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 June 30, 2023

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 July 20, 2023, the registrant had 2,228,165,367 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 Six Months Ended June 30, 2023 and 2022		4
	Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2023 and 2022		5
	Consolidated Balance Sheets - as of June 30, 2023 and December 31, 2022		6
	Consolidated Statements of Cash Flows - Six Months Ended June 30, 2023 and 2022		7
	Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30, 2023 and 2022		9
	Notes to Consolidated Financial Statements		11
	Note 1.	General	11
	Note 2.	Losses on Impairments	12
	Note 3.	Debt	13
	Note 4.	Stockholders’ Equity	14
	Note 5.	Risk Management	15
	Note 6.	Revenue Recognition	20
	Note 7.	Reportable Segments	23
	Note 8.	Income Taxes	24
	Note 9.	Litigation and Environmental	24
	Note 10.	Recent Accounting Pronouncements	29
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		30
	Results of Operations		30
	Overview		30
	Consolidated Earnings Results		33
	Non-GAAP Financial Measures		36
	Segment Earnings Results		40
	Liquidity and Capital Resources		47
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		53
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		54
Item 4.	Controls and Procedures		54
	PART II.  OTHER INFORMATION
Item 1.	Legal Proceedings		54
Item 1A.	Risk Factors		54
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		54
Item 3.	Defaults Upon Senior Securities		55
Item 4.	Mine Safety Disclosures		55
Item 5.	Other Information		55
Item 6.	Exhibits		56
	Signature		57

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

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; the outcomes of challenges to new regulations; our ability to mitigate the impacts of and recover expenditures made in respect of new regulations; and the other risks and uncertainties described in Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” Part I, Item 3. “Quantitative and Qualitative Disclosures About Market Risk” and Part II, Item 1A. “Risk Factors” in this report, as well as “Information Regarding Forward-Looking Statements” and Part I, Item 1A. “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2022 (except to the extent such information is modified or superseded by information in subsequent reports).

You should keep these risk factors in mind when considering forward-looking statements. These risk factors could cause our actual results to differ materially from those contained in any forward-looking statement. Because of these risks and uncertainties, you should not place undue reliance on any forward-looking statement. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Revenues
Services	$	2,045	$	2,011	$	4,114	$	4,061
Commodity sales	1,421		3,100		3,206		5,308
Other	35		40		69		75
Total Revenues	3,501		5,151		7,389		9,444
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	971		2,683		2,186		4,577
Operations and maintenance	685		663		1,324		1,248
Depreciation, depletion and amortization	557		543		1,122		1,081
General and administrative	169		152		335		308
Taxes, other than income taxes	103		116		213		227
Gain on divestitures and impairments, net	(13)		(11)		(13)		(21)
Other income, net	(1)		(1)		(2)		(6)
Total Operating Costs, Expenses and Other	2,471		4,145		5,165		7,414
Operating Income	1,030		1,006		2,224		2,030
Other Income (Expense)
Earnings from equity investments	208		182		373		369
Amortization of excess cost of equity investments	(19)		(19)		(36)		(38)
Interest, net	(443)		(355)		(888)		(688)
Other, net	2		23		4		42
Total Other Expense	(252)		(169)		(547)		(315)
Income Before Income Taxes	778		837		1,677		1,715
Income Tax Expense	(168)		(184)		(364)		(378)
Net Income	610		653		1,313		1,337
Net Income Attributable to Noncontrolling Interests	(24)		(18)		(48)		(35)
Net Income Attributable to Kinder Morgan, Inc.	$	586	$	635	$	1,265	$	1,302
Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.26	$	0.28	$	0.56	$	0.57
Basic and Diluted Weighted Average Shares Outstanding	2,237		2,265		2,242		2,266

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 June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Net income	$	610	$	653	$	1,313	$	1,337
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(14), $24, $(46) and $149, respectively)	49		(78)		155		(489)
Reclassification into earnings of net derivative instruments loss to net income (net of taxes of $—, $(48), $15 and $(89), respectively)	(2)		157		(51)		292
Benefit plan adjustments (net of taxes of $(1), $(1), $(2) and $(5), respectively)	4		3		8		16
Total other comprehensive income (loss)	51		82		112		(181)
Comprehensive income	661		735		1,425		1,156
Comprehensive income attributable to noncontrolling interests	(24)		(18)		(48)		(35)
Comprehensive income attributable to KMI	$	637	$	717	$	1,377	$	1,121

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)

	June 30, 2023		December 31, 2022
ASSETS
Current Assets
Cash and cash equivalents	$	497	$	745
Restricted deposits	23		49
Accounts receivable	1,284		1,840
Fair value of derivative contracts	153		231
Inventories	569		634
Other current assets	192		304
Total current assets	2,718		3,803
Property, plant and equipment, net	35,759		35,599
Investments	7,665		7,653
Goodwill	19,965		19,965
Other intangibles, net	1,696		1,809
Deferred charges and other assets	1,270		1,249
Total Assets	$	69,073	$	70,078
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,760	$	3,385
Accounts payable	1,142		1,444
Accrued interest	511		515
Fair value of derivative contracts	251		465
Other current liabilities	939		1,121
Total current liabilities	5,603		6,930
Long-term liabilities and deferred credits
Long-term debt
Outstanding	28,536		28,288
Debt fair value adjustments	96		115
Total long-term debt	28,632		28,403
Deferred income taxes	1,010		623
Other long-term liabilities and deferred credits	1,919		2,008
Total long-term liabilities and deferred credits	31,561		31,034
Total Liabilities	37,164		37,964
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,228,894,500 and 2,247,681,626 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	41,387		41,673
Accumulated deficit	(10,550)		(10,551)
Accumulated other comprehensive loss	(290)		(402)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,569		30,742
Noncontrolling interests	1,340		1,372
Total Stockholders’ Equity	31,909		32,114
Total Liabilities and Stockholders’ Equity	$	69,073	$	70,078

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)
	Six Months Ended June 30,
	2023		2022
Cash Flows From Operating Activities
Net income	$	1,313	$	1,337
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,122		1,081
Deferred income taxes	354		369
Amortization of excess cost of equity investments	36		38
Change in fair value of derivative contracts	(129)		51
Gain on divestitures and impairments, net	(13)		(21)
Earnings from equity investments	(373)		(369)
Distributions from equity investment earnings	367		348
Changes in components of working capital
Accounts receivable	573		(414)
Inventories	101		(108)
Other current assets	89		(39)
Accounts payable	(370)		499
Accrued interest, net of interest rate swaps	(6)		(53)
Other current liabilities	(132)		33
Rate reparations, refunds and other litigation reserve adjustments	(2)		(53)
Other, net	(47)		(51)
Net Cash Provided by Operating Activities	2,883		2,648
Cash Flows From Investing Activities
Acquisition of assets	(14)		—
Capital expenditures	(1,042)		(779)
Contributions to investments	(136)		(20)
Distributions from equity investments in excess of cumulative earnings	118		104
Other, net	(12)		23
Net Cash Used in Investing Activities	(1,086)		(672)
Cash Flows From Financing Activities
Issuances of debt	3,119		4,622
Payments of debt	(3,511)		(5,848)
Debt issue costs	(15)		(7)
Dividends	(1,264)		(1,247)
Repurchases of shares	(317)		(173)
Distributions to noncontrolling interests	(80)		(53)
Other, net	(3)		—
Net Cash Used in Financing Activities	(2,071)		(2,706)
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	(274)		(730)
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147
Cash, Cash Equivalents and Restricted Deposits, end of period	$	520	$	417

7

KINDER MORGAN, INC. AND SUBSIDIARIES (Continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions, unaudited)
	Six Months Ended June 30,
	2023		2022
Cash and Cash Equivalents, beginning of period	$	745	$	1,140
Restricted Deposits, beginning of period	49		7
Cash, Cash Equivalents and Restricted Deposits, beginning of period	794		1,147
Cash and Cash Equivalents, end of period	497		100
Restricted Deposits, end of period	23		317
Cash, Cash Equivalents and Restricted Deposits, end of period	520		417
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(274)	$	(730)
Non-cash Investing and Financing Activities
Assets contributed to equity investment	$	16	$	—
ROU assets and operating lease obligations recognized including adjustments	31		(8)
Increase in property, plant and equipment from both accruals and contractor retainage	74
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	919		792
Cash paid during the period for income taxes, net	9		10

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 March 31, 2023	2,241	$	22	$	41,575	$	(10,499)	$	(341)	$	30,757	$	1,357	$	32,114
Repurchases of shares	(12)			(204)						(204)				(204)
Restricted shares				19						19				19
Net income						586				586		24		610
Dividends						(637)				(637)				(637)
Distributions										—		(41)		(41)
Other				(3)						(3)				(3)
Other comprehensive income								51		51				51
Balance at June 30, 2023	2,229	$	22	$	41,387	$	(10,550)	$	(290)	$	30,569	$	1,340	$	31,909

	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 March 31, 2022	2,267	$	23	$	41,813	$	(10,544)	$	(674)	$	30,618	$	1,089	$	31,707
Repurchases of shares	(10)			(172)						(172)				(172)
Restricted shares				13						13				13
Net income						635				635		18		653
Dividends						(631)				(631)				(631)
Distributions										—		(27)		(27)
Other comprehensive income								82		82				82
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625

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

9

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY (Continued)

(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 December 31, 2022	2,248	$	22	$	41,673	$	(10,551)	$	(402)	$	30,742	$	1,372	$	32,114
Repurchases of shares	(19)			(317)						(317)				(317)
Restricted shares				34						34				34
Net income						1,265				1,265		48		1,313
Dividends						(1,264)				(1,264)				(1,264)
Distributions										—		(80)		(80)
Other				(3)						(3)				(3)
Other comprehensive income								112		112				112
Balance at June 30, 2023	2,229	$	22	$	41,387	$	(10,550)	$	(290)	$	30,569	$	1,340	$	31,909

	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 4)				(11)						(11)				(11)
Balance at January 1, 2022	2,267	23		41,795		(10,595)		(411)		30,812		1,098		31,910
Repurchases of shares	(10)			(173)						(173)				(173)
EP Trust I Preferred security conversions				1						1				1
Restricted shares				31						31				31
Net income						1,302				1,302		35		1,337
Dividends						(1,247)				(1,247)				(1,247)
Distributions										—		(53)		(53)
Other comprehensive loss								(181)		(181)				(181)
Balance at June 30, 2022	2,257	$	23	$	41,654	$	(10,540)	$	(592)	$	30,545	$	1,080	$	31,625

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

10

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 82,000 miles of pipelines, 140 terminals, 700 Bcf of working natural gas storage capacity and 3.8 Bcf per year of RNG generation capacity. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke and ethanol and other renewable fuels and feedstocks.

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 2022 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary.  If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2023 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (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 and income 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 as well as assumptions regarding future cash flows based on production growth assumptions, terminal values and discount rates. 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, 2023 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value, with our Terminals reporting unit’s fair value in excess of its carrying value by less than 10% which was impacted by a decline in market multiples.

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

11

earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock or restricted stock units issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	586	$	635	$	1,265	$	1,302
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	(4)		(2)		(7)		(6)
Net Income Allocated to Class P Stockholders	$	582	$	633	$	1,258	$	1,296
Basic Weighted Average Shares Outstanding	2,237		2,265		2,242		2,266
Basic Earnings Per Share	$	0.26	$	0.28	$	0.56	$	0.57

(a)As of June 30, 2023, there were 13 million restricted stock awards outstanding.

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

	Three Months Ended June 30,		Six Months Ended June 30,
	2023	2022	2023	2022
	(In millions on a weighted average basis)
Unvested restricted stock awards	13	12	13	13
Convertible trust preferred securities	3	3	3	3

2. Losses on Impairments

Impairments

During the first quarter of 2023, we recognized an impairment of $67 million related to our investment in Double Eagle Pipeline LLC (Double Eagle). The impairment was driven by lower expected renewal rates on contracts that expire in the second half of 2023. The impairment is recognized on our accompanying consolidated statement of income for the six months ended June 30, 2023 within “Earnings from equity investments.” Our investment in Double Eagle and associated earnings is included within our Products Pipelines business segment.

Ruby Chapter 11 Bankruptcy

On January 13, 2023, the bankruptcy court confirmed a plan of reorganization satisfactory to all interested parties regarding Ruby, which involved payment of Ruby’s outstanding senior notes with the proceeds from the sale of Ruby to Tallgrass, a settlement by KMI and Pembina of certain potential causes of action relating to the bankruptcy, and cash on hand. Our payment to the bankruptcy estate, net of payments received in respect of a long-term subordinated note receivable from Ruby, was approximately $28.5 million which was accrued for as of December 31, 2022. Consummation of the settlement and the sale of Ruby to Tallgrass occurred on January 13, 2023. We fully impaired our equity investment in Ruby in the fourth quarter of 2019 and fully impaired our investment in Ruby’s subordinated notes in the first quarter of 2021.

12

3. Debt

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

	June 30, 2023		December 31, 2022
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due August 20, 2027	$	—	$	—
$500 million credit facility due November 16, 2023	—		—
Commercial paper notes	—		—
Current portion of senior notes
3.15% due January 2023	—		1,000
Floating rate, due January 2023	—		250
3.45% due February 2023	—		625
3.50% due September 2023	600		600
5.625% due November 2023	750		750
4.15% due February 2024	650		—
4.30% due May 2024	600		—
Trust I preferred securities, 4.75%, due March 2028(a)	111		111
Current portion of other debt	49		49
Total current portion of debt	2,760		3,385
Long-term debt (excluding current portion)
Senior notes	27,899		27,638
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	320		330
Trust I preferred securities, 4.75%, due March 2028	109		109
Other	208		211
Total long-term debt	28,536		28,288
Total debt(b)	$	31,296	$	31,673

(a)Reflects the portion of cash consideration payable if all the outstanding securities as of the end of the reporting period were converted by the holders.

(b)Excludes our “Debt fair value adjustments” which, as of June 30, 2023 and December 31, 2022, increased our total debt balances by $96 million and $115 million, respectively.

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

On January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.

Credit Facilities and Restrictive Covenants

As of June 30, 2023, we had no borrowings outstanding under our credit facilities, no borrowings outstanding under our commercial paper program and $81 million in letters of credit. Our availability under our credit facilities as of June 30, 2023 was $3.9 billion. For the period ended June 30, 2023, we were in compliance with all required covenants.

13

Fair Value of Financial Instruments

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

	June 30, 2023				December 31, 2022
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	31,392	$	29,845	$	31,788	$	30,070

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

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

4. Stockholders’ Equity

Class P Common Stock

On July 19, 2017, our board of directors approved a $2 billion share buy-back program that began in December 2017. On January 18, 2023, our board of directors approved an increase in our share repurchase authorization to $3 billion. During the six months ended June 30, 2023, we repurchased 19 million of our shares for $317 million at an average price of $16.59 per share. Subsequent to June 30, 2023 and through July 20, 2023, we repurchased less than 1 million shares for $13 million at an average price of $16.93 per share. All shares we have repurchased are canceled and are no longer outstanding.

Dividends

The following table provides information about our per share dividends:

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
Per share cash dividend declared for the period	$	0.2825	$	0.2775	$	0.565	$	0.555
Per share cash dividend paid in the period	0.2825		0.2775		0.56		0.5475

On July 19, 2023, our board of directors declared a cash dividend of $0.2825 per share for the quarterly period ended June 30, 2023, which is payable on August 15, 2023 to shareholders of record as of the close of business on July 31, 2023.

Adoption of Accounting Pronouncement

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

14

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, 2022	$	(164)	$	(238)	$	(402)
Other comprehensive gain before reclassifications	155		8		163
Gain reclassified from accumulated other comprehensive loss	(51)		—		(51)
Net current-period change in accumulated other comprehensive loss	104		8		112
Balance as of June 30, 2023	$	(60)	$	(230)	$	(290)

	Net unrealized gains/(losses) on cash flow hedge derivatives		Pension and other postretirement liability adjustments		Total accumulated other comprehensive loss
	(In millions)
Balance as of December 31, 2021	$	(172)	$	(239)	$	(411)
Other comprehensive (loss) gain before reclassifications	(489)		16		(473)
Loss reclassified from accumulated other comprehensive loss	292		—		292
Net current-period change in accumulated other comprehensive loss	(197)		16		(181)
Balance as of June 30, 2022	$	(369)	$	(223)	$	(592)

5.  Risk Management

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

Energy Commodity Price Risk Management

As of June 30, 2023, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

	Net open position long/(short)
Derivatives designated as hedging contracts
Crude oil fixed price	(17.8)	MMBbl
Crude oil basis	(2.1)	MMBbl
Natural gas fixed price	(75.3)	Bcf
Natural gas basis	(61.3)	Bcf
NGL fixed price	(0.6)	MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price	(1.0)	MMBbl
Crude oil basis	(8.0)	MMBbl
Natural gas fixed price	(7.1)	Bcf
Natural gas basis	(91.5)	Bcf
NGL fixed price	(0.7)	MMBbl

15

As of June 30, 2023, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2027.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 2023:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)(b)	$	7,400	Fair value hedge	March 2035
Derivatives not designated as hedging instruments
Variable-to-fixed interest rate contracts	3,445		Mark-to-Market	December 2023

(a)The principal amount of hedged senior notes consisted of $2,050 million included in “Current portion of debt” and $5,350 million included in “Long-term debt” on our accompanying consolidated balance sheet.

(b)During the three and six months ended June 30, 2023, certain optional expedients as set forth in Topic 848 – Reference Rate Reform were elected on certain of these contracts to preserve fair value hedge accounting treatment. See Note 10 for further information on Topic 848.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 2023:

	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)	$	543	Cash flow hedge	March 2027

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

16

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
	Location	Derivatives Asset				Derivatives Liability
		June 30, 2023		December 31, 2022		June 30, 2023		December 31, 2022
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	$	101	$	150	$	(78)	$	(156)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	17		6		(38)		(91)
	Subtotal	118		156		(116)		(247)
Interest rate contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	—		—		(152)		(144)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	37		39		(234)		(261)
	Subtotal	37		39		(386)		(405)
Foreign currency contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	—		—		(9)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		—		(9)		(32)
	Subtotal	—		—		(18)		(35)
	Total	155		195		(520)		(687)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	38		80		(12)		(162)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	13		23		(1)		(19)
	Subtotal	51		103		(13)		(181)
Interest rate contracts
	Fair value of derivative contracts/(Fair value of derivative contracts)	14		1		—		—
	Subtotal	14		1		—		—
	Total	65		104		(13)		(181)
Total derivatives		$	220	$	299	$	(533)	$	(868)

17

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(a)
	Level 1		Level 2		Level 3		Gross amount						Net amount
	(In millions)
As of June 30, 2023
Energy commodity derivative contracts(b)	$	81	$	88	$	—	$	169	$	(14)	$	—	$	155
Interest rate contracts	—		51		—		51		—		—		51
As of December 31, 2022
Energy commodity derivative contracts(b)	$	115	$	144	$	—	$	259	$	(186)	$	—	$	73
Interest rate contracts	—		40		—		40		—		—		40

	Balance sheet liability fair value measurements by level								Contracts available for netting		Cash collateral posted(a)
	Level 1		Level 2		Level 3		Gross amount						Net amount
	(In millions)
As of June 30, 2023
Energy commodity derivative contracts(b)	$	(4)	$	(125)	$	—	$	(129)	$	14	$	(101)	$	(216)
Interest rate contracts	—		(386)		—		(386)		—		—		(386)
Foreign currency contracts	—		(18)		—		(18)		—		—		(18)
As of December 31, 2022
Energy commodity derivative contracts(b)	$	(23)	$	(405)	$	—	$	(428)	$	186	$	(30)	$	(272)
Interest rate contracts	—		(405)		—		(405)		—		—		(405)
Foreign currency contracts	—		(35)		—		(35)		—		—		(35)

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

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

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

Derivatives in fair value hedging relationships	Location	Gain/(loss) recognized in income  on derivative and related hedged item
		Three Months Ended June 30,				Six Months Ended June 30,
		2023		2022		2023		2022
		(In millions)
Interest rate contracts	Interest, net	$	(99)	$	(160)	$	19	$	(476)
Hedged fixed rate debt(a)	Interest, net	$	101	$	162	$	(18)	$	482

(a)As of June 30, 2023, the cumulative amount of fair value hedging adjustments to our hedged fixed rate debt was a decrease of $350 million included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

18

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 June 30,					Three Months Ended June 30,
	2023		2022			2023		2022
	(In millions)					(In millions)
Energy commodity derivative contracts	$	50	$	(70)	Revenues—Commodity sales	$	18	$	(185)
					Costs of sales	(20)		7
Interest rate contracts	—		3		Interest, net	—		—
Foreign currency contracts	13		(35)		Other, net	4		(27)
Total	$	63	$	(102)	Total	$	2	$	(205)

Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income(b)
	Six Months Ended June 30,					Six Months Ended June 30,
	2023		2022			2023		2022
	(In millions)					(In millions)
Energy commodity derivative contracts	$	185	$	(569)	Revenues—Commodity sales	$	83	$	(317)
					Costs of sales	(27)		17
Interest rate contracts	—		6		Interest, net	—		—
Foreign currency contracts	16		(75)		Other, net	10		(81)
Total	$	201	$	(638)	Total	$	66	$	(381)

(a)We expect to reclassify approximately $34 million of loss associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2023 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(b)During the three and six months ended June 30, 2022, we recognized approximate gains of $5 million 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 June 30,				Six Months Ended June 30,
		2023		2022		2023		2022
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	10	$	(17)	$	31	$	(26)
	Costs of sales	51		(8)		120		(99)
	Earnings from equity investments	—		—		1		(5)
Interest rate contracts	Interest, net	7		12		12		48
Total(a)		$	68	$	(13)	$	164	$	(82)

(a)The three and six months ended June 30, 2023 amounts include approximate gains of $7 million and $35 million, respectively, and the three and six months ended June 30, 2022 amounts include approximate losses of $38 million and $20 million, respectively. These gains and losses were associated with natural gas, crude and NGL derivative contract settlements.

19

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 June 30, 2023 and December 31, 2022, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2023 and December 31, 2022, we had cash margins of $72 million and $1 million, respectively, posted by our counterparties with us as collateral and reported within “Other current liabilities” on our accompanying consolidated balance sheets. The cash margin balance at June 30, 2023 represents our initial margin requirements of $29 million and variation margin requirements of $101 million posted by 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 June 30, 2023, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one notch, we would not be required to post additional collateral. If we were downgraded two notches, we estimate that we would be required to post $52 million of additional collateral.

6. Revenue Recognition

Disaggregation of Revenues

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

	Three Months Ended June 30, 2023
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	849	$	49	$	208	$	1	$	—	$	1,107
Fee-based services	248		246		98		10		—		602
Total services	1,097		295		306		11		—		1,709
Commodity sales
Natural gas sales	484		—		—		13		(2)		495
Product sales	233		380		9		277		(3)		896
Total commodity sales	717		380		9		290		(5)		1,391
Total revenues from contracts with customers	1,814		675		315		301		(5)		3,100
Other revenues(c)
Leasing services(d)	120		52		163		11		—		346
Derivatives adjustments on commodity sales	40		2		—		(14)		—		28
Other	17		6		—		4		—		27
Total other revenues	177		60		163		1		—		401
Total revenues	$	1,991	$	735	$	478	$	302	$	(5)	$	3,501

20

	Three Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	849	$	60	$	198	$	1	$	(1)	$	1,107
Fee-based services	234		242		96		11		—		583
Total services	1,083		302		294		12		(1)		1,690
Commodity sales
Natural gas sales	1,810		—		—		24		(6)		1,828
Product sales	410		640		7		404		13		1,474
Total commodity sales	2,220		640		7		428		7		3,302
Total revenues from contracts with customers	3,303		942		301		440		6		4,992
Other revenues(c)
Leasing services(d)	118		49		149		15		—		331
Derivatives adjustments on commodity sales	(81)		—		—		(121)		—		(202)
Other	16		5		—		9		—		30
Total other revenues	53		54		149		(97)		—		159
Total revenues	$	3,356	$	996	$	450	$	343	$	6	$	5,151

	Six Months Ended June 30, 2023
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,766	$	89	$	415	$	1	$	(1)	$	2,270
Fee-based services	484		486		196		20		—		1,186
Total services	2,250		575		611		21		(1)		3,456
Commodity sales
Natural gas sales	1,283		—		—		33		(4)		1,312
Product sales	507		716		13		545		(4)		1,777
Total commodity sales	1,790		716		13		578		(8)		3,089
Total revenues from contracts with customers	4,040		1,291		624		599		(9)		6,545
Other revenues(c)
Leasing services(d)	237		99		315		25		—		676
Derivatives adjustments on commodity sales	147		1		—		(34)		—		114
Other	33		12		—		9		—		54
Total other revenues	417		112		315		—		—		844
Total revenues	$	4,457	$	1,403	$	939	$	599	$	(9)	$	7,389

21

	Six Months Ended June 30, 2022
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,788	$	119	$	386	$	1	$	(2)	$	2,292
Fee-based services	447		476		194		24		—		1,141
Total services	2,235		595		580		25		(2)		3,433
Commodity sales
Natural gas sales	3,036		—		—		44		(10)		3,070
Product sales	752		1,066		11		752		(3)		2,578
Total commodity sales	3,788		1,066		11		796		(13)		5,648
Total revenues from contracts with customers	6,023		1,661		591		821		(15)		9,081
Other revenues(c)
Leasing services(d)	235		93		289		28		—		645
Derivatives adjustments on commodity sales	(120)		(3)		—		(220)		—		(343)
Other	31		11		—		19		—		61
Total other revenues	146		101		289		(173)		—		363
Total revenues	$	6,169	$	1,762	$	880	$	648	$	(15)	$	9,444

(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 5 for additional information related to our derivative contracts.

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

Contract Balances

As of June 30, 2023 and December 31, 2022, our contract asset balances were $34 million and $33 million, respectively. Of the contract asset balance at December 31, 2022, $20 million was transferred to accounts receivable during the six months ended June 30, 2023. As of June 30, 2023 and December 31, 2022, our contract liability balances were $231 million and $204 million, respectively. Of the contract liability balance at December 31, 2022, $50 million was recognized as revenue during the six months ended June 30, 2023.

22

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 June 30, 2023 that we will invoice or transfer from contract liabilities and recognize in future periods:

Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2023	$	2,248
2024	3,888
2025	3,187
2026	2,763
2027	2,353
Thereafter	13,588
Total	$	28,027

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

7.  Reportable Segments

Financial information by segment follows:

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Revenues
Natural Gas Pipelines
Revenues from external customers	$	1,987	$	3,363	$	4,450	$	6,156
Intersegment revenues	4		(7)		7		13
Products Pipelines	735		996		1,403		1,762
Terminals
Revenues from external customers	477		449		937		878
Intersegment revenues	1		1		2		2
CO2	302		343		599		648
Corporate and intersegment eliminations	(5)		6		(9)		(15)
Total consolidated revenues	$	3,501	$	5,151	$	7,389	$	9,444

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	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines	$	1,255	$	1,134	$	2,750	$	2,318
Products Pipelines	285		299		469		598
Terminals	261		253		515		491
CO2	175		212		347		404
Total Segment EBDA	1,976		1,898		4,081		3,811
DD&A	(557)		(543)		(1,122)		(1,081)
Amortization of excess cost of equity investments	(19)		(19)		(36)		(38)
General and administrative and corporate charges	(179)		(144)		(358)		(289)
Interest, net	(443)		(355)		(888)		(688)
Income tax expense	(168)		(184)		(364)		(378)
Total consolidated net income	$	610	$	653	$	1,313	$	1,337

	June 30, 2023		December 31, 2022
	(In millions)
Assets
Natural Gas Pipelines	$	47,406	$	47,978
Products Pipelines	8,832		8,985
Terminals	8,292		8,357
CO2	3,505		3,449
Corporate assets(b)	1,038		1,309
Total consolidated assets	$	69,073	$	70,078

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

(b)Includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas and miscellaneous corporate assets (such as information technology, telecommunications equipment and legacy activity) not allocated to our reportable segments.

8.  Income Taxes

Income tax expense included on our accompanying consolidated statements of income is as follows:

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(In millions, except percentages)
Income tax expense	$	168		$	184		$	364		$	378
Effective tax rate	21.6		%	22.0		%	21.7		%	22.0		%

The effective tax rates for the three and six months ended June 30, 2023 and 2022 are higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline, NGPL Holdings and Products (SE) Pipe Line Company.

9.   Litigation and Environmental

We and our subsidiaries are parties to various legal, regulatory and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account established reserves and insurance, that the ultimate resolution of such items will not have a material adverse impact to our business. We believe we have meritorious defenses to

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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.

Gulf LNG Facility Disputes

On September 28, 2018, GLNG filed a lawsuit against Eni S.p.A. in the Supreme Court of the State of New York in New York County to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. on December 10, 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). The suit to enforce the Guarantee against Eni S.p.A. was filed after an arbitration tribunal delivered an award on June 29, 2018 which called for the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response to GLNG’s lawsuit to enforce the Guarantee, Eni S.p.A. filed counterclaims and other claims based on the terminal use agreement and a parent direct agreement with Gulf LNG Energy (Port), LLC. The foregoing counterclaims asserted by Eni S.p.A sought unspecified damages and involved the same substantive allegations which were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC (ALSS), a consortium of international oil companies including Eni S.p.A. On January 4, 2022, the trial court granted Eni S.p.A’s motion for summary judgment on the claims asserted by GLNG to enforce the Guarantee. GLNG filed an appeal of the trial court’s decision to the state Appellate Division. The Appellate Division denied GLNG’s appeal on February 9, 2023 and denied our motion for rehearing on July 6, 2023. GLNG may pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court. With respect to the counterclaims and other claims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment on June 13, 2023 and directed the clerk to enter judgment dismissing all of Eni S.p.A.’s claims. Upon entry of judgment, Eni S.p.A. may choose to take an appeal to the state Appellate Division. We intend to vigorously pursue a favorable and expeditious resolution of all claims on appeal.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On November 21, 2022, Freeport filed a notice of appeal to the 14th Court of Appeals, where the matter remains pending. We believe that our declaration of force majeure was valid and we intend to continue to vigorously defend this case.

Pension Plan Litigation

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

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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 investigated the incident and issued its report on April 27, 2023. EPNG completed the physical work on Line 2000 in accordance with PHMSA’s requirements and returned the pipeline to commercial service in February 2023. While no litigation is pending at this time, we notified our insurers of the incident and do not expect that the resolution of claims will have a material adverse impact to our business.

General

As of June 30, 2023 and December 31, 2022, our total reserve for legal matters was $39 million and $70 million, respectively.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal, CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations.

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

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

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

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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 December 2024. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. Because costs associated with any remedial plan are expected to be spread over at least several years, we do not anticipate that our share of the costs of the remediation will have a material adverse impact to our business.

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

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. 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, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey. We believe our share of the costs to resolve this matter, including our share of the settlement with EPA and the costs to remediate the Site, if any, will not have a material adverse impact to our business.

Louisiana Governmental Coastal Zone Erosion Litigation

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

On November 8, 2013, the Parish of Plaquemines, Louisiana and others 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. The case was 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 subsequently remanded to the state district courts for Plaquemines and Cameron Parishes, respectively. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.

On March 29, 2019, the City of New Orleans and Orleans Parish (collectively, Orleans) and others 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 January 2020, the U.S. District Court ordered the case to be stayed and

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administratively closed pending the resolution of issues in a separate case to which SNG is not a party. On May 3, 2023, the U.S. District Court re-opened the case. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.

Products Pipeline Incident, Walnut Creek, California

On November 20, 2020, SFPP identified an issue on its Line Section 16 (LS-16) which transports petroleum products in California from Concord to San Jose. We shut down the pipeline and notified the appropriate regulatory agencies of a “threatened release” of gasoline. We investigated the issue 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. On May 8, 2023, the California Attorney General confirmed SFPP had complied with the terms of the plea agreement.

Since the November 2020 release, we have cooperated fully with federal and state agencies and worked diligently to remediate the affected areas. There may be civil enforcement actions by federal and state agencies arising from the November 2020 release. Further, we anticipate 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, if any, or 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 June 30, 2023 and December 31, 2022, we have accrued a total reserve for environmental liabilities in the amount of $212 million and $221 million, respectively. In addition, as of June 30, 2023 and December 31, 2022, we had receivables of $11 million and $12 million, respectively, recorded for expected cost recoveries that have been deemed probable.

Challenge to Federal “Good Neighbor Plan”

On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit seeking review of the EPA’s final action promulgating the EPA’s final rule known as the “Good Neighbor Plan” (the Plan). The Plan was published in the Federal Register as a final rule on June 5, 2023. The Plan is a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone National Ambient Air Quality Standards. We believe that the Plan is deeply flawed and that numerous meritorious bases for challenging the Plan exist. If the Plan were fully implemented, its emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. If the Plan were to remain in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to state implementation plan disapprovals and no successful challenge to the Plan), we anticipate that it would have a material impact on us. Impacts are difficult to predict, particularly given the extensive pending litigation. We would seek to mitigate the impacts, and to recover expenditures through adjustments to our rates on our regulated assets where available.

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10. Recent Accounting Pronouncements

Accounting Standards Updates

Reference Rate Reform (Topic 848)

On March 12, 2020, the FASB issued ASU No. 2020-04, “Reference Rate Reform – Facilitation of the Effects of Reference Rate Reform on Financial Reporting.” This ASU provides temporary optional expedients and exceptions to GAAP guidance on contract modifications and hedge accounting to ease the financial reporting burdens of the expected market transition from LIBOR and other interbank offered rates to alternative reference rates, such as the Secured Overnight Financing Rate (SOFR). Entities can elect not to apply certain modification accounting requirements to contracts affected by reference rate reform, if certain criteria are met. An entity that makes this election would not have to remeasure the contracts at the modification date or reassess a previous accounting determination. Entities can also elect various optional expedients that would allow them to continue applying hedge accounting for hedging relationships affected by reference rate reform, if certain criteria are met.

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

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

The guidance was effective upon issuance.

During the six months ended June 30, 2023 we amended certain of our existing fixed-to-variable interest rate swap agreements, which were designated as fair value hedges, to transition the variable leg of such agreements from LIBOR to SOFR. These agreements contain a combined notional principal amount of $1,225 million and convert a portion of our fixed rate debt to variable rates. 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. See Note 5 “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 2022 Form 10-K; (ii) our management’s discussion and analysis of financial condition and results of operations included in our 2022 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report and in our 2022 Form 10-K; and (iv) “Risk Factors” in Part II, Item 1A of this report and Part I, Item 1 in our 2022 Form 10-K.

Acquisition

Following is an acquisition we made during the six months ended June 30, 2023.

Event	Description	Business Segment
Diamond M Field acquisition (June 2023)	We closed on our acquisition of Parallel Petroleum’s interest in the Diamond M Field for $15 million, before working capital adjustments. The acquired field is located directly adjacent to our existing SACROC field. It is currently under waterflood, but it is expected to be very receptive to CO2 flooding given its proximity to SACROC. Implementation of enhanced oil recovery is projected to begin in 2024.	CO2 business segment (Oil and Producing activities)

2023 Dividends and Discretionary Capital

We expect to declare dividends of $1.13 per share for 2023, a 2% increase from the 2022 declared dividends of $1.11 per share. We now expect to invest $2.1 billion in expansion projects, acquisitions, and contributions to joint ventures during 2023.

The expectations for 2023 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance.  Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement.

Results of Operations

Overview

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

GAAP Financial Measures

The Consolidated Earnings Results for the three and six months ended June 30, 2023 and 2022 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 7 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation and environmental expenses, and shared corporate services including accounting, information technology, human resources and legal services.

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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 our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making 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 most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation and casualty losses). (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “Amounts from Joint Ventures” below). The following table summarizes our Certain Items for the three and six months ended June 30, 2023 and 2022, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Certain Items
Fair value amortization	$	4	$	(3)	$	—	$	(7)
Change in fair value of derivative contracts(a)	(62)		(27)		(130)		55
Loss on impairment	—		—		67		—
Income tax Certain Items(b)	12		5		13		(15)
Other	—		11		—		18
Total Certain Items(c)(d)	$	(46)	$	(14)	$	(50)	$	51

(a)Gains or losses are reflected when realized.

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

(c)Amounts for the periods ending June 30, 2023 and 2022 include the following amounts reported within “Earnings from equity investments” on the accompanying consolidated statements of income: (i) $1 million and none for the three-month periods, respectively, and $(1) million and $5 million for the six-month periods, respectively, included within “Change in fair value of derivative contracts” and (ii) $67 million for the 2023 six-month period only included within “Loss on impairment” for a non-cash impairment related to our investment in Double Eagle Pipeline LLC in our Products Pipelines business segment (see Note 2 “Losses on Impairments—Impairments”).

(d)Amounts for the periods ending June 30, 2023 and 2022 include, in the aggregate, $(5) million and $(17) million for the three-month periods, respectively, and $(13) million and $(61) million for the six-month periods, respectively, included within “Interest, net” on the accompanying consolidated statements of income which consist of (i) $4 million and $(3) million for the three-month periods, respectively, and none and $(7) million for the six-month periods, respectively, of “Fair value amortization” and (ii) $(9) million and $(14) million for the three-month periods, respectively, and $(13) million and $(54) million for the six-month periods, respectively, of “Change in fair value of derivative contracts.”

Adjusted Earnings

Adjusted Earnings is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Earnings is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our

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ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Earnings is Net income attributable to Kinder Morgan, Inc. Adjusted Earnings per share uses Adjusted Earnings and applies the same two-class method used in arriving at basic earnings per share. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Earnings” below.

DCF

DCF is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items, and further for DD&A and amortization of excess cost of equity investments, income tax expense, cash taxes, sustaining capital expenditures and other items. We also adjust amounts from joint ventures for income taxes, DD&A, cash taxes and sustaining capital expenditures (see “Amounts from Joint Ventures” below). DCF is a significant performance measure used by us, investors and other external users of our financial statements to evaluate our performance and to measure and estimate the ability of our assets to generate economic earnings after paying interest expense, paying cash taxes and expending sustaining capital. DCF provides additional insight into the specific costs associated with our assets in the current period and facilitates period-to-period comparisons of our performance from ongoing business activities. DCF is also used by us, investors, and other external users to compare the performance of companies across our industry. DCF per share serves as the primary financial performance target for purposes of annual bonuses under our annual incentive compensation program and for performance-based vesting of equity compensation grants under our long-term incentive compensation program. DCF should not be used as an alternative to net cash provided by operating activities computed under GAAP. We believe the GAAP measure most directly comparable to DCF is Net income attributable to Kinder Morgan, Inc. DCF per share is DCF divided by average outstanding shares, including restricted stock awards that participate in dividends. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting Segment EBDA for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—Non-GAAP Financial Measures—Reconciliation of Segment EBDA to Adjusted Segment EBDA” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A and amortization of excess cost of equity investments, income tax expense and interest. We also include amounts from joint ventures for income taxes and DD&A (see “Amounts from Joint Ventures” below). Adjusted EBITDA is used by management, investors and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. 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; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the

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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 June 30, 2023, by subtracting the following amounts from our debt balance of $31,392 million: (i) cash and cash equivalents of $497 million; (ii) debt fair value adjustments of $96 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $2 million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.

Consolidated Earnings Results

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

	Three Months Ended June 30,
	2023		2022		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	3,501	$	5,151	$	(1,650)	(32)	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(971)		(2,683)		1,712		64	%
Operations and maintenance	(685)		(663)		(22)		(3)	%
DD&A	(557)		(543)		(14)		(3)	%
General and administrative	(169)		(152)		(17)		(11)	%
Taxes, other than income taxes	(103)		(116)		13		11	%
Gain on divestitures and impairments, net	13		11		2		18	%
Other income, net	1		1		—		—	%
Total Operating Costs, Expenses and Other	(2,471)		(4,145)		1,674		40	%
Operating Income	1,030		1,006		24		2	%
Other Income (Expense)
Earnings from equity investments	208		182		26		14	%
Amortization of excess cost of equity investments	(19)		(19)		—		—	%
Interest, net	(443)		(355)		(88)		(25)	%
Other, net	2		23		(21)		(91)	%
Total Other Expense	(252)		(169)		(83)		(49)	%
Income Before Income Taxes	778		837		(59)		(7)	%
Income Tax Expense	(168)		(184)		16		9	%
Net Income	610		653		(43)		(7)	%
Net Income Attributable to Noncontrolling Interests	(24)		(18)		(6)		(33)	%
Net Income Attributable to Kinder Morgan, Inc.	$	586	$	635	$	(49)	(8)	%
Basic and diluted earnings per share	$	0.26	$	0.28	$	(0.02)	(7)	%
Basic and diluted weighted average shares outstanding	2,237		2,265		(28)		(1)	%
Declared dividends per share	$	0.2825	$	0.2775	$	0.005	2	%

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	Six Months Ended June 30,
	2023		2022		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	7,389	$	9,444	$	(2,055)	(22)	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(2,186)		(4,577)		2,391		52	%
Operations and maintenance	(1,324)		(1,248)		(76)		(6)	%
DD&A	(1,122)		(1,081)		(41)		(4)	%
General and administrative	(335)		(308)		(27)		(9)	%
Taxes, other than income taxes	(213)		(227)		14		6	%
Gain on divestitures and impairments, net	13		21		(8)		(38)	%
Other income, net	2		6		(4)		(67)	%
Total Operating Costs, Expenses and Other	(5,165)		(7,414)		2,249		30	%
Operating Income	2,224		2,030		194		10	%
Other Income (Expense)
Earnings from equity investments	373		369		4		1	%
Amortization of excess cost of equity investments	(36)		(38)		2		5	%
Interest, net	(888)		(688)		(200)		(29)	%
Other, net	4		42		(38)		(90)	%
Total Other Expense	(547)		(315)		(232)		(74)	%
Income Before Income Taxes	1,677		1,715		(38)		(2)	%
Income Tax Expense	(364)		(378)		14		4	%
Net Income	1,313		1,337		(24)		(2)	%
Net Income Attributable to Noncontrolling Interests	(48)		(35)		(13)		(37)	%
Net Income Attributable to Kinder Morgan, Inc.	$	1,265	$	1,302	$	(37)	(3)	%
Basic and diluted earnings per share	$	0.56	$	0.57	$	(0.01)	(2)	%
Basic and diluted weighted average shares outstanding	2,242		2,266		(24)		(1)	%
Declared dividends per share	$	0.565	$	0.555	$	0.01	2	%

Our consolidated revenues include fees for transportation and other midstream services that we perform. Fluctuations in our consolidated services revenue largely reflect changes in volumes and/or in the rates we charge. Our consolidated costs of sales and sales revenues also include purchases and sales of natural gas and products (which means, collectively, NGL, crude oil, CO2 and transmix) and related derivative activity. Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the associated costs of sales will usually have a commensurate and offsetting impact, except for the CO2 segment, which produces, instead of purchases, the crude oil and CO2 it sells. Additionally, fluctuations in revenues and costs of sales may be further impacted by gains or losses from derivative contracts that we use to manage our commodity price risk.

Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable three and six-month periods ended June 30, 2023 and 2022:

Revenues

Revenues decreased $1,650 million and $2,055 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods. The decreases were primarily due to lower natural gas sales of $1,333 million and $1,758 million, respectively, and product sales of $578 million and $801 million, respectively, driven primarily by lower commodity prices and, to a lesser extent, lower volumes, partially offset by the impact of derivative contracts used to hedge commodity sales of $230 million and $457 million, respectively, which includes both realized and unrealized gains and losses from derivatives. These decreases in revenues were offset by corresponding decreases in our costs of sales as described below under “Operating Costs, Expenses and Other—Costs of sales.”

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Operating Costs, Expenses and Other

Costs of sales

Costs of sales decreased $1,712 million and $2,391 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods. The decreases were primarily due to lower costs of sales for natural gas of $1,328 million and $1,731 million, respectively, and products of $324 million and $449 million, respectively, driven primarily by lower commodity prices and, to a lesser extent, lower volumes. Costs of sales was further reduced by the impacts of derivative contracts used to hedge commodity purchases of $32 million and $175 million, respectively, which includes both realized and unrealized gains and losses from derivatives.

Operations and Maintenance

Operations and maintenance increased $22 million and $76 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods. The increases were primarily driven by higher labor costs, and further in the six-month period by materials and supplies, services and fuel costs related to greater activity levels and inflation.

Other Income (Expense)

Interest, net

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount.  Our interest expense, net increased $88 million and $200 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods. The increases were primarily due to higher realized floating rates associated with interest rate swaps and changes in fair value of interest rate swaps.

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Non-GAAP Financial Measures

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except per share amounts)
Net income attributable to Kinder Morgan, Inc.	$	586	$	635	$	1,265	$	1,302
Certain Items(a)
Fair value amortization	4		(3)		—		(7)
Change in fair value of derivative contracts	(62)		(27)		(130)		55
Loss on impairment	—		—		67		—
Income tax Certain Items	12		5		13		(15)
Other	—		11		—		18
Total Certain Items	(46)		(14)		(50)		51
Adjusted Earnings	$	540	$	621	$	1,215	$	1,353
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to DCF
Net income attributable to Kinder Morgan, Inc.	$	586	$	635	$	1,265	$	1,302
Total Certain Items(b)	(46)		(14)		(50)		51
DD&A	557		543		1,122		1,081
Amortization of excess cost of equity investments	19		19		36		38
Income tax expense(c)	156		179		351		393
Cash taxes	(8)		(8)		(9)		(9)
Sustaining capital expenditures	(195)		(176)		(351)		(291)
Amounts from joint ventures
Unconsolidated joint venture DD&A	80		76		161		153
Remove consolidated joint venture partners’ DD&A	(15)		(11)		(31)		(22)
Unconsolidated joint venture income tax expense(d)(e)	20		20		46		41
Unconsolidated joint venture cash taxes(d)	(52)		(39)		(52)		(39)
Unconsolidated joint venture sustaining capital expenditures	(46)		(39)		(75)		(51)
Remove consolidated joint venture partners’ sustaining capital expenditures	2		2		4		4
Other items(f)	18		(11)		33		(20)
DCF	$	1,076	$	1,176	$	2,450	$	2,631
Adjusted Earnings per share	$	0.24	$	0.27	$	0.54	$	0.59
Weighted average shares outstanding for dividends(g)	2,250		2,277		2,255		2,279
DCF per share	$	0.48	$	0.52	$	1.09	$	1.15
Declared dividends per share	$	0.2825	$	0.2775	$	0.565	$	0.555

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

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

(c)To avoid duplication, adjustments for income tax expense for the periods ended June 30, 2023 and 2022 exclude $12 million and $5 million for the three-month periods, respectively, and $13 million and $(15) million for the six-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

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

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

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

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

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Net income attributable to Kinder Morgan, Inc.	$	586	$	635	$	1,265	$	1,302
Certain Items(a)
Fair value amortization	4		(3)		—		(7)
Change in fair value of derivative contracts	(62)		(27)		(130)		55
Loss on impairment	—		—		67		—
Income tax Certain Items	12		5		13		(15)
Other	—		11		—		18
Total Certain Items	(46)		(14)		(50)		51
DD&A	557		543		1,122		1,081
Amortization of excess cost of equity investments	19		19		36		38
Income tax expense(b)	156		179		351		393
Interest, net(c)	448		372		901		749
Amounts from joint ventures
Unconsolidated joint venture DD&A	80		76		161		153
Remove consolidated joint venture partners’ DD&A	(15)		(11)		(31)		(22)
Unconsolidated joint venture income tax expense(d)	20		20		46		41
Adjusted EBITDA	$	1,805	$	1,819	$	3,801	$	3,786

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

(b)To avoid duplication, adjustments for income tax expense for the periods ended June 30, 2023 and 2022 exclude $12 million and $5 million for the three-month periods, respectively, and $13 million and $(15) million for the six-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(c)To avoid duplication, adjustments for interest, net for the periods ended June 30, 2023 and 2022 exclude $(5) million and $(17) million for the three-month periods, respectively, and $(13) million and $(61) million for the six-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.

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

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Below is a discussion of significant changes in our Adjusted Earnings, DCF and Adjusted EBITDA:

	Three Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Adjusted Earnings	$	540	$	621	$	(81)
DCF	1,076		1,176		(100)
Adjusted EBITDA	1,805		1,819		(14)

	Six Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Adjusted Earnings	$	1,215	$	1,353	$	(138)
DCF	2,450		2,631		(181)
Adjusted EBITDA	3,801		3,786		15

Adjusted Earnings decreased $81 million and $138 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods and were driven by lower commodity prices and higher interest expense. These items also affected DCF. The $100 million and $181 million decreases in DCF for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods were further impacted by increases in sustaining capital expenditures. Adjusted EBITDA decreased $14 million and increased $15 million for the three and six months ended June 30, 2023, respectively, as compared to the respective prior year periods which were also impacted by lower commodity prices offset by, to a greater extent in the six-month period, favorable margins from our Natural Gas Pipeline business segment.

General and Administrative and Corporate Charges

	Three Months Ended June 30,				Earnings increase/(decrease)
	2023		2022
	(In millions, except percentages)
General and administrative	$	(169)	$	(152)	$	(17)	(11)	%
Corporate (charges) benefit	(10)		8		(18)		(225)	%
General and administrative and corporate charges	$	(179)	$	(144)	$	(35)	(24)	%

	Six Months Ended June 30,				Earnings increase/(decrease)
	2023		2022
	(In millions, except percentages)
General and administrative	$	(335)	$	(308)	$	(27)	(9)	%
Corporate (charges) benefit	(23)		19		(42)		(221)	%
General and administrative and corporate charges	$	(358)	$	(289)	$	(69)	(24)	%

General and administrative expenses increased $17 million and $27 million and corporate (charges) benefit increased $18 million and $42 million for the three and six months ended June 30, 2023 when compared with the respective prior year periods, respectively. The combined changes were primarily due to higher pension costs of $26 million and $48 million, and higher labor and benefit-related costs of $15 million and $24 million, for the three and six months ended June 30, 2023, respectively.

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Reconciliation of Segment EBDA to Adjusted Segment EBDA

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA	$	1,255	$	1,134	$	2,750	$	2,318
Certain Items(b)
Change in fair value of derivative contracts	(54)		(12)		(119)		94
Other	—		11		—		18
Natural Gas Pipelines Adjusted Segment EBDA	$	1,201	$	1,133	$	2,631	$	2,430
Products Pipelines Segment EBDA	$	285	$	299	$	469	$	598
Certain Items(b)
Change in fair value of derivative contracts	1		—		1		—
Loss on impairment	—		—		67		—
Products Pipelines Adjusted Segment EBDA	$	286	$	299	$	537	$	598
Terminals Segment EBDA	$	261	$	253	$	515	$	491
CO2 Segment EBDA	$	175	$	212	$	347	$	404
Certain Items(b)
Change in fair value of derivative contracts	—		(1)		1		15
CO2 Adjusted Segment EBDA	$	175	$	211	$	348	$	419

(a)Includes revenues, earnings from equity investments, operating expenses, gain on divestitures and impairments, net, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.

(b)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.

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Segment Earnings Results

Natural Gas Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except operating statistics)
Revenues	$	1,991	$	3,356	$	4,457	$	6,169
Operating expenses	(928)		(2,374)		(2,105)		(4,158)
Gain on divestitures and impairments, net	9		—		9		—
Other income	1		1		2		2
Earnings from equity investments	175		149		375		303
Other, net	7		2		12		2
Segment EBDA	1,255		1,134		2,750		2,318
Certain Items:
Change in fair value of derivative contracts	(54)		(12)		(119)		94
Other	—		11		—		18
Certain Items(a)	(54)		(1)		(119)		112
Adjusted Segment EBDA	$	1,201	$	1,133	$	2,631	$	2,430
Change from prior period	Increase/(Decrease)
Segment EBDA	$	121			$	432
Adjusted Segment EBDA	$	68			$	201
Volumetric data(b)
Transport volumes (BBtu/d)	39,173		37,465		39,783		38,387
Sales volumes (BBtu/d)	2,220		2,579		2,169		2,547
Gathering volumes (BBtu/d)	3,518		2,944		3,398		2,856
NGLs (MBbl/d)	34		30		33		31

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending June 30, 2023 and 2022 Certain Items of (i) $(55) million and $(12) million for the three-month periods, respectively, and $(118) million and $89 million for the six-month periods, respectively, are associated with our Midstream business; (ii) $1 million and none for the three-month periods, respectively, and $(1) million and $5 million for the six-month periods, respectively, are associated with our East business; and (iii) none and $11 million for the three-month periods, respectively, and none and $18 million for the six-month periods, respectively, are associated with our West business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

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

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Below are the changes in Segment EBDA:

	Three Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Midstream	$	394	$	340	$	54
East	645		599		46
West	216		195		21
Total Natural Gas Pipelines Segment EBDA	$	1,255	$	1,134	$	121

	Six Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Midstream	$	934	$	623	$	311
East	1,341		1,246		95
West	475		449		26
Total Natural Gas Pipelines Segment EBDA	$	2,750	$	2,318	$	432

The changes in Segment EBDA for our Natural Gas Pipelines business segment in the comparable three and six-month periods ended June 30, 2023 and 2022 are explained by the following discussion:

•The $54 million (16%) and $311 million (50%) increases, respectively, in Midstream were affected by period-over-period decreases in costs of sales and, to a lesser extent, in revenues related to the impacts of non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, which we treated as Certain Items.

In addition, Midstream was favorably impacted by (i) higher sales margins on our Texas intrastate natural gas pipeline operations largely driven by realized gains on sales hedges partially offset by lower sales volumes; (ii) higher commodity sales margin driven primarily by higher volumes on our Altamont asset; and (iii) higher volumes partially offset by overall lower rates on our KinderHawk assets. These impacts were partially offset by lower service fee revenues and lower deficiency revenues as a result of renegotiated contracts at lower rates on our South Texas assets. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

•The $46 million (8%) and $95 million (8%) increases, respectively, in East were primarily due to higher equity earnings from Midcontinent Express Pipeline LLC, driven by new customer contracts entered into in the later part of 2022, higher revenues on our Stagecoach assets as a result of increased demand in its services due to favorable pricing and higher revenues on TGP primarily due to increased rates on capacity sales.

•The $21 million (11%) and $26 million (6%) increases, respectively, in West were primarily due to higher earnings from EPNG due to (i) increased revenues from the return of a pipeline segment to service in February 2023 and (ii) an increase in gas sales margin, partially offset by lower revenues from Cheyenne Plains Gas Pipeline Company, L.L.C. and Wyoming Interstate Company, L.L.C., principally resulting from contract expirations in December 2022.

In addition, the West was affected by costs associated with the EPNG pipeline rupture for the 2022 periods only, which we treated as Certain Items.

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Products Pipelines

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except operating statistics)
Revenues	$	735	$	996	$	1,403	$	1,762
Operating expenses	(474)		(717)		(914)		(1,214)
Gain on divestitures and impairments, net	—		—		—		12
Earnings (loss) from equity investments	24		20		(20)		38
Segment EBDA	285		299		469		598
Certain Items:
Change in fair value of derivative contracts	1		—		1		—
Loss on impairment	—		—		67		—
Certain Items(a)	1		—		68		—
Adjusted Segment EBDA	$	286	$	299	$	537	$	598
Change from prior period	Increase/(Decrease)
Segment EBDA	$	(14)			$	(129)
Adjusted Segment EBDA	$	(13)			$	(61)
Volumetric data(b)
Gasoline(c)	1,004		1,017		976		979
Diesel fuel	356		372		342		371
Jet fuel	290		267		281		255
Total refined product volumes	1,650		1,656		1,599		1,605
Crude and condensate	495		478		477		482
Total delivery volumes (MBbl/d)	2,145		2,134		2,076		2,087

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 and 2022 Certain Items of (i) $1 million and $(1) million, respectively, for both the three-month and six-month periods are associated with our Southeast Refined Products business and (ii) none and $1 million for the three-month periods, respectively, and $67 million and $1 million for the six-month periods, respectively, are associated with our Crude and Condensate business. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

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

(c)Volumes include ethanol pipeline volumes.

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Below are the changes in Segment EBDA:

	Three Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Southeast Refined Products	$	63	$	80	$	(17)
Crude and Condensate	87		88		(1)
West Coast Refined Products	135		131		4
Total Products Pipelines Segment EBDA	$	285	$	299	$	(14)

	Six Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Southeast Refined Products	$	134	$	153	$	(19)
Crude and Condensate	92		177		(85)
West Coast Refined Products	243		268		(25)
Total Products Pipelines Segment EBDA	$	469	$	598	$	(129)

The changes in Segment EBDA for our Products Pipelines business segment in the comparable three and six-month periods ended June 30, 2023 and 2022 are explained by the following discussion:

•The $17 million (21%) and $19 million (12%) decreases, respectively, in Southeast Refined Products were driven by lower earnings at our Transmix processing operations primarily due to lower prices, partially offset by higher volumes and a rate escalation on Central Florida Pipeline LLC.

•The $1 million (1%) and $85 million (48%) decreases, respectively, in Crude and Condensate was affected by a year-to-date decrease of $67 million to equity earnings for a non-cash impairment related to our investment in Double Eagle Pipeline LLC, which we treated as a Certain Item.

In addition, Crude and Condensate was unfavorably impacted by (i) lower earnings from Kinder Morgan Crude & Condensate pipeline driven primarily by a decrease in revenues as a result of re-contracting at lower rates and lower deficiency revenues and (ii) from our Double H pipeline due to lower volumes. These impacts were partially offset by (i) an increase in equity earnings, excluding the impairment discussed above, from Double Eagle Pipeline LLC due to an increase in deficiency revenues and volumes and (ii) higher earnings from our KM Condensate Processing facility as a result of rate escalations. Our Crude and Condensate business also had lower revenues with a corresponding decrease in costs of sales, resulting from decreased commodity pricing and lower volumes.

•The $4 million (3%) increase and $25 million (9%) decrease, respectively, in West Coast Refined Products were impacted by increased revenues from our Pacific operations as a result of new contracts and from Calnev Pipe Line LLC driven by higher rates, both reduced by higher operating costs driven, to a greater extent in the six-month period, by net changes in product gains and losses. The year-to-date decrease was further impacted by a gain on sale of land in the 2022 period at Calnev Pipe Line LLC.

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Terminals

	Three Months Ended June 30,						Six Months Ended June 30,
	2023			2022			2023			2022
	(In millions, except operating statistics)
Revenues	$	478		$	450		$	939		$	880
Operating expenses	(224)			(216)			(434)			(415)
Gain on divestitures and impairments, net	3			12			3			9
Other income	—			—			—			4
Earnings from equity investments	2			4			4			8
Other, net	2			3			3			5
Segment EBDA	$	261		$	253		$	515		$	491
Change from prior period	Increase/(Decrease)
Segment EBDA	$	8					$	24
Volumetric data(a)
Liquids leasable capacity (MMBbl)	78.6			78.2			78.6			78.2
Liquids leased capacity %(b)	93.6		%	91.4		%	93.2		%	91.0		%
Bulk transload tonnage (MMtons)	13.7			13.7			27.1			26.7

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

(b)The ratio of our tankage capacity in service to liquids leasable capacity.

For purposes of the following tables and related discussions, the results of operations of our terminals held for sale or divested, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping below and included within the All others group.

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Below are the changes in Segment EBDA:

	Three Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Marine operations	$	44	$	34	$	10
Southeast	13		9		4
Gulf Central	38		35		3
All others (including intrasegment eliminations)	166		175		(9)
Total Terminals Segment EBDA	$	261	$	253	$	8

	Six Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Marine operations	$	85	$	72	$	13
Southeast	22		16		6
Gulf Central	76		67		9
All others (including intrasegment eliminations)	332		336		(4)
Total Terminals Segment EBDA	$	515	$	491	$	24

The changes in Segment EBDA for our Terminals business segment in the comparable three and six-month periods ended June 30, 2023 and 2022 are explained by the following discussion:

•The $10 million (29%) and $13 million (18%) increases, respectively, in Marine operations were primarily due to higher average charter rates.

•The $4 million (44%) and $6 million (38%) increases, respectively, in the Southeast terminals were primarily due to improved pricing and margin as well as additional services added in our steel handling business.

•The $3 million (9%) and $9 million (13%) increases, respectively, in the Gulf Central terminals were primarily due to higher revenues resulting from contractual rate escalations and higher volumes for petroleum coke handling activities.

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CO2

	Three Months Ended June 30,				Six Months Ended June 30,
	2023		2022		2023		2022
	(In millions, except operating statistics)
Revenues	$	302	$	343	$	599	$	648
Operating expenses	(135)		(140)		(267)		(265)
Gain on divestitures and impairments, net	1		—		1		1
Earnings from equity investments	7		9		14		20
Segment EBDA	175		212		347		404
Certain Items:
Change in fair value of derivative contracts	—		(1)		1		15
Certain Items(a)	—		(1)		1		15
Adjusted Segment EBDA	$	175	$	211	$	348	$	419
Change from prior period	Increase/(Decrease)
Segment EBDA	$	(37)			$	(57)
Adjusted Segment EBDA	$	(36)			$	(71)
Volumetric data
SACROC oil production	21.81		19.67		20.37		19.47
Yates oil production	6.55		6.35		6.65		6.57
Other	2.46		2.82		2.53		2.86
Total oil production, net (MBbl/d)(b)	30.82		28.84		29.55		28.90
NGL sales volumes, net (MBbl/d)(b)	9.24		9.24		8.70		9.33
CO2 sales volumes, net (Bcf/d)	0.342		0.350		0.352		0.361
Realized weighted average oil price ($ per Bbl)	$	67.73	$	68.92	$	67.45	$	67.91
Realized weighted average NGL price ($ per Bbl)	$	31.22	$	41.86	$	32.54	$	42.77

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. Three and six months ended June 2023 and 2022 Certain Items are associated with our Oil and Gas Producing activities. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(b)Net of royalties and outside working interests.

Below are the changes in Segment EBDA:

	Three Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Source and Transportation activities	$	39	$	69	$	(30)
Oil and Gas Producing activities	135		137		(2)
Subtotal	174		206		(32)
Energy Transition Ventures	1		6		(5)
Total CO2 Segment EBDA	$	175	$	212	$	(37)

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	Six Months Ended June 30,
	2023		2022		increase/ (decrease)
	(In millions)
Source and Transportation activities	$	88	$	131	$	(43)
Oil and Gas Producing activities	253		263		(10)
Subtotal	341		394		(53)
Energy Transition Ventures	6		10		(4)
Total CO2 Segment EBDA	$	347	$	404	$	(57)

The changes in Segment EBDA for our CO2 business segment in the comparable three and six-month periods ended June 30, 2023 and 2022 are explained by the following discussion:

•The $30 million (43%) and $43 million (33%) decreases, respectively, in Source and Transportation activities were primarily due to lower revenues related to lower CO2 sales prices and higher operating expenses.

•The $2 million (1%) and $10 million (4%) decreases. respectively, in Oil and Gas Producing activities were primarily due to decreases in revenues related to lower realized NGL and crude oil prices and lower NGL volumes partially offset by higher crude oil volumes.

In addition, the decreases in Oil and Gas Producing activities for the three and six-month periods were affected by an unfavorable and favorable change, respectively, in revenues related to non-cash mark-to-market derivative hedge contracts, which we treated as Certain Items.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to a lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2023:

	Remaining 2023		2024		2025		2026		2027
Crude Oil(a)
Price ($ per Bbl)	$	65.17	$	63.06	$	62.14	$	64.63	$	61.49
Volume (MBbl/d)	25.60		17.20		10.45		7.20		0.90
NGLs
Price ($ per Bbl)	$	53.95	$	49.48
Volume (MBbl/d)	4.27		0.78

(a)Includes West Texas Intermediate hedges.

Liquidity and Capital Resources

General

As of June 30, 2023, we had $497 million of “Cash and cash equivalents,” a decrease of $248 million from December 31, 2022. Additionally, as of June 30, 2023, we had borrowing capacity of approximately $3.9 billion under our credit facilities (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position and remaining borrowing capacity on our credit facilities are more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flows from operations, providing a source of funds of $2,883 million and $2,648 million in the first six months of 2023 and 2022, respectively. The period-to-period increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash flows from operations to fund our sustaining capital expenditures, dividend payments and our expansion capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any.

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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 June 30, 2023 and December 31, 2022, approximately $4,019 million (13%) and $6,314 million (20%), respectively, of the principal amount of our debt balances were subject to variable interest rates—either as short-term or long-term variable rate debt obligations or as fixed-rate debt converted to variable rates through the use of interest rate swaps. The percentage at June 30, 2023 and December 31, 2022 includes $3,445 million and $1,250 million, respectively, of variable-to-fixed interest rate derivative contracts which expire in December 2023. For more information on our interest rate swaps, see Note 5 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements.

Our board of directors declared a quarterly dividend of $0.2825 per share for the second quarter of 2023, a 2% increase over the dividend declared for the second quarter of 2022.

On January 31, 2023, we issued in a registered offering $1,500 million aggregate principal amount of 5.20% senior notes due 2033 for net proceeds of $1,485 million, which were used to repay short-term borrowings, maturing debt and for general corporate purposes.

During the first quarter, upon maturity, we repaid our 3.15% senior notes, our floating rate senior notes and our 3.45% senior notes.

Short-term Liquidity

As of June 30, 2023, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our combined $4.0 billion of credit facilities with an available capacity of approximately $3.9 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facilities can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings reduce borrowings allowed under our credit facilities and letters of credit reduce borrowings allowed under our $3.5 billion credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facilities and, as previously discussed, have consistently generated strong cash flows from operations.

As of June 30, 2023, our $2,760 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, 2022 was $3,385 million.

We had working capital (defined as current assets less current liabilities) deficits of $2,885 million and $3,127 million as of June 30, 2023 and December 31, 2022, respectively. From time to time, our current liabilities may include short-term borrowings used to finance our expansion capital expenditures, which we may periodically replace with long-term financing and/or pay down using retained cash from operations. The overall $242 million reduction in deficit from year-end 2022 was primarily due to (i) a $625 million decrease in senior notes that mature in the next twelve months; (ii) a $182 million decrease in other current liabilities, primarily related to reductions in exchange gas payables, bonus accruals and property tax; and (iii) favorable short-term fair value adjustments on derivative contracts of $136 million; partially offset by (i) a $248 million decrease in cash and cash equivalents which was used to repay a portion of senior notes that matured in the first quarter of 2023; (ii) a $254 million net unfavorable change in our accounts receivables and payables; (iii) a $112 million decrease in other current assets, primarily in exchange gas receivables and regulatory assets; and (iv) a $65 million decrease in inventories, primarily associated with gas in underground storage. Generally, our working capital balance varies due to factors such as the timing of scheduled debt payments, timing differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts, and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities.

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Capital Expenditures

We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:

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

Budgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal, but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.

Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion. The classification has an impact on DCF because capital expenditures that are classified as expansion capital expenditures are not deducted in calculating DCF, while those classified as sustaining capital expenditures are.

Our capital expenditures for the six months ended June 30, 2023, and the amount we expect to spend for the remainder of 2023 to sustain our assets and expand our business are as follows:

	Six Months Ended June 30, 2023		2023 Remaining		Total 2023
	(In millions)
Capital expenditures:
Sustaining capital expenditures	$	351	$	534	$	885
Expansion capital expenditures	779		1,057		1,836
Accrued capital expenditures, contractor retainage and other	(88)		—		—
Capital expenditures	$	1,042	$	1,591	$	2,721
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)	$	75	$	79	$	154
Investments in unconsolidated joint ventures(b)	134		124		258
Less: Consolidated joint venture partners’ sustaining capital expenditures	(4)		(7)		(11)
Less: Consolidated joint venture partners’ expansion capital expenditures	(6)		(14)		(20)
Acquisition	14		—		14
Accrued capital expenditures, contractor retainage and other	88		—		—
Total capital investments	$	1,343	$	1,773	$	3,116

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

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(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

Our capital investments consist of the following:

	Six Months Ended June 30, 2023		2023 Remaining		Total 2023
	(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment	$	351	$	534	$	885
Sustaining capital expenditures of unconsolidated joint ventures(a)	75		79		154
Less: Consolidated joint venture partners’ sustaining capital expenditures	(4)		(7)		(11)
Total sustaining capital investments	422		606		1,028
Expansion capital investments
Capital expenditures for property, plant and equipment	779		1,057		1,836
Investments in unconsolidated joint ventures(b)	134		124		258
Less: Consolidated joint venture partners’ expansion capital expenditures	(6)		(14)		(20)
Acquisition	14		—		14
Total expansion capital investments	921		1,167		2,088
Total capital investments	$	1,343	$	1,773	$	3,116

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

(b)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

Impact of Regulation

The trend toward increasingly stringent regulations creates uncertainty regarding our capital and operating expenditure requirements over the longer term. For example, on June 5, 2023, the EPA’s final rule known as the “Good Neighbor Plan” (the Plan) was published in the federal register as a final rule. As part of the Plan, the EPA disapproved 19 state implementation plans (SIPs) under the interstate transport (good neighbor) provisions of the Clean Air Act for the 2015 Ozone National Ambient Air Quality Standards and issued prescriptive emission standards for several sectors, including new and existing internal combustion engines of a certain size used in pipeline transportation of natural gas.

Multiple legal challenges have already been filed, including by us. See Note 9, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. While we are unable to predict whether any legal challenges will result in changes to the Plan or how those changes, if any, would impact us, we believe that the EPA’s disapprovals of the SIPs were improper, that the Plan is deeply flawed and that numerous meritorious bases for challenging the Plan exist. Several states in which we have affected assets, including Arkansas, Kentucky, Louisiana, Mississippi, Missouri, Oklahoma and Texas, have appealed the EPA’s disapprovals of SIPs and requested stays pending appeal. The criteria for a stay pending appeal include a requirement that the applicant show likelihood of success on the merits. Stays pending appeal have been granted with respect to the EPA’s disapprovals of SIPs submitted by Arkansas, Kentucky, Louisiana, Minnesota, Mississippi, Missouri, Nevada and Texas, meaning that (for as long as the stays remain in place) the EPA no longer has a legal basis to enforce the Plan in these states. Guidance issued by the EPA on June 1, 2023 indicates the Plan’s requirements will not take effect as to sources in Arkansas, Kentucky, Louisiana, Mississippi, Missouri and Texas while the stays of the SIP disapproval action remain in place. If the Plan were fully implemented, its emission standards would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. The Plan would require that all impacted engines meet the stringent emission limits by May 1, 2026 unless compliance schedule extensions are granted by the EPA, which would need to be supported by us and approved by the EPA on an engine-by-engine basis. If the Plan were to remain in effect in its current form (including full compliance by its May 1, 2026 compliance deadline, and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate that it would have a material impact on us, including estimated costs necessary to comply with the Plan ranging from $1.5 billion to $1.8 billion (including costs for joint ventures that we operate, net to our interests in such joint ventures), potential shortages of equipment resulting in our inability to comply with the Plan, and

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operational disruptions. However, impacts are difficult to predict, particularly given the extensive pending litigation. The outcomes of these numerous lawsuits may significantly decrease our exposure. For example, our currently estimated costs necessary to comply with the Plan associated with states that have not challenged disapproval of their SIPs range from $200 million to $300 million. However, successful challenges to the Plan would impact all states. In addition, we would seek to mitigate the impacts and to recover expenditures through adjustments to our rates on our regulated assets where available.

The cost estimates discussed above are preliminary, based on a number of assumptions and subject to significant variation, including outside of the ranges provided. Costs are assumed based on the average cost incurred historically for a typical retrofit of an average engine. These estimates reflect only the anticipated upgrades that would need to be performed (and in the case of joint ventures, only on assets that we operate) and do not take into account potential complications such as additional maintenance requirements that may be identified during the upgrade process.

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, 2022 in our 2022 Form 10-K.

Commitments for the purchase of property, plant and equipment as of June 30, 2023 and December 31, 2022 were $553 million and $527 million, respectively. The increase of $26 million was primarily driven by capital commitments related to our Natural Gas Pipelines segment.

Cash Flows

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

	Six Months Ended June 30,
	2023		2022		Changes
	(In millions)
Net Cash Provided by (Used in)
Operating activities	$	2,883	$	2,648	$	235
Investing activities	(1,086)		(672)		(414)
Financing activities	(2,071)		(2,706)		635
Net Decrease in Cash, Cash Equivalents and Restricted Deposits	$	(274)	$	(730)	$	456

Operating Activities

$235 million more cash provided by operating activities in the comparable six-month periods ended June 30, 2023 and 2022 is explained by the following discussion:

•a $411 million increase in cash associated with net changes in working capital items and other non-current assets and liabilities. The increase was primarily driven by (i) net favorable changes related to the timing of accounts receivable collections and trade payable payments, largely in our Natural Gas business segment; and (ii) a decrease in inventories primarily driven by higher settlements associated with commodity hedges related to gas in underground storage and lower market prices and volumes with crude and transmix inventories; partially offset by,

•a $176 million decrease in cash after adjusting the $24 million decrease in net income by $152 million for the combined effects of the period-to-period net changes in non-cash items.

Investing Activities

$414 million more cash used in investing activities in the comparable six-month periods ended June 30, 2023 and 2022 is explained by the following discussion:

•a $263 million increase in capital expenditures primarily driven by the expansion projects in our Natural Gas business segment; and

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•a $116 million increase in cash used for contributions to equity investees driven primarily by higher contributions to Permian Highway Pipeline LLC in the 2023 period compared with the 2022 period, and contributions in 2023 to our newly formed equity investment, Greenholly Gathering Pipeline LLC.

Financing Activities

$635 million less cash used in financing activities in the comparable six-month periods ended June 30, 2023 and 2022 is explained by the following discussion:

•an $826 million net decrease in cash used related to debt activity as a result of lower net debt payments in the 2023 period compared to the 2022 period; partially offset by,

•a $144 million increase in cash used for share repurchases under our share buy-back program.

Dividends

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

Three months ended	Total quarterly dividend per share for the period		Date of declaration	Date of record	Date of dividend
March 31, 2023	$	0.2825	April 19, 2023	May 1, 2023	May 15, 2023
June 30, 2023	0.2825		July 19, 2023	July 31, 2023	August 15, 2023

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws and other factors. See 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 2022 Form 10-K. All of these matters will be taken into consideration by our board of directors when 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 a Subsidiary Issuer is in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X.  Also, see Exhibit 10.1 to this Report “Cross Guarantee Agreement, dated as of November 26, 2014, among Kinder Morgan, Inc. and certain of its subsidiaries, with schedules updated as of June 30, 2023.”

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

Excluding fair value adjustments, as of June 30, 2023 and December 31, 2022, the Obligated Group had $30,522 million and $30,886 million, respectively, of Guaranteed Notes outstanding.

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

Summarized Combined Balance Sheet Information	June 30, 2023		December 31, 2022
	(In millions)
Current assets	$	2,436	$	3,514
Current assets - affiliates	604		618
Noncurrent assets	61,623		61,523
Noncurrent assets - affiliates	525		516
Total Assets	$	65,188	$	66,171
Current liabilities	$	5,296	$	6,612
Current liabilities - affiliates	671		707
Noncurrent liabilities	31,193		30,668
Noncurrent liabilities - affiliates	1,185		1,096
Total Liabilities	38,345		39,083
Kinder Morgan, Inc.’s stockholders’ equity	26,843		27,088
Total Liabilities and Stockholders’ Equity	$	65,188	$	66,171

Summarized Combined Income Statement Information	Three Months Ended June 30, 2023		Six Months Ended June 30, 2023
	(In millions)
Revenues	$	3,210	$	6,823
Operating income	912		2,020
Net income	487		1,100

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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, 2022, in Part II, Item 7A in our 2022 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4.  Controls and Procedures.

As of June 30, 2023, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934.  There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives.  Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2023 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II.  OTHER INFORMATION

Item 1.  Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

Except as follows, there have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2022 Form 10-K.

For more information on our risk management activities, refer to Part I, Item 1, Note 5 “Risk Management” to our consolidated financial statements.

For updates regarding the EPA’s final rule known as the “Good Neighbor Plan,” which was discussed under Item 1A in our Form 10-Q for the three months ended March 31, 2023, please refer to Part I, Item 2. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation” and Note 9, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements.

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

Our Purchases of Our Class P Stock

(During the quarter ended June 30, 2023)

Settlement Period	Total number of securities purchased(a)	Average price paid per security(b)		Total number of securities purchased as part of publicly announced plans(a)	Maximum number (or approximate dollar value) of securities that may yet be purchased under the plans or programs(a)
April 1 to April 30, 2023	—	$	—	—	$	1,944,068,674
May 1 to May 31, 2023	6,987,483	16.56		6,987,483	1,828,348,210
June 1 to June 30, 2023	5,283,678	16.59		5,283,678	1,740,686,259
Total	12,271,161	$	16.57	12,271,161	$	1,740,686,259

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

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

Subsequent to June 30, 2023 and through July 20, 2023, we repurchased less than 1 million shares for $13 million at an average price of $16.93 per share.

Item 3.  Defaults Upon Senior Securities.

None.

Item 4.  Mine Safety Disclosures.

Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank). We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of Dodd-Frank for the quarter ended June 30, 2023.

Item 5.  Other Information.

During the quarter ended June 30, 2023, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

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Item 6.  Exhibits.

Exhibit Number	Description
3.1	Certificate of Amendment to Amended and Restated Certificate of Incorporation of Kinder Morgan, Inc. (filed as exhibit 3.1 to Kinder Morgan, Inc.’s Current Report on Form 8-K filed May 16, 2023 (File No. 001-35081)).
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 June 30, 2023.
22.1	Subsidiary guarantors and issuers of guaranteed securities.
31.1	Certification by Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
31.2	Certification by Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.
32.1	Certification by Chief Executive Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
32.2	Certification by Chief Financial Officer furnished pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
101	Interactive data files pursuant to Rule 405 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language): (i) our Consolidated Statements of Income for the three and six months ended June 30, 2023 and 2022; (ii) our Consolidated Statements of Comprehensive Income for the three and six months ended June 30, 2023 and 2022; (iii) our Consolidated Balance Sheets as of June 30, 2023 and December 31, 2022; (iv) our Consolidated Statements of Cash Flows for the six months ended June 30, 2023 and 2022; (v) our Consolidated Statements of Stockholders’ Equity for the three and six months ended June 30, 2023 and 2022; and (vi) the notes to our Consolidated Financial Statements.
104	Cover Page Interactive Data File pursuant to Rule 406 of Regulation S-T formatted in iXBRL (Inline Extensible Business Reporting Language) and contained in Exhibit 101.

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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:	July 21, 2023	By:	/s/ David P. Michels
			David P. Michels Vice President and Chief Financial Officer (principal financial and accounting officer)

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