,656	$	3,251

(a)~~Nine months ended September 30, 2022, 2022 Remaining, and Total 2022 amounts include $83 million, $53 million, and $136 million, respectively, for sustaining~~Sustaining capital expenditures ~~from~~by our joint ventures generally do not require cash outlays by us.

(b)Reflects cash contributions to unconsolidated joint ~~ventures, reduced by consolidated~~ventures. Also includes contributions to an unconsolidated joint venture ~~partners’ sustaining capital expenditures. See table included in “~~that are netted within the amount the joint venture declares as a distribution to us.

~~—Results of Operations—Non-GAAP Financial Measures—Supplemental Information.~~”

5243

Our capital investments consist of the following:


	Three Months Ended March 31, 2023		2023 Remaining		Total 2023
	(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment	$	156	$	718	$	874
Sustaining capital expenditures of unconsolidated joint ventures(a)	29		130		159
Less: Consolidated joint venture partners’ sustaining capital expenditures	(2)		(9)		(11)
Total sustaining capital investments	183		839		1,022

Expansion capital investments
Capital expenditures for property, plant and equipment	368		1,617		1,985
Investments in unconsolidated joint ventures(b)	44		200		244

Total expansion capital investments	412		1,817		2,229
Total capital investments	$	595	$	2,656	$	3,251

(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.

(b)~~Nine months ended September 30, 2022 amount includes $15 million due to increases in accrued capital expenditures and contractor retainage and net changes in other.~~

~~(c)~~Nine months ended September 30, 2022 amount includes $63 million of our contributions to certain unconsolidated joint ventures for capital investments. Both Nine Months Ended September 30, 2022 and Total 2022 amounts also include $490 million for our acquisitions of Mas CanAm, LLC and NANR.

~~(d)Amounts include our actual or estimated~~Reflects cash contributions to unconsolidated joint ~~ventures, net of actual or estimated~~ventures. Also includes contributions ~~from certain partners in non-wholly owned consolidated subsidiaries for capital investments.~~to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

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, ~~2021~~2022 in our ~~2021~~2022 Form 10-K.

Commitments for the purchase of property, plant and equipment as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021~~2022 were ~~$556~~$322 million and ~~$209~~$527 million, respectively. The ~~increase~~decrease of ~~$347~~$205 million was primarily driven by ~~an overall increase of~~ capital ~~commitments.~~commitments related to our Terminals and Products Pipelines segments.

Cash Flows

The following table summarizes our net cash flows provided by (used in) operating, investing and financing activities between 2023 and 2022.


	Three Months Ended March 31,
	2023		2022		Changes
	(In millions)
Net Cash Provided by (Used in)
Operating activities	$	1,333	$	1,084	$	249
Investing activities	(508)		(371)		(137)
Financing activities	(1,181)		(1,512)		331

Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(356)	$	(799)	$	443

Operating Activities

~~Cash~~$249 million more cash provided by operating activities ~~decreased $877 million~~ in the ~~nine months~~comparable three-month periods ended ~~September 30,~~March 31, 2023 and 2022 ~~compared to~~is explained by the ~~respective 2021 period primarily due to:~~following discussion:

•a ~~$576~~$316 million ~~decrease in cash after adjusting the $736 million~~ increase in net income by $1,312 million for the combined effects of the period-to-period net changes in non-cash items. This overall cash decrease primarily resulted from the benefit recognized in the 2021 period for largely nonrecurring earnings related to the February 2021 winter storm (see discussion above in “—Results of Operations”); and

•~~a $301 million decrease~~ in cash associated with net changes in working capital items and other non-current assets and liabilities. The ~~decrease~~increase was primarily driven by ~~unfavorable~~(i) net favorable changes ~~due~~related to ~~(i) increases in our customer~~the timing of accounts ~~receivables~~receivable collections and trade payable payments, largely in our Natural Gas business ~~segment which was impacted by higher natural gas price increases in the 2022 period relative to the 2021 period;~~segment; and (ii) ~~higher inventories reflecting higher storage rates and increased volumes; and (iii)~~ a decrease in ~~reserves~~inventories primarily driven by higher settlements associated with ~~litigation matters~~commodity hedges related to gas in underground storage; partially offset by,

•a $67 million decrease in cash after adjusting the ~~2022 period compared with~~$19 million increase in net income by $86 million for the ~~2021 period.~~combined effects of the period-to-period net changes in non-cash items.

Investing Activities

~~Cash~~$137 million more cash used in investing activities ~~decreased $366 million for~~in the ~~nine months~~comparable three-month periods ended ~~September 30,~~March 31, 2023 and 2022 ~~compared to~~is explained by the ~~respective 2021 period primarily attributable to:~~following discussion:

•a $1,030 million decrease in expenditures for the acquisition of assets and investments, net of cash acquired, primarily driven by a combined $488 million of net cash used for our acquisitions of Mas CanAm, LLC and NANR in the 2022 period, compared with a combined $1,508 million of net cash used for the acquisitions of Stagecoach Gas Services LLC and Kinetrex Energy in the 2021 period; partially offset by,

•a $413 million decrease in proceeds from sales of investments primarily due to $412 million received from the sale of a partial interest in our equity investment in NGPL Holdings in the 2021 period; and

•~~a $250~~$100 million increase in capital expenditures ~~reflecting an overall increase of~~primarily driven by the expansion ~~capital~~ projects in ~~the 2022 period over the comparative 2021 period.~~our Natural Gas business segment.

Financing Activities

~~Cash~~$331 million less cash used in financing activities ~~decreased $1,017 million for~~in the ~~nine months~~comparable three-month periods ended ~~September 30,~~March 31, 2023 and 2022 ~~compared to~~is explained by the ~~respective 2021 period primarily attributable to:~~following discussion:

•~~an $837~~a $470 million net decrease in cash used related to debt activity as a result of lower net debt payments in the ~~2022~~2023 period compared to ~~the 2021 period; and~~

•~~$557 million of net proceeds received from the sale of a 25.5% ownership interest in ELC in~~ the 2022 period; partially offset by,

•~~$333~~a $112 million ofincrease in cash used ~~in the 2022 period~~ for share repurchases under our share buy-back program.

Dividends

We expect to declare dividends of ~~$1.11~~$1.13 per share on our stock for ~~2022.~~2023. The table below reflects our ~~2022~~2023 dividends declared:

Three months ended

Total quarterly dividend per share for the period

Date of declaration

Date of record

Date of dividend

March 31, ~~2022~~2023

~~0.2775~~0.2825

April ~~20, 2022~~19, 2023

May ~~2, 2022~~1, 2023

May ~~16, 2022~~

~~June 30, 2022~~

~~0.2775~~

~~July 20, 2022~~

~~August 1, 2022~~

~~August~~ 15, ~~2022~~

~~September 30, 2022~~

~~0.2775~~

~~October 19, 2022~~

~~October 31, 2022~~

~~November 15, 2022~~2023

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 ~~2021~~2022 Form 10-K. All of these matters will be taken into consideration by our board of directors inwhen 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 will be paid on or about the 15th day of each February, May, August and November.

5445

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), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or a Subsidiary ~~Issuers are~~Issuer is 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 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 “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, 2022.~~March 31, 2023.”

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the 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 30, 2022~~March 31, 2023 and December 31, ~~2021,~~2022, the Obligated Group had ~~$30,842~~$30,519 million and ~~$31,608~~$30,886 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, 2022		December 31, 2021		Summarized Combined Balance Sheet Information	March 31, 2023		December 31, 2022
		(In millions)					(In millions)

Current assets	Current assets	$	3,523	$	3,556	Current assets	$	2,397	$	3,514
Current assets - affiliates	Current assets - affiliates	644		1,233		Current assets - affiliates	587		618
Noncurrent assets	Noncurrent assets	61,395		61,754		Noncurrent assets	61,489		61,523
Noncurrent assets - affiliates	Noncurrent assets - affiliates	512		508		Noncurrent assets - affiliates	520		516
Total Assets	Total Assets	$	66,074	$	67,051	Total Assets	$	64,993	$	66,171

Current liabilities	Current liabilities	$	5,826	$	5,413	Current liabilities	$	4,456	$	6,612
Current liabilities - affiliates	Current liabilities - affiliates	709		1,332		Current liabilities - affiliates	639		707
Noncurrent liabilities	Noncurrent liabilities	31,337		32,310		Noncurrent liabilities	31,679		30,668
Noncurrent liabilities - affiliates	Noncurrent liabilities - affiliates	1,075		1,047		Noncurrent liabilities - affiliates	1,137		1,096
Total Liabilities	Total Liabilities	38,947		40,102		Total Liabilities	37,911		39,083

Kinder Morgan, Inc.’s stockholders’ equity	Kinder Morgan, Inc.’s stockholders’ equity	27,127		26,949		Kinder Morgan, Inc.’s stockholders’ equity	27,082		27,088
Total Liabilities and Stockholders’ Equity	Total Liabilities and Stockholders’ Equity	$	66,074	$	67,051	Total Liabilities and Stockholders’ Equity	$	64,993	$	66,171

Summarized Combined Income Statement Information Three Months Ended
September 30, 2022 Nine Months Ended
September 30, 2022
(In millions)
Revenues $ 4,757 $ 13,490
Operating income 811 2,606
Net income 482 1,587


Summarized Combined Income Statement Information	Three Months Ended March 31, 2023
	(In millions)
Revenues	$	3,613
Operating income	1,108
Net income	613

5546

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, ~~2021,~~2022, in Part II, Item 7A in our ~~2021~~2022 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 65 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of ~~September 30, 2022,~~March 31, 2023, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended ~~September 30, 2022~~March 31, 2023 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~~Other than the following updated risk factor, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our ~~2021~~2022 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 65 “Risk Management” to our consolidated financial statements.

New laws, policies, regulations, rulemaking and oversight, as well as changes to those currently in effect, could adversely impact our earnings, cash flows and operations.

Our assets and operations are subject to extensive regulation and oversight by federal, state and local regulatory authorities. Legislative changes, as well as regulatory actions taken by these authorities, have the potential to adversely affect our profitability. Additional regulatory burdens and uncertainties will be created if and to the extent that more stringent energy and environmental and pipeline safety policies are enacted. Overall, we have seen an increase in the efforts of regulatory authorities to issue new regulations and guidance and to interpret existing laws and regulations in ways that promote the use of renewable energy sources and further protection of the environment, call upon companies to increase monitoring and emissions reduction efforts, and increase investigations and enforcement actions for potential violations of environmental laws. For example, in November 2021, the EPA proposed a rule containing standards of performance for GHG emissions, in the form of methane limitations, and volatile organic compound emissions for crude oil and natural gas sources, including the production, processing, transmission and storage segments. In November 2022, the EPA announced a supplemental proposal expanding on the November 2021 proposed rule aimed at achieving more comprehensive emissions reductions from oil and natural gas sources.

These types of proposals, if finalized, would affect our assets and operations indirectly, such as by increasing the costs associated with the production of natural gas and liquids that we transport, or directly, such as by increasing significantly our capital and operating costs associated with impacted equipment.

On March 15, 2023, the EPA announced finalization of its Good Neighbor Plan (the “Plan”) indicating the Plan will significantly cut nitrogen oxide pollution from power plants and other industrial facilities from 23 upwind states which the EPA determined is significantly contributing to National Ambient Air Quality Standards (NAAQS) nonattainment and interfering with maintenance of the 2015 ozone NAAQS in downwind states. As part of the Plan, the EPA announced that it would be

issuing prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas. If the Plan is published in the Federal Register as a final rule, in the form announced by the EPA, those standards will require the installation of more stringent air pollution controls on hundreds of our existing internal combustion engines. The Plan is scheduled to take effect in 2026 and will apply to all impacted engines unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and considered by the EPA on an engine-by-engine basis. The Plan could have material financial impacts on our Natural Gas business segment in relation to the costs necessary to comply with the Plan, the timing of compliance, equipment shortages, potential operational disruptions, and the availability of and costs associated with the purchase of offsets.

These and other initiatives of regulatory authorities may affect our assets and operations directly or indirectly, such as by preventing or delaying the exploration for and production of natural gas and liquids that we transport or expanding regulation of existing infrastructure or new sources that are not currently regulated.

Regulation affects almost every part of our business. In addition to environmental and pipeline safety matters, we are subject to regulations extending to such matters as (i) federal, state and local taxation; (ii) rates (which include reservation, commodity, surcharges, fuel and gas lost and unaccounted for), operating terms and conditions of service; (iii) the types of services we may offer to our customers; (iv) the contracts for service entered into with our customers; (v) the certification and construction of new facilities; (vi) the integrity, safety and security (including against cyber-attacks) of facilities and operations; (vii) the acquisition of other businesses; (viii) the acquisition, extension, disposition or abandonment of services or facilities; (ix) reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

Should we fail to comply with any applicable statutes, rules, regulations, and orders of such regulatory authorities, we could be subject to substantial penalties and fines and potential loss of government contracts. New laws or regulations, or different interpretations of existing laws or regulations, including unexpected policy changes, applicable to our income, operations, assets or another aspect of our business could have a material adverse impact on our earnings, cash flow, financial condition and results of operations. For more information, see Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation” in our 2022 Form 10-K.

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

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
July 1 to July 31, 2022 6,139,969 $ 16.63 6,139,969 $ 1,149,696,799
August 1 to August 31, 2022 — — — 1,149,696,799
September 1 to September 30, 2022 3,531,359 16.42 3,531,359 1,091,722,406
Total 9,671,328 $ 16.55 9,671,328 $ 1,091,722,406
(During the quarter ended March 31, 2023)


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(a)
January 1 to January 31, 2023	—	$	—	—	$	2,057,284,126
February 1 to February 28, 2023	—	—		—	2,057,284,126
March 1 to March 31, 2023	6,810,307	16.62		6,810,307	1,944,068,674

Total	6,810,307	$	16.62	6,810,307	$	1,944,068,674

(a)On July 19, 2017, our board of directors approved a $2 billion common share buy-back ~~program that began~~program. On January 18, 2023, our board of directors approved an increase in ~~December 2017.~~our share repurchase authorization to $3 billion from $2 billion. After repurchase, the shares are canceled and no longer outstanding.

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

~~Subsequent to September 30, 2022 and through October 20, 2022, we repurchased approximately 2 million of our shares for $34 million at an average price of $16.75 per share.~~

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Except for 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). 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 30, 2022.~~March 31, 2023.

Item 5. Other Information.

None.

5749

Item 6. Exhibits.


Exhibit Number						Description
4.1						Certificate of the Vice President and Treasurer and Vice President and Chief Financial Officer of Kinder Morgan, Inc. establishing the terms of the ~~4.800%~~5.200% Notes due ~~2033 and the 5.450% Notes due 2052.~~2033.

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, 2022.~~March 31, 2023.

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 Income for the three ~~and nine~~ months ended ~~September 30, 2022~~March 31, 2023 and ~~2021;~~2022; (ii) our Consolidated Statements of Comprehensive Income for the three ~~and nine~~ months ended ~~September 30, 2022~~March 31, 2023 and ~~2021;~~2022; (iii) our Consolidated Balance Sheets as of ~~September 30, 2022~~March 31, 2023 and December 31, ~~2021;~~2022; (iv) our Consolidated Statements of Cash Flows for the ~~nine~~three months ended ~~September 30, 2022~~March 31, 2023 and ~~2021;~~2022; (v) our Consolidated Statements of Stockholders’ Equity for the three ~~and nine~~ months ended ~~September 30, 2022~~March 31, 2023 and ~~2021;~~2022; 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.

5850

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~~April 21, ~~2022~~2023

By:

/s/ David P. Michels

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

5951


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant & equipment		Other long-term assets		Goodwill		Current liabilities
			(In millions)
(1)	8/22	North American Natural Resources, Inc.	$	132	$	2	$	5	$	64	$	61	$	—
(2)	7/22	Mas CanAm, LLC	358		9		31		319		—		(1)


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


Goodwill as of December 31, 2021	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	63	$	19,914
Acquisitions(a)	—		—		—		—		—		—		51		51


Goodwill as of September 30, 2022	$	14,249	$	2,343	$	928	$	1,378	$	151	$	802	$	114	$	19,965


	Three Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	836	$	66	$	181	$	1	$	(2)	$	1,082
Fee-based services	190		244		93		10		—		537
Total services	1,026		310		274		11		(2)		1,619
Commodity sales
Natural gas sales	1,097		—		—		7		(3)		1,101
Product sales	372		247		8		279		(11)		895

Total commodity sales	1,469		247		8		286		(14)		1,996
Total revenues from customers	2,495		557		282		297		(16)		3,615
Other revenues(c)
Leasing services(d)	119		42		140		15		—		316
Derivatives adjustments on commodity sales	(71)		—		—		(63)		—		(134)
Other	12		6		—		8		1		27
Total other revenues	60		48		140		(40)		1		209
Total revenues	$	2,555	$	605	$	422	$	257	$	(15)	$	3,824


	Nine Months Ended September 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	2,633	$	176	$	585	$	1	$	(2)	$	3,393
Fee-based services	690		723		300		35		—		1,748
Total services	3,323		899		885		36		(2)		5,141
Commodity sales
Natural gas sales	4,938		—		—		68		(17)		4,989
Product sales	1,141		1,577		22		1,105		(4)		3,841

Total commodity sales	6,079		1,577		22		1,173		(21)		8,830
Total revenues from customers	9,402		2,476		907		1,209		(23)		13,971
Other revenues(c)
Leasing services(d)	355		144		430		44		—		973
Derivatives adjustments on commodity sales	(132)		(3)		—		(280)		—		(415)
Other	49		17		—		26		—		92
Total other revenues	272		158		430		(210)		—		650
Total revenues	$	9,674	$	2,634	$	1,337	$	999	$	(23)	$	14,621


	Nine Months Ended September 30, 2021
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from 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 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


	Three Months Ended September 30,
	2022						2021
	GAAP		Certain Items		Adjusted		GAAP		Certain Items		Adjusted		Adjusted amounts increase/(decrease) to earnings
	(In millions)
Segment EBDA
Natural Gas Pipelines	$	1,135	$	24	$	1,159	$	1,069	$	21	$	1,090	$	69
Products Pipelines	257		—		257		279		1		280		(23)
Terminals	240		—		240		216		17		233		7
CO2	215		(20)		195		163		(9)		154		41

Total Segment EBDA(a)	1,847		4		1,851		1,727		30		1,757		94
DD&A and amortization of excess cost of equity investments	(570)		—		(570)		(547)		—		(547)		(23)
General and administrative and corporate charges(a)	(149)		—		(149)		(167)		—		(167)		18
Interest, net(a)	(399)		15		(384)		(368)		(8)		(376)		(8)
Income before income taxes	729		19		748		645		22		667		81
Income tax expense(b)	(134)		(20)		(154)		(134)		(12)		(146)		(8)
Net income	595		(1)		594		511		10		521		73
Net income attributable to noncontrolling interests	(19)		—		(19)		(16)		—		(16)		(3)

Net income attributable to Kinder Morgan, Inc.	$	576	$	(1)	$	575	$	495	$	10	$	505	$	70


	Nine Months Ended September 30, 2022		2022 Remaining		Total 2022
	(In millions)
Sustaining capital expenditures(a)(b)	$	581	$	317	$	898
Discretionary capital investments(b)(c)(d)	1,214		632		1,846


Summarized Combined Income Statement Information	Three Months Ended September 30, 2022		Nine Months Ended September 30, 2022
	(In millions)
Revenues	$	4,757	$	13,490
Operating income	811		2,606
Net income	482		1,587