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

or

☐  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 20, 2022, the registrant had 2,247,742,071 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 and 2021		4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 30, 2022 and 2021		5
	Consolidated Balance Sheets - as of September 30, 2022 and December 31, 2021		6
	Consolidated Statements of Cash Flows - Nine Months Ended September 30, 2022 and 2021		7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 30, 2022 and 2021		9
	Notes to Consolidated Financial Statements		10
	Note 1.	General	10
	Note 2.	Acquisitions and Divestitures	11
	Note 3.	Losses on Impairments and Other Write-downs	13
	Note 4.	Debt	14
	Note 5.	Stockholders’ Equity	15
	Note 6.	Risk Management	16
	Note 7.	Revenue Recognition	21
	Note 8.	Reportable Segments	24
	Note 9.	Income Taxes	25
	Note 10.	Litigation and Environmental	26
	Note 11.	Recent Accounting Pronouncements	30
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		32
	Results of Operations		32
	Overview		32
	Consolidated Earnings Results (GAAP)		35
	Non-GAAP Financial Measures		38
	Segment Earnings Results		41
	DD&A, General and Administrative and Corporate Charges, Interest, net and Noncontrolling Interests		49
	Income Taxes		51
	Liquidity and Capital Resources		51
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		55
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56
Item 4.	Controls and Procedures		56
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings		56
Item 1A.	Risk Factors		56
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		56
Item 3.	Defaults Upon Senior Securities		56
Item 4.	Mine Safety Disclosures		57
Item 5.	Other Information		57
Item 6.	Exhibits		58
	Signature		59

1

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
/d	=	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	ROU	=	Right-of-Use
			U.S.	=	United States of America
EPA	=	U.S. Environmental Protection Agency	WTI	=	West Texas Intermediate
FASB	=	Financial Accounting Standards Board

2

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” 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 (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.

3

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,
	2022		2021		2022		2021
Revenues
Services	$	2,028	$	1,928	$	6,089	$	5,734
Commodity sales	3,108		1,868		8,416		6,343
Other	41		28		116		108
Total Revenues	5,177		3,824		14,621		12,185
Operating Costs, Expenses and Other
Costs of sales	2,717		1,559		7,294		4,504
Operations and maintenance	712		614		1,960		1,710
Depreciation, depletion and amortization	551		526		1,632		1,595
General and administrative	162		174		470		490
Taxes, other than income taxes	113		106		340		324
(Gain) loss on divestitures and impairments, net	(9)		4		(30)		1,602
Other income, net	—		(3)		(6)		(6)
Total Operating Costs, Expenses and Other	4,246		2,980		11,660		10,219
Operating Income	931		844		2,961		1,966
Other Income (Expense)
Earnings from equity investments	195		169		564		392
Amortization of excess cost of equity investments	(19)		(21)		(57)		(56)
Interest, net	(399)		(368)		(1,087)		(1,122)
Other, net (Note 2)	21		21		63		264
Total Other Expense	(202)		(199)		(517)		(522)
Income Before Income Taxes	729		645		2,444		1,444
Income Tax Expense	(134)		(134)		(512)		(248)
Net Income	595		511		1,932		1,196
Net Income Attributable to Noncontrolling Interests	(19)		(16)		(54)		(49)
Net Income Attributable to Kinder Morgan, Inc.	$	576	$	495	$	1,878	$	1,147
Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.25	$	0.22	$	0.83	$	0.50
Basic and Diluted Weighted Average Shares Outstanding	2,253		2,267		2,262		2,265

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

4

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions, unaudited)

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
Net income	$	595	$	511	$	1,932	$	1,196
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
Benefit plan adjustments (net of taxes of $(1), $(2), $(6) and $(7), respectively)	2		6		18		28
Total other comprehensive income (loss)	229		(33)		48		(235)
Comprehensive income	824		478		1,980		961
Comprehensive income attributable to noncontrolling interests	(19)		(16)		(54)		(49)
Comprehensive income attributable to KMI	$	805	$	462	$	1,926	$	912

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

5

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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

	September 30, 2022		December 31, 2021
ASSETS
Current Assets
Cash and cash equivalents	$	483	$	1,140
Restricted deposits	240		7
Accounts receivable	1,873		1,611
Fair value of derivative contracts	194		220
Inventories	715		562
Other current assets	314		289
Total current assets	3,819		3,829
Property, plant and equipment, net	35,534		35,653
Investments	7,465		7,578
Goodwill	19,965		19,914
Other intangibles, net	1,875		1,678
Deferred income taxes	—		115
Deferred charges and other assets	1,334		1,649
Total Assets	$	69,992	$	70,416
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,634	$	2,646
Accounts payable	1,579		1,259
Accrued interest	327		504
Accrued taxes	297		270
Fair value of derivative contracts	501		178
Other current liabilities	810		964
Total current liabilities	6,148		5,821
Long-term liabilities and deferred credits
Long-term debt
Outstanding	29,000		29,772
Debt fair value adjustments	107		902
Total long-term debt	29,107		30,674
Deferred income taxes	442		—
Other long-term liabilities and deferred credits	2,160		2,000
Total long-term liabilities and deferred credits	31,709		32,674
Total Liabilities	37,857		38,495
Commitments and contingencies (Notes 4 and 10)
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
Additional paid-in capital	41,689		41,806
Accumulated deficit	(10,593)		(10,595)
Accumulated other comprehensive loss	(363)		(411)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,756		30,823
Noncontrolling interests	1,379		1,098
Total Stockholders’ Equity	32,135		31,921
Total Liabilities and Stockholders’ Equity	$	69,992	$	70,416

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

6

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Nine Months Ended September 30,
	2022		2021
Cash Flows From Operating Activities
Net income	$	1,932	$	1,196
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,632		1,595
Deferred income taxes	499		236
Amortization of excess cost of equity investments	57		56
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)
Earnings from equity investments	(564)		(392)
Distributions from equity investment earnings	548		535
Changes in components of working capital
Accounts receivable	(260)		(119)
Inventories	(165)		(89)
Other current assets	(60)		(90)
Accounts payable	347		362
Accrued interest, net of interest rate swaps	(160)		(177)
Accrued taxes	27		15
Other current liabilities	2		71
Rate reparations, refunds and other litigation reserve adjustments	(189)		(97)
Other, net	(98)		(118)
Net Cash Provided by Operating Activities	3,563		4,440
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 2)	(488)		(1,518)
Capital expenditures	(1,144)		(894)
Proceeds from sales of investments (Note 2)	4		417
Contributions to investments	(60)		(36)
Distributions from equity investments in excess of cumulative earnings	126		121
Other, net	17		(1)
Net Cash Used in Investing Activities	(1,545)		(1,911)
Cash Flows From Financing Activities
Issuances of debt	8,898		4,950
Payments of debt	(9,569)		(6,459)
Debt issue costs	(21)		(20)
Dividends	(1,876)		(1,828)
Repurchases of shares	(333)		—
Proceeds from sale of noncontrolling interests (Note 2)	557		—
Contributions from noncontrolling interests	1		4
Distributions to investment partner	—		(67)
Distributions to noncontrolling interests	(85)		(14)
Other, net	(14)		(25)
Net Cash Used in Financing Activities	(2,442)		(3,459)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(424)		(930)
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 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

7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Nine Months Ended September 30,
	2022		2021
Cash and Cash Equivalents, end of period	483		102
Restricted Deposits, end of period	240		177
Cash, Cash Equivalents, and Restricted Deposits, end of period	723		279
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(424)	$	(930)
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments	$	19	$	35
Increase in property, plant and equipment from both accruals and contractor retainage	23		4
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,278		1,313
Cash paid during the period for income taxes, net	12		8

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

8

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
	Issued shares	Par value
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625
Repurchases of shares	(9)			(160)						(160)				(160)
Restricted shares	2			5						5				5
Net income						576				576		19		595
Distributions										—		(32)		(32)
Contributions										—		1		1
Impact of change in ownership interest in subsidiary				190						190		311		501
Dividends						(629)				(629)				(629)
Other comprehensive income								229		229				229
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
	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
	Issued shares	Par value
Balance at December 31, 2020	2,264	$	23	$	41,756	$	(9,936)	$	(407)	$	31,436	$	402	$	31,838
Restricted shares	3			32						32				32
Net income						1,147				1,147		49		1,196
Distributions										—		(14)		(14)
Contributions										—		4		4
Dividends						(1,828)				(1,828)				(1,828)
Other										—		(1)		(1)
Other comprehensive loss								(235)		(235)				(235)
Balance at September 30, 2021	2,267	$	23	$	41,788	$	(10,617)	$	(642)	$	30,552	$	440	$	30,992

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

9

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 83,000 miles of pipelines, 141 terminals, 700 Bcf of working natural gas storage capacity and 2.2 Bcf per year of renewable natural gas 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 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.

10

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,
	2022		2021		2022		2021
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	576	$	495	$	1,878	$	1,147
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	(4)		(4)		(9)		(10)
Net Income Allocated to Class P Stockholders	$	572	$	491	$	1,869	$	1,137
Basic Weighted Average Shares Outstanding	2,253		2,267		2,262		2,265
Basic Earnings Per Share	$	0.25	$	0.22	$	0.83	$	0.50

(a)As of September 30, 2022, 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,
	2022	2021	2022	2021
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	13	13	13
Convertible trust preferred securities	3	3	3	3

2. Acquisitions and Divestitures

Business Combinations

As of September 30, 2022, our preliminary allocation 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 CO2 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 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.

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(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 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, 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.

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.

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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 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 within “Earnings from equity investments” on 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.

Ruby Chapter 11 Bankruptcy Filing

The balance of Ruby Pipeline, L.L.C.’s 2022 unsecured notes matured on April 1, 2022 in the principal amount of $475 million. Although Ruby has sufficient liquidity to operate its business, it lacked sufficient liquidity to satisfy its obligations under the 2022 unsecured notes on the maturity date of April 1, 2022. Accordingly, on March 31, 2022, Ruby filed a voluntary petition for relief under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware. Ruby, as the debtor, will continue to operate in the ordinary course as a debtor in possession under the jurisdiction of the United States Bankruptcy Court. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021. We had no amounts included in our “Investments” on our accompanying consolidated balance sheets associated with Ruby as of September 30, 2022 or December 31, 2021.

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4. Debt

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

	September 30, 2022		December 31, 2021
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2026	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes	—		—
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	1,000		—
Floating rate, due January 2023(d)	250		—
3.45% due February 2023	625		—
3.50% due September 2023	600		—
Trust I preferred securities, 4.75%, due March 2028	111		111
Current portion of other debt	48		47
Total current portion of debt	2,634		2,646
Long-term debt (excluding current portion)
Senior notes	28,343		29,097
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	336		348
Trust I preferred securities, 4.75%, due March 2028	109		110
Other	212		217
Total long-term debt	29,000		29,772
Total debt(e)	$	31,634	$	32,418

(a)We repaid the principal amount of these senior notes during the first quarter of 2022.

(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 and December 31, 2021, increased our total debt balances by $107 million and $902 million, respectively.

We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement.

On February 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, we issued in a registered offering two series of senior notes consisting of $750 million aggregate principal amount of 4.80% senior notes due 2033 and $750 million aggregate principal amount of 5.45% senior notes due 2052 and received combined net proceeds of $1,484 million. We used a portion of the proceeds to repay short-term borrowings and for general corporate purposes.

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Credit Facilities and Restrictive Covenants

As of September 30, 2022, 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 was $3.9 billion. As of September 30, 2022, we were in compliance with all required covenants.

Fair Value of Financial Instruments

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

	September 30, 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

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

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

5. 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. During the nine months ended September 30, 2022, we repurchased approximately 19 million of our shares for $333 million at an average price of $16.97 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,
	2022		2021		2022		2021
Per share cash dividend declared for the period	$	0.2775	$	0.27	$	0.8325	$	0.81
Per share cash dividend paid in the period	0.2775		0.27		0.8250		0.8025

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

Adoption of Accounting Pronouncement

On January 1, 2022, we adopted Accounting Standards Update (ASU) No. 2020-06, “Debt – Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging – Contracts in Entity’s Own Equity (Subtopic 815-40): Accounting for Convertible Instruments and Contracts in an Entity’s Own Equity.” This ASU (i) simplifies an issuer’s accounting for convertible instruments by eliminating two of the three models in ASC 470-20 that require separate accounting for embedded conversion features, (ii) amends diluted earnings per share calculations for convertible instruments by requiring the use of the if-converted method and (iii) simplifies the settlement assessment entities are required to perform on contracts that can potentially settle in an entity’s own equity by removing certain requirements. Using the modified retrospective method, the adoption of this ASU resulted in a pre-tax adjustment of $14 million to unwind the remaining unamortized debt discount within “Debt fair value adjustments” on our consolidated balance sheet and an adjustment of $11 million to unwind the balance of the conversion feature classified in “Additional paid in capital” on our consolidated statement of stockholders’ equity for the nine months ended September 30, 2022.

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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, 2020	$	(13)	$	(394)	$	(407)
Other comprehensive (loss) gain before reclassifications	(444)		28		(416)
Loss reclassified from accumulated other comprehensive loss	181		—		181
Net current-period change in accumulated other comprehensive loss	(263)		28		(235)
Balance as of September 30, 2021	$	(276)	$	(366)	$	(642)

6.  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, 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)	MMBbl
Crude oil basis	(6.0)	MMBbl
Natural gas fixed price	(50.8)	Bcf
Natural gas basis	(28.0)	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)	MMBbl
Natural gas fixed price	(7.5)	Bcf
Natural gas basis	(37.8)	Bcf
NGL fixed price	(0.8)	MMBbl

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As of September 30, 2022, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2026.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2022:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)	$	7,500	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		Mark-to-Market	December 2022

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

(b)During the three and nine months ended September 30, 2022, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 11 “Recent Accounting Pronouncements” 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:

	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.

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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
		Derivatives Asset				Derivatives Liability
		September 30, 2022		December 31, 2021		September 30, 2022		December 31, 2021
	Location	Fair value				Fair value
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	$	104	$	61	$	(229)	$	(141)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	29		3		(67)		(94)
Subtotal		133		64		(296)		(235)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	3		101		(115)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	36		284		(307)		(15)
Subtotal		39		385		(422)		(18)
Foreign currency contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	—		35		(6)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		6		(62)		—
Subtotal		—		41		(68)		(3)
Total		172		490		(786)		(256)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	48		11		(151)		(31)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	20		1		(22)		(6)
Subtotal		68		12		(173)		(37)
Interest rate contracts	Fair value of derivative contracts/(Fair value of derivative contracts)	39		12		—		—
Total		107		24		(173)		(37)
Total derivatives		$	279	$	514	$	(959)	$	(293)

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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)
	Level 1		Level 2		Level 3		Gross amount						Net amount
	(In millions)
As of September 30, 2022
Energy commodity derivative contracts(a)	$	63	$	138	$	—	$	201	$	(169)	$	—	$	32
Interest rate contracts	—		78		—		78		—		—		78
As of December 31, 2021
Energy commodity derivative contracts(a)	$	56	$	20	$	—	$	76	$	(53)	$	(20)	$	3
Interest rate contracts	—		397		—		397		(9)		—		388
Foreign currency contracts	—		41		—		41		(3)		—		38

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

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

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

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

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,
		2022		2021		2022		2021
		(In millions)
Interest rate contracts	Interest, net	$	(278)	$	(39)	$	(754)	$	(228)
Hedged fixed rate debt(a)	Interest, net	$	279	$	39	$	761	$	229

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

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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	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2022		2021			2022		2021
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(375)	$	(514)	Revenues—Commodity sales	$	(433)	$	(167)
					Costs of sales	34		10
Interest rate contracts	7		3		Interest, net	—		—
Foreign currency contracts	(107)		(68)		Other, net	(115)		(79)
Total	$	(475)	$	(579)	Total	$	(514)	$	(236)

(a)We expect to reclassify approximately $124 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 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	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2022		2021		2022		2021
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	44	$	(40)	$	18	$	(703)
	Costs of sales	(30)		(7)		(129)		154
	Earnings from equity investments	(7)		(2)		(11)		(4)
Interest rate contracts	Interest, net	(20)		—		28		—
Total(a)		$	(13)	$	(49)	$	(94)	$	(553)

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

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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 and December 31, 2021, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2022, we had cash margins of $223 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, we had cash margins of $14 million posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheet. The balance at September 30, 2022 represents our initial margin requirements of $88 million and variation margin requirements of $135 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, 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 million of additional collateral.

7. 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
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from customers(a)
Services
Firm services(b)	$	845	$	57	$	199	$	—	$	—	$	1,101
Fee-based services	243		247		106		11		—		607
Total services	1,088		304		305		11		—		1,708
Commodity sales
Natural gas sales	1,902		—		—		24		(7)		1,919
Product sales	389		511		11		353		(1)		1,263
Total commodity sales	2,291		511		11		377		(8)		3,182
Total revenues from customers	3,379		815		316		388		(8)		4,890
Other revenues(c)
Leasing services(d)	120		51		141		16		—		328
Derivatives adjustments on commodity sales	(12)		—		—		(60)		—		(72)
Other	18		6		—		7		—		31
Total other revenues	126		57		141		(37)		—		287
Total revenues	$	3,505	$	872	$	457	$	351	$	(8)	$	5,177

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	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

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

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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 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2022	$	1,157
2023	4,055
2024	3,244
2025	2,685
2026	2,357
Thereafter	14,007
Total	$	27,505

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

8.  Reportable Segments

Financial information by segment follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2022		2021		2022		2021
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	3,497	$	2,541	$	9,653	$	8,611
Intersegment revenues	8		14		21		45
Products Pipelines	872		605		2,634		1,572
Terminals
Revenues from external customers	457		421		1,335		1,273
Intersegment revenues	—		1		2		2
CO2	351		257		999		729
Corporate and intersegment eliminations	(8)		(15)		(23)		(47)
Total consolidated revenues	$	5,177	$	3,824	$	14,621	$	12,185

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	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
	(In millions)
Assets
Natural Gas Pipelines	$	47,872	$	47,746
Products Pipelines	8,994		9,088
Terminals	8,362		8,513
CO2	3,470		2,843
Corporate assets(b)	1,294		2,226
Total consolidated assets	$	69,992	$	70,416

(a)Includes revenues, earnings from equity investments, operating expenses, (gain) loss 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.  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,
	2022			2021			2022			2021
	(In millions, except percentages)
Income tax expense	$	134		$	134		$	512		$	248
Effective tax rate	18.4		%	20.8		%	20.9		%	17.2		%

The effective tax rate for the three and nine months ended September 30, 2022 is lower 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 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.

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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.

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

On December 20, 2019, GLNG’s remaining customer, Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A., filed a Notice of Arbitration seeking a declaration that its terminal use agreement should be deemed terminated as of March 1, 2016 on substantially the same terms and conditions as set forth in the arbitration award pertaining to Eni USA. On July 15, 2021, the arbitration tribunal delivered an Award on the merits of all

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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 against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. We believe that our declaration of force majeure was valid and we 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 pipeline segment is currently out of service. 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 and December 31, 2021, our total reserve for legal matters was $42 million and $231 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline,

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terminal and CO2 field and oil field operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

We are currently involved in several governmental proceedings involving alleged violations of local, state and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but we do not believe any such fines and penalties will be material to our business, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have established a reserve to address the costs associated with the remediation efforts.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental reserves have been established for those sites where our contribution is probable and reasonably estimable. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas or CO2.

PHMSA Enforcement Matter for KMLT Midwest Terminals

On July 11, 2022, Kinder Morgan Liquid Terminals (KMLT) received a Notice of Probable Violation (NOPV) from PHMSA relating to inspections conducted during 2021 at KMLT’s Cincinnati, Indianapolis, Dayton, Argo, O’Hare, and Wood River Terminals. The NOPV alleges 16 violations of Department of Transportation regulations. The NOPV proposes a penalty of approximately $455,000 and seeks a compliance agreement relating to three of the alleged violations. The alleged violations are predominately procedural in nature. On September 1, 2022, we submitted a Request for Hearing, Statement of Issues and Response to the NOPV. At the same time we initiated settlement discussions with PHMSA which are ongoing. We do not anticipate the costs to resolve this matter, including any costs to implement a compliance agreement, will have a material adverse impact to our business.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated 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. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

In addition to CERCLA cleanup costs, we are reviewing and will attempt to settle, if possible, natural resource damage (NRD) claims in the amount of approximately $5 million asserted by state and federal trustees following their natural resource assessment of the PHSS.

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

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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 cleanup plan in the ROD is estimated to cost $440 million. No timeline for the cleanup has been established. Certain PRPs, including EPEC, are engaged in discussions with the EPA concerning the upper nine miles. There remains significant uncertainty as to the implementation and associated costs of the remedy set forth in the upper nine mile ROD. Until the ongoing discussions with the EPA conclude, we are unable to reasonably estimate the extent of our potential liability. We do not anticipate that our share of the costs to resolve this matter, including the costs of any remediation of the Site, will have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

Beginning in 2013, several parishes in Louisiana and the City of New Orleans filed separate lawsuits in state district courts in Louisiana against a number of oil and gas companies, including TGP and SNG. In these cases, the parishes and New Orleans, as Plaintiffs, allege that certain of the defendants’ oil and gas exploration, production and transportation operations were conducted in violation of the State and Local Coastal Resources Management Act of 1978, as amended (SLCRMA) and that those operations caused substantial damage to the coastal waters of Louisiana and nearby lands. The Plaintiffs seek, among other relief, unspecified money damages, attorneys’ fees, interest, and payment of costs necessary to restore the affected areas. There are more than 40 of these cases pending in Louisiana against oil and gas companies, 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 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 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.

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On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) filed a petition for damages in the state district court for Orleans Parish, Louisiana against SNG and 10 other energy companies alleging that the defendants’ operations in Orleans Parish violated the SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans seeks, among other relief, unspecified money damages, attorney fees, interest, and payment of costs necessary to restore the allegedly affected areas. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. In May 2019, Orleans moved to remand the case to the state district court. In January 2020, the U.S. District Court ordered the case to be stayed and administratively closed pending the resolution of issues in a separate case to which SNG is not a party; Parish of Cameron vs. Auster Oil & Gas, Inc., pending in U.S. District Court for the Western District of Louisiana; after which either party may move to re-open the case. Until these and other issues are determined, we are not able to reasonably estimate the extent of our potential liability, if any. We 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 and December 31, 2021, we have accrued a total reserve for environmental liabilities in the amount of $227 million and $243 million, respectively. In addition, as of September 30, 2022 and December 31, 2021, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.

11. 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).

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Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

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

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

During the nine months ended September 30, 2022 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $1,725 million and convert a portion of our fixed rate debt to variable rates through March 2035. 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 Management—Interest Rate Risk 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 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2021 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2021 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1A of our 2021 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 per share for 2022, a 3% increase from the 2021 declared dividends of $1.08 per share. We now expect to invest $1.8 billion in expansion projects, acquisitions, and contributions to joint ventures or discretionary capital expenditures during 2022.

The expectations for 2022 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using the GAAP financial measures of Segment EBDA (as presented in Note 8 “Reportable 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.

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GAAP Financial Measures

The Consolidated Earnings Results for the three and nine months ended September 30, 2022 and 2021 present Segment EBDA and Net income attributable to Kinder Morgan, Inc. which are prepared and presented in accordance with GAAP. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of these non-GAAP financial measures by reviewing our comparable GAAP measures, understanding the differences between the measures and taking this information into account in its analysis and its decision making processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically either (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in our view are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below and the tables included in “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. (GAAP) to Adjusted EBITDA” and “—Non-GAAP Financial Measures—Supplemental Information” below). In addition, Certain Items are described in more detail in the footnotes to tables included in “—Segment Earnings Results” and “—DD&A, General and Administrative and Corporate Charges, Interest, net, and Noncontrolling Interests” below.

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us and certain external users of our financial statements to assess the earnings of our business excluding Certain Items as another reflection of our ability to generate earnings. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income 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” below.

DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items (Adjusted Earnings), and further by DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also include amounts from joint ventures for income taxes, DD&A and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure useful to management and external users of our financial statements in evaluating our performance and in measuring and estimating the ability of our assets to generate cash earnings after servicing our debt, paying cash taxes and expending sustaining capital, that could be used for discretionary purposes such as dividends, stock repurchases, retirement of debt, or expansion capital expenditures. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income 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 and external users of our financial statements additional insight into the ability of our segments to generate cash earnings on an ongoing basis. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. We believe the GAAP measure most directly comparable to Adjusted Segment EBDA is Segment EBDA. See “—Consolidated Earnings Results (GAAP)—Certain Items Affecting Consolidated Earnings Results” for a reconciliation of Segment EBDA to Adjusted Segment EBDA by business segment.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting EBITDA for Certain Items. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management and external users, in conjunction with our Net Debt (as described further below), to evaluate certain leverage metrics. Therefore, we believe Adjusted EBITDA is useful to investors. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income 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. (See “—Non-GAAP Financial Measures—Supplemental Information” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculations of DCF and Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of September 30, 2022, by subtracting the following amounts from our debt balance of $31,741 million: (i) cash and cash equivalents of $483 million; and (ii) debt fair value adjustments of $107 million; and excluding the foreign exchange impact on Euro-denominated bonds of $(53) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt is a non-GAAP financial measure that management believes is useful to investors and other users of our financial information in evaluating our leverage. We believe the most comparable measure to Net Debt is debt net of cash and cash equivalents.

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Consolidated Earnings Results (GAAP)

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

	Three Months Ended September 30,
	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%

	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	%

(a)Includes revenues, earnings from equity investments, operating expenses, (gain) loss 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.

Net income attributable to Kinder Morgan, Inc. increased $81 million and $731 million for the three and nine months ended September 30, 2022, respectively, as compared to the respective prior year periods. The third quarter increase was

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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 partially 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

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	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.

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

Net income 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 CO2 business segments. The year-to-date decrease was impacted by 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.

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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.

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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, respectively, 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.

39

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.

40

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

(a)Three months ended September 30, 2022 amount includes an increase in revenues of $51 million and an increase in costs of sales of $47 million, and nine months ended September 30, 2022 amount includes an increase in revenues of $48 million and an increase in costs of sales of $133 million related 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 associated with a pipeline rupture. Three and nine months ended September 30, 2021 amounts include decreases 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.

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.

41

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

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

	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
	2022		2021		increase/ (decrease)
Midstream	$	1,063	$	1,807	$	(744)
East	1,846		1,706		140
West	680		735		(55)
Total Natural Gas Pipelines	$	3,589	$	4,248	$	(659)

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

•$62 million (21%) increase and $744 million (41%) decrease, respectively, in Midstream. The third quarter increase was primarily due to higher volumes on our KinderHawk assets, higher sales margins due to higher prices 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 offset by higher volumes on our KinderHawk assets, higher NGL sales margins driven by higher prices on our Altamont asset and higher earnings on our Oklahoma assets from higher 2021 commodity prices on certain purchase contracts as a result of the February 2021 winter storm. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales;

•$18 million (3%) and $140 million (8%) increases, respectively, in the East Region were primarily due to higher capacity sales associated with our Stagecoach assets, higher equity earnings from SNG as a result of increased revenues due to an increase in demand for services and increased earnings from Kinder Morgan Louisiana Pipeline, LLC reflecting a new LNG customer contract partially offset by decreased earnings on TGP driven by higher operating expenses due in part to higher property taxes and pipeline integrity costs. The year-to-date increase was further impacted by our July 2021 acquisition of the Stagecoach assets; and

•$11 million (5%) and $55 million (7%) decreases, respectively, in the West Region were primarily due to lower earnings from Colorado Interstate Gas Company, L.L.C. driven by lower revenues resulting from a rate case settlement and a decrease in revenues from EPNG driven by lower commodity and park and loan volumes that resulted from a partial pipeline outage.

42

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

(a)Nine months ended September 30, 2021 amount includes increases in expenses of $28 million and $15 million related to a litigation reserve and an environmental reserve adjustment, respectively.

Other

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

(c)Volumes include ethanol pipeline volumes.

43

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

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

	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
	2022		2021		increase/ (decrease)
Crude and Condensate	$	250	$	269	$	(19)
Southeast Refined Products	209		198		11
West Coast Refined Products	396		369		27
Total Products Pipelines	$	855	$	836	$	19

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

•$13 million (15%) and $19 million (7%) decreases, respectively, in Crude and Condensate were primarily due to lower earnings from our Bakken Crude assets due to lower volumes from 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 lower deficiency revenues, partially offset by higher earnings from our KM Condensate Processing facility reflecting increased revenues due to higher volumes and rate escalations. Our Crude and Condensate pipeline also had higher revenues of $209 million and $832 million, respectively, with corresponding increases in cost of sales, resulting from increased marketing activities;

•$7 million (11%) decrease and $11 million (6%) increase, respectively, in Southeast Refined 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 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 volumes and SFPP resulting from higher revenues driven by increased regulatory rates.

44

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

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

45

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

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

	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
	2022		2021		increase/ (decrease)
Mid Atlantic	$	77	$	47	$	30
Gulf Central	102		83		19
Gulf Liquids	217		220		(3)
Northeast	67		80		(13)
Marine operations	105		117		(12)
All others (including intrasegment eliminations)	163		159		4
Total Terminals	$	731	$	706	$	25

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

•$15 million (100%) and $30 million (64%) increases, respectively, in the Mid Atlantic terminals were primarily due to higher handling rates and coal volumes at our Pier IX 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 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, in the Northeast terminals were primarily driven by decreased revenues associated with lower 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.

46

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

(a)Three and nine months ended September 30, 2022 amounts include $(20) million and $(5) million, respectively, and three and nine months ended September 30, 2021 amounts include $1 million and $7 million, respectively, of changes in revenue related to non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales.

Other

(b)Net of royalties and outside working interests.

47

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

Three Months Ended September 30, 2022 versus Three Months Ended September 30, 2021

	Adjusted Segment EBDA
	2022		2021		increase/ (decrease)
Oil and Gas Producing activities	$	132	$	63	$	69
Source and Transportation activities	59		89		(30)
Subtotal	191		152		39
Energy Transition Ventures	4		2		2
Total CO2	$	195	$	154	$	41

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 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:

•$69 million (110%) and $13 million (3%) increases, respectively, in Oil and Gas Producing activities primarily due to higher realized crude oil and NGL prices 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 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

•$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 Oil and Gas Producing activities offset by increased revenues of $12 million and $46 million, respectively, related to higher CO2 sales prices. The year-to-date decrease was also impacted by decreased revenues related to lower CO2 sales volumes.

48

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of September 30, 2022:

	Remaining 2022		2023		2024		2025		2026
Crude Oil(a)
Price ($ per Bbl)	$	62.42	$	63.28	$	61.04	$	61.08	$	65.67
Volume (MBbl/d)	26.40		21.10		13.40		8.95		3.00
NGLs
Price ($ per Bbl)	$	56.02	$	61.39
Volume (MBbl/d)	4.57		2.04
Midland-to-Cushing Basis Spread
Price ($ per Bbl)	$	0.53	$	0.87
Volume (MBbl/d)	23.65		14.50

(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)	%

49

	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% and 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.

50

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, we had $483 million of “Cash and cash equivalents,” a decrease of $657 million from December 31, 2021. Additionally, as of September 30, 2022, 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 million and $4,440 million in the first nine months of 2022 and 2021, respectively. The period-to-period decrease is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided from operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any.

Our board of directors declared a quarterly dividend of $0.2775 per share for the third quarter of 2022, consistent with the dividend declared for the previous quarter.

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.

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

During the first quarter, upon maturity, we repaid EPNG’s 8.625% senior notes, our 4.15% corporate senior notes, and the 1.50% series of our Euro denominated debt. During the second quarter 2022, we repaid $1 billion of our 3.95% 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.

Short-term Liquidity

As of September 30, 2022, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities and associated 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.

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As of September 30, 2022, our $2,634 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 was $2,646 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,329 million and $1,992 million as of September 30, 2022 and December 31, 2021, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $337 million unfavorable change from year-end 2021 was primarily due to (i) a $657 million decrease in cash and cash equivalents which includes $1,190 million related to repayments 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); (ii) unfavorable short-term fair value adjustments on derivative contracts of $349 million; and (iii) a $58 million net unfavorable change in our accounts receivables and payables; partially offset by (i) a $233 million increase in restricted deposits related to our derivative activity; (ii) a $192 million decrease in accrued contingencies; (iii) a $177 million decrease in accrued interest; and (iv) a $153 million increase in inventories, primarily 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 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.

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

Our capital expenditures for the nine months ended September 30, 2022, and the amount we expect to spend for the remainder of 2022 to sustain our assets and grow 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

(a)Nine months ended September 30, 2022, 2022 Remaining, and Total 2022 amounts include $83 million, $53 million, and $136 million, respectively, for sustaining capital expenditures from unconsolidated joint ventures, reduced by consolidated joint venture partners’ sustaining capital expenditures. See table included in “—Results of Operations—Non-GAAP Financial Measures—Supplemental Information.”

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(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 contributions to unconsolidated joint ventures, net of actual or estimated contributions from certain partners in non-wholly owned consolidated subsidiaries for capital investments.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2021 in our 2021 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2022 and December 31, 2021 were $556 million and $209 million, respectively. The increase of $347 million was primarily driven by an overall increase of capital commitments.

Cash Flows

Operating Activities

Cash provided by operating activities decreased $877 million in the nine months ended September 30, 2022 compared to the respective 2021 period primarily due to:

•a $576 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 was primarily driven by unfavorable changes due to (i) increases in our customer accounts receivables 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; (ii) higher inventories reflecting higher storage rates and increased volumes; and (iii) a decrease in reserves associated with litigation matters in the 2022 period compared with the 2021 period.

Investing Activities

Cash used in investing activities decreased $366 million for the nine months ended September 30, 2022 compared to the respective 2021 period primarily attributable to:

•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 million increase in capital expenditures reflecting an overall increase of expansion capital projects in the 2022 period over the comparative 2021 period.

Financing Activities

Cash used in financing activities decreased $1,017 million for the nine months ended September 30, 2022 compared to the respective 2021 period primarily attributable to:

•an $837 million net decrease in cash used related to debt activity as a result of lower net debt payments in the 2022 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 million of cash used in the 2022 period for share repurchases under our share buy-back program.

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Dividends

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

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
March 31, 2022	$	0.2775	April 20, 2022	May 2, 2022	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

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 Form 10-K. All of these matters will be taken into consideration by our board of directors in declaring dividends.

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

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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 Subsidiary Issuers are in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for 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.”

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 and December 31, 2021, the Obligated Group had $30,842 million and $31,608 million, respectively, of Guaranteed Notes outstanding.

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

Summarized Combined Balance Sheet Information	September 30, 2022		December 31, 2021
	(In millions)
Current assets	$	3,523	$	3,556
Current assets - affiliates	644		1,233
Noncurrent assets	61,395		61,754
Noncurrent assets - affiliates	512		508
Total Assets	$	66,074	$	67,051
Current liabilities	$	5,826	$	5,413
Current liabilities - affiliates	709		1,332
Noncurrent liabilities	31,337		32,310
Noncurrent liabilities - affiliates	1,075		1,047
Total Liabilities	38,947		40,102
Kinder Morgan, Inc.’s stockholders’ equity	27,127		26,949
Total Liabilities and Stockholders’ Equity	$	66,074	$	67,051

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

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

Item 4.  Controls and Procedures.

As of September 30, 2022, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2022 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 10 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2021 Form 10-K. For more information on our risk management activities, refer to Part I, Item 1, Note 6 “Risk Management” to our consolidated financial statements.

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

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

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

Subsequent to 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. 

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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.

Item 5.  Other Information.

None.

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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% Notes due 2033 and the 5.450% Notes due 2052.
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.
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 and 2021; (ii) our Consolidated Statements of Comprehensive Income for the three and nine months ended September 30, 2022 and 2021; (iii) our Consolidated Balance Sheets as of September 30, 2022 and December 31, 2021; (iv) our Consolidated Statements of Cash Flows for the nine months ended September 30, 2022 and 2021; (v) our Consolidated Statements of Stockholders’ Equity for the three and nine months ended September 30, 2022 and 2021; and (vi) the notes to our Consolidated Financial Statements.
104	Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

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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 21, 2022	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

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