KMI 10-Q Quarterly Report Sept. 30, 2025

KINDER MORGAN, INC.

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kmi-20250930

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2025

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

KINDER MORGAN, INC.

(Exact name of registrant as specified in its charter)


Delaware			80-0682103
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

1001 Louisiana Street , Suite 1000 , Houston , Texas 77002

(Address of principal executive offices)(zip code)

Registrant’s telephone number, including area code: 713 - 369-9000

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes þ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer þ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No þ

As of October 23, 2025, the registrant had 2,224,760,390 shares of Class P common stock outstanding.

KINDER MORGAN, INC. AND SUBSIDIARIES

TABLE OF CONTENTS


			Page Number
	Glossary		2
	Information Regarding Forward-Looking Statements		3
	PART I. FINANCIAL INFORMATION
Item 1.	Financial Statements (Unaudited)
	Consolidated Statements of Income - Three and Nine Months Ended September 3 0 , 202 5 and 202 4		4
	Consolidated Statements of Comprehensive Income - Three and Nine Months Ended September 3 0 , 202 5 and 202 4		5
	Consolidated Balance Sheets - as of September 30 , 202 5 and December 31, 202 4		6
	Consolidated Statements of Cash Flows - Nine Months Ended September 3 0 , 202 5 and 202 4		7
	Consolidated Statements of Stockholders’ Equity - Three and Nine Months Ended September 3 0 , 202 5 and 202 4		9
	Notes to Consolidated Financial Statements		10
	Note 1 .	General	10
	Note 2.	Acquisition s and Divestiture	11
	Note 3.	Debt	12
	Note 4.	Stockholders ’ Equity	13
	Note 5.	Risk Management	14
	Note 6.	Revenue Recognition	19
	Note 7.	Reportable Segments	22
	Note 8.	Income Taxes	27
	Note 9.	Litigation and Environmental	27
	Note 10.	Recent Accounting Pronouncements	31
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations
	General and Basis of Presentation		32
	Results of Operations		32
	Overview		32
	Consolidated Earnings Results		35
	Non-GAAP Financial Measures		38
	Segment Earnings Results		40
	Liquidity and Capital Resources		48
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries		52
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		53
Item 4.	Controls and Procedures		53
	PART II. OTHER INFORMATION
Item 1.	Legal Proceedings		53
Item 1A.	Risk Factors		53
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		53
Item 3.	Defaults Upon Senior Securities		53
Item 4.	Mine Safety Disclosures		53
Item 5.	Other Information		53
Item 6.	Exhibits		54
	Signature		55

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

KMBT

Kinder Morgan Bulk Terminals, Inc.

KMLT

Kinder Morgan Liquid Terminals, LLC

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.

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

Common Industry and Other Terms

per day

LLC

limited liability company

Bbl

barrels

MBbl

thousand barrels

BBtu

billion British Thermal Units

MMBbl

million barrels

Bcf

billion cubic feet

MMtons

million tons

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

NGL

natural gas liquids

NYMEX

New York Mercantile Exchange

CO 2

carbon dioxide or our CO 2 business segment

OTC

over-the-counter

DD&A

depreciation, depletion and amortization

RIN

Renewable Identification Number

EPA

U.S. Environmental Protection Agency

RNG

Renewable natural gas

FASB

Financial Accounting Standards Board

ROU

Right-of-Use

GAAP

U.S. Generally Accepted Accounting Principles

U.S.

United States of America

Information Technology

WTI

West Texas Intermediate

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results or the ability to generate revenues, 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: long-term demand for our assets and services, our business strategy, expected financial results, dividends, sustaining and discretionary/expansion capital expenditures, our cash requirements and our financing and capital allocation strategy, anticipated impacts of litigation and legal or regulatory developments, and our 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 impact of changes in trade policies and tariffs; 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 and in Part II, Item 1A. “ Risk Factors ” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025 (March 31, 2025 Form 10-Q), as well as “ Information Regarding Forward-Looking Statements, ” Part I, Item 1A. “ Risk Factors, ” and Part I, Item 7. “ Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources ” in our Annual Report on Form 10-K for the year ended December 31, 2024 (2024 Form 10-K) (except to the extent such information is modified or superseded by information in subsequent reports).

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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts, unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Revenues
Services	$	2,340	$	2,215	$	7,026	$	6,625
Commodity sales	1,758		1,441		5,262		4,307
Other	48		43		141		181
Total Revenues	4,146		3,699		12,429		11,113

Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	1,395		1,024		4,082		3,098
Operations and maintenance	786		790		2,270		2,211
Depreciation, depletion and amortization	609		587		1,835		1,758
General and administrative	183		176		558		530
Taxes, other than income taxes	111		107		334		327

Other income, net	( 1 )		—		( 10 )		( 87 )
Total Operating Costs, Expenses and Other	3,083		2,684		9,069		7,837

Operating Income	1,063		1,015		3,360		3,276

Other Income (Expense)
Earnings from equity investments	221		199		647		625


Interest, net	( 456 )		( 466 )		( 1,359 )		( 1,402 )
Other, net	11		16		39		17
Total Other Expense	( 224 )		( 251 )		( 673 )		( 760 )

Income Before Income Taxes	839		764		2,687		2,516

Income Tax Expense	( 185 )		( 113 )		( 548 )		( 490 )

Net Income	654		651		2,139		2,026






Net Income Attributable to Noncontrolling Interests	( 26 )		( 26 )		( 79 )		( 80 )

Net Income Attributable to Kinder Morgan, Inc.	$	628	$	625	$	2,060	$	1,946





Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.28	$	0.28	$	0.92	$	0.87

Basic and Diluted Weighted Average Shares Outstanding	2,224		2,221		2,223		2,220

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions, unaudited)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Net income	$	654	$	651	$	2,139	$	2,026
Other comprehensive income, net of tax
Net unrealized gain from derivative instruments (net of taxes of $( 7 ), $( 30 ), $( 44 ) and $( 6 ), respectively)	22		99		145		18
Reclassification into earnings of net derivative instruments (gain) loss to net income (net of taxes of $ 3 , $ 4 , $ 19 and $( 3 ), respectively)	( 10 )		( 13 )		( 59 )		9

Benefit plan adjustments (net of taxes of $ 1 , $ — , $ 2 and $( 4 ), respectively)	( 2 )		1		( 5 )		15
Total other comprehensive income	10		87		81		42

Comprehensive income	664		738		2,220		2,068
Comprehensive income attributable to noncontrolling interests	( 26 )		( 26 )		( 79 )		( 80 )
Comprehensive income attributable to KMI	$	638	$	712	$	2,141	$	1,988

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

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


	September 30, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	71	$	88
Restricted deposits	62		126
Accounts receivable	1,444		1,506

Inventories	560		555


Other current assets	289		246
Total current assets	2,426		2,521

Property, plant and equipment, net	39,021		38,013
Investments	7,747		7,845
Goodwill	20,084		20,084
Other intangibles, net	1,774		1,760


Deferred charges and other assets	1,264		1,184
Total Assets	$	72,316	$	71,407

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	1,081	$	2,009
Accounts payable	1,295		1,395

Accrued interest	362		543
Accrued taxes	291		276


Other current liabilities	817		878
Total current liabilities	3,846		5,101

Long-term liabilities and deferred credits
Long-term debt
Outstanding	31,303		29,779

Debt fair value adjustments	196		102
Total long-term debt	31,499		29,881
Deferred income taxes	2,605		2,070

Other long-term liabilities and deferred credits	2,333		2,488

Total long-term liabilities and deferred credits	36,437		34,439
Total Liabilities	40,283		39,540
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity

Class P Common Stock, $ 0.01 par value, 4,000,000,000 shares authorized, 2,224,753,580 and 2,221,647,775 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	41,255		41,237
Accumulated deficit	( 10,523 )		( 10,633 )
Accumulated other comprehensive loss	( 14 )		( 95 )
Total Kinder Morgan, Inc.’s stockholders’ equity	30,740		30,531
Noncontrolling interests	1,293		1,336
Total Stockholders’ Equity	32,033		31,867
Total Liabilities and Stockholders’ Equity	$	72,316	$	71,407

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


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

	Nine Months Ended September 30,
	2025		2024
Cash Flows From Operating Activities
Net income	$	2,139	$	2,026
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,835		1,758
Deferred income taxes	512		454
Change in fair value of derivative contracts	14		32
Gain on divestitures, net	( 3 )		( 76 )

Earnings from equity investments	( 647 )		( 625 )
Distributions of equity investment earnings	585		600
Changes in components of working capital
Accounts receivable	75		300
Inventories	( 5 )		2
Other current assets	13		( 2 )
Accounts payable	( 30 )		( 107 )
Accrued interest, net of interest rate swaps	( 181 )		( 138 )
Accrued taxes	19		15
Other current liabilities	( 26 )		( 68 )


Other, net	( 75 )		( 46 )
Net Cash Provided by Operating Activities	4,225		4,125

Cash Flows From Investing Activities
Acquisition of assets (Note 2)	( 648 )		( 58 )
Capital expenditures	( 2,206 )		( 1,857 )

Contributions to investments	( 103 )		( 93 )
Distributions from equity investments in excess of cumulative earnings	269		117
Other, net	( 14 )		33
Net Cash Used in Investing Activities	( 2,702 )		( 1,858 )

Cash Flows From Financing Activities
Issuances of debt	8,434		8,803
Payments of debt	( 7,910 )		( 8,937 )
Debt issue costs	( 18 )		( 31 )
Dividends	( 1,950 )		( 1,915 )
Repurchases of shares	—		( 7 )


Distributions to noncontrolling interests	( 122 )		( 123 )
Other, net	( 38 )		( 20 )
Net Cash Used in Financing Activities	( 1,604 )		( 2,230 )


Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits	( 81 )		37
Cash, Cash Equivalents and Restricted Deposits, beginning of period	214		96
Cash, Cash Equivalents and Restricted Deposits, end of period	$	133	$	133


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

	Nine Months Ended September 30,
	2025		2024
Cash and Cash Equivalents, beginning of period	$	88	$	83
Restricted Deposits, beginning of period	126		13
Cash, Cash Equivalents and Restricted Deposits, beginning of period	214		96

Cash and Cash Equivalents, end of period	71		108
Restricted Deposits, end of period	62		25
Cash, Cash Equivalents and Restricted Deposits, end of period	133		133

Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits	$	( 81 )	$	37

Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments	$	17	$	31

Net increase in property, plant and equipment from both accruals and contractor retainage			11
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,538		1,542
Cash paid during the period for income taxes, net	43		26

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions, unaudited)


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at June 30, 2025	2,222	$	22	$	41,269	$	( 10,497 )	$	( 24 )	$	30,770	$	1,311	$	32,081





Restricted shares	3			( 14 )						( 14 )				( 14 )
Net income						628				628		26		654
Dividends						( 654 )				( 654 )				( 654 )
Distributions										—		( 44 )		( 44 )



Other comprehensive income								10		10				10
Balance at September 30, 2025	2,225	$	22	$	41,255	$	( 10,523 )	$	( 14 )	$	30,740	$	1,293	$	32,033


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at June 30, 2024	2,219	$	22	$	41,218	$	( 10,640 )	$	( 262 )	$	30,338	$	1,356	$	31,694



Restricted shares	3			( 1 )						( 1 )				( 1 )
Net income						625				625		26		651
Dividends						( 643 )				( 643 )				( 643 )
Distributions										—		( 42 )		( 42 )


Other comprehensive income								87		87				87
Balance at September 30, 2024	2,222	$	22	$	41,217	$	( 10,658 )	$	( 175 )	$	30,406	$	1,340	$	31,746


	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, 2024	2,222	$	22	$	41,237	$	( 10,633 )	$	( 95 )	$	30,531	$	1,336	$	31,867





Restricted shares	3			18						18				18
Net income						2,060				2,060		79		2,139
Dividends						( 1,950 )				( 1,950 )				( 1,950 )
Distributions										—		( 122 )		( 122 )



Other comprehensive income								81		81				81
Balance at September 30, 2025	2,225	$	22	$	41,255	$	( 10,523 )	$	( 14 )	$	30,740	$	1,293	$	32,033


	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, 2023	2,220	$	22	$	41,190	$	( 10,689 )	$	( 217 )	$	30,306	$	1,423	$	31,729



Repurchases of shares	( 1 )			( 7 )						( 7 )				( 7 )

Restricted shares	3			34						34				34
Net income						1,946				1,946		80		2,026
Dividends						( 1,915 )				( 1,915 )				( 1,915 )
Distributions										—		( 123 )		( 123 )

Acquisition adjustment (Note 2)										—		( 38 )		( 38 )
Other										—		( 2 )		( 2 )
Other comprehensive income								42		42				42
Balance at September 30, 2024	2,222	$	22	$	41,217	$	( 10,658 )	$	( 175 )	$	30,406	$	1,340	$	31,746

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 79,000 miles of pipelines, 139 terminals, over 700 Bcf of working natural gas storage capacity, and have RNG generation capacity of approximately 6.9 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO 2 , 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 2024 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, 2025 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO 2 ; (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, which include assumptions primarily involving management’s judgments and estimates. For all reporting units other than the Energy Transition Ventures reporting unit within our CO 2 business segment, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of basis differences, which was previously presented separately as amortization of excess cost of equity investments, (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For Energy Transition Ventures reporting unit, which had a goodwill balance of $ 114 million as of September 30, 2025, we estimated fair value based on an income approach, which includes assumptions regarding future cash flows based primarily on production growth assumptions, terminal values, and discount rates.

The results of our May 31, 2025 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value. Subsequent to our annual goodwill impairment test, we have not identified any triggers requiring further impairment analysis. Changes to any one or a combination of the factors above 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.

Earnings per Share (EPS)

The following table sets forth net income allocated to common stockholders and EPS, calculated using the two-class method:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	628	$	625	$	2,060	$	1,946
Less: Net Income Allocated to Participating Securities(a)	( 4 )		( 4 )		( 11 )		( 11 )
Net Income Allocated to Common Stockholders	$	624	$	621	$	2,049	$	1,935

Basic and Diluted Weighted Average Shares Outstanding(b)	2,224		2,221		2,223		2,220
Basic and Diluted EPS(b)	$	0.28	$	0.28	$	0.92	$	0.87

(a) Participating securities consist of unvested stock awards issued to employees and non-employee directors. These awards receive dividend equivalents but do not share in net losses or distributions in excess of earnings.

(b) For all periods presented, diluted EPS is equal to basic EPS, as our potential common stock equivalents are antidilutive.

The following potential common stock equivalents are excluded from the determination of diluted EPS:


	Three Months Ended September 30,		Nine Months Ended September 30,
	2025	2024	2025	2024
	(In millions on a weighted average basis)
Unvested stock awards	13	14	13	13
Convertible trust preferred securities	3	3	3	3

2. Acquisitions and Divestiture

Acquisitions

As of September 30, 2025, our allocation of the purchase price for acquisitions are detailed below:


				Assignment of Purchase Price
Ref	Acquisition	Purchase price		Current assets		Property, plant & equipment		Other long-term assets		Current liabilities		Long-term liabilities		Non-controlling interest		Resulting goodwill
		(In millions)
(1)	Outrigger Energy	$	648	$	16	$	497	$	160	$	( 5 )	$	( 20 )	$	—	$	—
(2)	North McElroy Unit	61		1		102		—		—		( 42 )		—		—
(3)	STX Midstream	1,829		25		1,199		549		( 6 )		—		( 66 )		128

(1) Outrigger Energy Acquisition

On February 18, 2025, we completed the acquisition of a natural gas gathering and processing system in North Dakota from Outrigger Energy II LLC for a purchase price of $ 648 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation consists of customer relationships intangible with a weighted average amortization period of approximately 15 years. The acquisition includes a 0.27 Bcf/d processing facility and a 104 -mile, large-diameter, high-pressure rich gas gathering header pipeline with 0.35 Bcf/d of capacity connecting supplies from the Williston Basin area to high-demand markets. The acquired assets are included in our Natural Gas Pipelines business segment.

(2) North McElroy Unit Acquisition

On June 10, 2024, we completed the acquisition of AVAD Energy Partners’ interest in North McElroy Unit, which is an existing waterflood located in Crane County, Texas for a purchase price of $ 61 million. The acquired long-term liabilities consist of asset retirement obligations. The acquired assets are included in our CO 2 business segment.

(3) South Texas Midstream Pipeline System (STX Midstream) Acquisition

On December 28, 2023, we completed the acquisition of STX Midstream from NextEra Energy Partners for a purchase price of $ 1,829 million, including purchase price adjustments for working capital. During the three months ended March 31, 2024, the Company identified an adjustment of $ 38 million to the calculation of noncontrolling interest in addition to measurement period adjustments of $ 10 million, resulting in a net $ 28 million decrease to goodwill. The acquired assets are included in our Natural Gas Pipelines business segment.

Pro Forma Information

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

Divestiture

CO 2 Divestiture

In June 2024, we divested our interests in the Katz Unit, Goldsmith Landreth San Andres Unit, Tall Cotton Field, and Reinecke Unit, along with certain shallow interests in the Diamond M Field, all located in the Permian Basin, and received a leasehold interest in an undeveloped leasehold directly adjacent to the SACROC Unit. In addition to the leasehold interest, we received $ 18 million of cash proceeds in 2024 from this divestiture, net of working capital adjustments, which is classified as an investing activity within “Other, net” on our consolidated statement of cash flows, and recorded a gain of $ 40 million during the year ended December 31, 2024, which is reported within “Other income, net” on our consolidated statement of income and includes the effect of a $ 33 million reduction in our asset retirement obligations that were transferred to the buyer. Of the gain recorded, $ 41 million was recognized during the nine months ended September 30, 2024. The assets were included in our CO 2 business segment.

3. Debt

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


	September 30, 2025		December 31, 2024
	(In millions, unless otherwise stated)
Current portion of debt
$ 3.5 billion credit facility due August 20, 2027	$	—	$	—
Commercial paper notes(a)	568		331
Current portion of senior notes
4.30 % due June 2025	—		1,500
4.15 % due August 2026	375		—
Trust I preferred securities, 4.75 %, due March 2028(b)	111		111
Current portion of other debt	27		67
Total current portion of debt	1,081		2,009

Long-term debt (excluding current portion)
Senior notes	30,764		29,221
EPC Building, LLC, promissory note, 3.967 %, due 2024 through 2035	273		289

Trust I preferred securities, 4.75 %, due March 2028	110		110
Other	156		159
Total long-term debt	31,303		29,779
Total debt(c)	$	32,384	$	31,788

(a) Weighted average interest rate on borrowings at September 30, 2025 and December 31, 2024 was 4.32 % and 4.60 %, respectively.

(b) 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.

(c) Excludes our “Debt fair value adjustments” which, as of September 30, 2025 and December 31, 2024, increased our total debt balances by $ 196 million and $ 102 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 May 1, 2025, we issued in a registered offering, two series of senior notes consisting of $ 1,100 million aggregate principal amount of 5.15 % senior notes due 2030 and $ 750 million aggregate principal amount of 5.85 % senior notes due 2035 and received combined net proceeds of $ 1,834 million.

Credit Facilities and Restrictive Covenants

As of September 30, 2025, we had no borrowings outstanding under our credit facility, $ 568 million borrowings outstanding under our commercial paper program, and $ 11 million in letters of credit. Our availability under our credit facility as of September 30, 2025 was $ 2.9 billion. For the periods ended September 30, 2025 and 2024, we were in compliance with all required covenants.

Fair Value of Financial Instruments

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


	September 30, 2025				December 31, 2024
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	32,580	$	32,449	$	31,890	$	30,794

(a) Included in the estimated fair value are amounts for our Trust I Preferred Securities of $ 219 million and $ 201 million as of September 30, 2025 and December 31, 2024, respectively.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both September 30, 2025 and December 31, 2024.

4. Stockholders’ Equity

Class P Common Stock

Dividends

The following table provides information about our per share dividends:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
Per share cash dividend declared for the period	$	0.2925	$	0.2875	$	0.8775	$	0.8625
Per share cash dividend paid in the period	0.2925		0.2875		0.8725		0.8575

On October 22, 2025, our board of directors declared a cash dividend of $ 0.2925 per share for the quarterly period ended September 30, 2025, which is payable on November 17, 2025 to shareholders of record as of the close of business on November 3, 2025.

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, 2024	$	( 33 )	$	( 62 )	$	( 95 )
Other comprehensive gain (loss) before reclassifications	145		( 5 )		140
Gain reclassified from accumulated other comprehensive loss	( 59 )		—		( 59 )
Net current-period change in accumulated other comprehensive loss	86		( 5 )		81
Balance as of September 30, 2025	$	53	$	( 67 )	$	( 14 )


	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, 2023	$	( 44 )	$	( 173 )	$	( 217 )
Other comprehensive gain before reclassifications	18		15		33
Loss reclassified from accumulated other comprehensive loss	9		—		9
Net current-period change in accumulated other comprehensive loss	27		15		42
Balance as of September 30, 2024	$	( 17 )	$	( 158 )	$	( 175 )

5. Risk Management

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

Energy Commodity Price Risk Management

As of September 30, 2025, 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	( 14.6 )	MMBbl

Natural gas fixed price	( 62.0 )	Bcf
Natural gas basis	( 34.3 )	Bcf

Derivatives not designated as hedging contracts
Crude oil fixed price	( 1.0 )	MMBbl
Crude oil basis	( 1.0 )	MMBbl
Natural gas fixed price	( 3.8 )	Bcf
Natural gas basis	( 77.9 )	Bcf
NGL fixed price	( 1.4 )	MMBbl

As of September 30, 2025, 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 2028.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of September 30, 2025:

Notional amount

Accounting treatment

Maximum term

(In millions)

Derivatives designated as hedging instruments

Fixed-to-variable interest rate contracts(a)

3,500

Fair value hedge

August 2035

Derivatives not designated as hedging instruments

Variable-to-fixed interest rate contracts

1,500

Mark-to-Market

December 2025

(a) Included in “Long-term debt” on our accompanying consolidated balance sheets.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of September 30, 2025:

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.

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
		September 30, 2025		December 31, 2024		September 30, 2025		December 31, 2024
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	$	65	$	10	$	( 9 )	$	( 46 )
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	23		9		—		( 8 )
	Subtotal	88		19		( 9 )		( 54 )
Interest rate contracts
	Other current assets/(Other current liabilities)	4		1		( 37 )		( 51 )
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	38		19		( 101 )		( 203 )
	Subtotal	42		20		( 138 )		( 254 )
Foreign currency contracts
	Other current assets/(Other current liabilities)	—		—		( 5 )		( 3 )
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	43		—		—		( 26 )
	Subtotal	43		—		( 5 )		( 29 )
	Total	173		39		( 152 )		( 337 )

Derivatives not designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	18		14		( 61 )		( 35 )
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	6		1		( 1 )		( 15 )
	Subtotal	24		15		( 62 )		( 50 )
Interest rate contracts
	Other current assets/(Other current liabilities)	1		4		—		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		4		—		( 2 )
	Subtotal	1		8		—		( 2 )
	Total	25		23		( 62 )		( 52 )
	Total derivatives	$	198	$	62	$	( 214 )	$	( 389 )

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 September 30, 2025
Energy commodity derivative contracts(b)	$	39	$	73	$	—	$	112	$	( 44 )	$	—	$	68
Interest rate contracts	—		43		—		43		( 7 )		—		36
Foreign currency contracts	—		43		—		43		—		—		43
As of December 31, 2024
Energy commodity derivative contracts(b)	$	6	$	29	$	—	$	35	$	( 19 )	$	—	$	16
Interest rate contracts	—		27		—		27		—		—		27


	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 September 30, 2025
Energy commodity derivative contracts(b)	$	( 3 )	$	( 68 )	$	—	$	( 71 )	$	44	$	13	$	( 14 )
Interest rate contracts	—		( 138 )		—		( 138 )		7		—		( 131 )
Foreign currency contracts	—		( 5 )		—		( 5 )		—		—		( 5 )
As of December 31, 2024
Energy commodity derivative contracts(b)	$	( 17 )	$	( 89 )	$	—	$	( 106 )	$	19	$	52	$	( 35 )
Interest rate contracts	—		( 254 )		—		( 254 )		—		—		( 254 )
Foreign currency contracts	—		( 29 )		—		( 29 )		—		—		( 29 )

(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 September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
		(In millions)
Interest rate contracts	Interest, net	$	15	$	160	$	136	$	105

Hedged fixed rate debt(a)	Interest, net	$	( 25 )	$	( 160 )	$	( 145 )	$	( 104 )

(a) As of September 30, 2025, the cumulative amount of fair value hedging adjustments resulted in a decrease of $ 96 million in the carrying value of our hedged fixed rate debt balance and is included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income
	Three Months Ended September 30,					Three Months Ended September 30,
	2025		2024			2025		2024
	(In millions)					(In millions)
Energy commodity derivative contracts	$	32	$	110	Revenues—Commodity sales	$	17	$	2

					Costs of sales	( 1 )		( 6 )


Foreign currency contracts	( 3 )		19		Other, net	( 3 )		21
Total	$	29	$	129	Total	$	13	$	17


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income
	Nine Months Ended September 30,					Nine Months Ended September 30,
	2025		2024			2025		2024
	(In millions)					(In millions)
Energy commodity derivative contracts	$	122	$	5	Revenues—Commodity sales	$	11	$	( 6 )

					Costs of sales	( 2 )		( 15 )
Interest rate contracts	—		13		Interest, net	—		4

Foreign currency contracts	67		6		Other, net	69		5
Total	$	189	$	24	Total	$	78	$	( 12 )

(a) We expect to reclassify approximately $ 57 million of gains associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of September 30, 2025 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.


Derivatives not designated as accounting hedges	Location	Gain/(loss) recognized in income on derivatives
		Three Months Ended September 30,				Nine Months Ended September 30,
		2025		2024		2025		2024
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	6	$	21	$	22	$	13
	Costs of sales	( 25 )		( 9 )		( 45 )		( 41 )
	Earnings from equity investments	1		1		1		—
Interest rate contracts	Interest, net	( 2 )		( 5 )		( 4 )		( 7 )
Total(a)		$	( 20 )	$	8	$	( 26 )	$	( 35 )

(a) The three and nine months ended September 30, 2025 amounts include approximate losses of $ 4 million and $ 20 million, respectively, and the three and nine months ended September 30, 2024 amounts include approximate losses of $ 12 million and $ 1 million, respectively, associated with natural gas, crude, and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of September 30, 2025 and December 31, 2024, we had no outstanding letters of credit supporting our commodity price risk management program. As of September 30, 2025 and December 31, 2024, we had cash margins of $ 37 million and $ 104 million, respectively, posted by us with our counterparties as collateral and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The cash margin balance at September 30, 2025 represents the initial margin requirements of $ 24 million, and variation margin requirements of

$ 13 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of September 30, 2025, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches, we would not be required to post additional collateral.

6. Revenue Recognition

Disaggregation of Revenues

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


	Three Months Ended September 30, 2025
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	1,037	$	51	$	217	$	—	$	( 1 )	$	1,304
Fee-based services	282		282		106		12		( 1 )		681
Total services	1,319		333		323		12		( 2 )		1,985
Commodity sales
Natural gas sales	952		—		—		10		( 2 )		960
Product sales	239		292		9		210		( 2 )		748
Other sales	7		—		—		24		( 1 )		30
Total commodity sales	1,198		292		9		244		( 5 )		1,738
Total revenues from contracts with customers	2,517		625		332		256		( 7 )		3,723
Other revenues(c)
Leasing services(d)	115		46		186		18		—		365
Derivatives adjustments on commodity sales	18		—		—		5		—		23
Other	26		6		—		3		—		35
Total other revenues	159		52		186		26		—		423
Total revenues	$	2,676	$	677	$	518	$	282	$	( 7 )	$	4,146


	Three Months Ended September 30, 2024
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	949	$	59	$	211	$	1	$	( 1 )	$	1,219
Fee-based services	270		265		111		9		( 1 )		654
Total services	1,219		324		322		10		( 2 )		1,873
Commodity sales
Natural gas sales	559		—		—		11		( 2 )		568
Product sales	221		330		9		254		( 1 )		813
Other sales	2		—		—		32		—		34
Total commodity sales	782		330		9		297		( 3 )		1,415
Total revenues from contracts with customers	2,001		654		331		307		( 5 )		3,288
Other revenues(c)
Leasing services(d)	115		50		167		19		—		351
Derivatives adjustments on commodity sales	34		—		—		( 11 )		—		23
Other	26		7		—		4		—		37
Total other revenues	175		57		167		12		—		411
Total revenues	$	2,176	$	711	$	498	$	319	$	( 5 )	$	3,699


	Nine Months Ended September 30, 2025
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	3,128	$	151	$	662	$	1	$	( 3 )	$	3,939
Fee-based services	864		817		306		32		( 4 )		2,015
Total services	3,992		968		968		33		( 7 )		5,954
Commodity sales
Natural gas sales	2,802		—		—		37		( 6 )		2,833
Product sales	712		898		41		663		( 6 )		2,308
Other sales	21		—		—		77		( 2 )		96
Total commodity sales	3,535		898		41		777		( 14 )		5,237
Total revenues from contracts with customers	7,527		1,866		1,009		810		( 21 )		11,191
Other revenues(c)
Leasing services(d)	340		146		560		53		—		1,099
Derivatives adjustments on commodity sales	24		—		—		9		—		33
Other	75		19		—		12		—		106
Total other revenues	439		165		560		74		—		1,238
Total revenues	$	7,966	$	2,031	$	1,569	$	884	$	( 21 )	$	12,429


	Nine Months Ended September 30, 2024
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services(b)	$	2,861	$	166	$	638	$	1	$	( 3 )	$	3,663
Fee-based services	798		789		335		31		( 3 )		1,950
Total services	3,659		955		973		32		( 6 )		5,613
Commodity sales
Natural gas sales	1,632		—		—		33		( 5 )		1,660
Product sales	655		1,086		37		787		( 3 )		2,562
Other sales	14		—		—		63		( 1 )		76
Total commodity sales	2,301		1,086		37		883		( 9 )		4,298
Total revenues from contracts with customers	5,960		2,041		1,010		915		( 15 )		9,911
Other revenues(c)
Leasing services(d)	344		156		493		48		—		1,041
Derivatives adjustments on commodity sales	81		( 1 )		—		( 73 )		—		7
Other	120		19		—		15		—		154
Total other revenues	545		174		493		( 10 )		—		1,202
Total revenues	$	6,505	$	2,215	$	1,503	$	905	$	( 15 )	$	11,113

(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. Our revenues derived from leases were not material. We do not lease assets that qualify as sales-type or finance leases.

Contract Balances

As of September 30, 2025 and December 31, 2024, our contract asset balances were $ 36 million and $ 15 million, respectively. Of the contract asset balance at December 31, 2024, $ 7 million was transferred to accounts receivable during the nine months ended September 30, 2025. As of September 30, 2025 and December 31, 2024, our contract liability balances were $ 445 million and $ 377 million, respectively. Of the contract liability balance at December 31, 2024, $ 66 million was recognized as revenue during the nine months ended September 30, 2025.

In addition to our contract balances above, we also had lease contract liabilities associated with prepaid fixed reservation charges under a long-term terminaling contract totaling $ 545 million and $ 587 million as of September 30, 2025 and December 31, 2024, respectively.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue allocated to remaining performance obligations for contracted revenue that has not yet been recognized, representing our “contractually committed” revenue as of September 30, 2025 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
Three months ended December 31, 2025	$	1,390
2026	5,013
2027	4,260
2028	3,575
2029	3,142
Thereafter	18,291
Total	$	35,671

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, based on the practical expedient that we elected to apply, generally exclude 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

Our reportable segments are strategic business units that offer different products and services, have different marketing strategies, and are managed separately. The Company’s chief operating decision maker (CODM) is represented by the Office of the Chairman which consists of our Executive Chairman, Chief Executive Officer, and President. Our CODM evaluates performance principally based on each reportable segment’s earnings before DD&A expenses (EBDA), which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense. The CODM uses budgeted Segment EBDA compared to actual results to evaluate performance and allocate certain resources for each segment.

We consider each period’s EBDA to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at book value.

Effective January 1, 2025, amortization of basis differences related to our joint ventures (previously known as amortization of excess cost of equity investments) is included within “Earnings from equity investments” in our accompanying consolidated statements of income for the three and nine months ended September 30, 2025 and 2024, and therefore is included within Segment EBDA. As a result, Segment EBDA for the three and nine months ended September 30, 2024 has been adjusted to conform to the current presentation in the tables below.

Financial information by segment follows:


	Three Months Ended September 30, 2025
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	2,672	$	677	$	516	$	281	$	—	$	4,146
Intersegment revenues	4		—		2		1		( 7 )		—
Total revenues	2,676		677		518		282		( 7 )		4,146
Costs of sales	( 1,089 )		( 281 )		( 9 )		( 22 )
Labor	( 84 )		( 34 )		( 70 )		( 13 )
Fuel and power	( 23 )		( 25 )		( 4 )		( 42 )
Field - non-labor(a)	( 237 )		( 52 )		( 135 )		( 64 )

Taxes, other than income taxes	( 70 )		( 10 )		( 16 )		( 12 )
Earnings (loss) from equity investments	212		13		( 10 )		6
Other segment items(b)	6		—		—		—

Total Segment EBDA(c)	$	1,391	$	288	$	274	$	135			2,088
DD&A											( 609 )

General and administrative and corporate charges											( 184 )
Interest, net(d)											( 456 )
Income tax expense											( 185 )
Net income											$	654

Other segment activity information:
DD&A	$	294	$	81	$	130	$	98	$	6	$	609
Capital expenditures	572		53		79		79		10		793


	Three Months Ended September 30, 2024
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	2,173	$	711	$	496	$	319	$	—	$	3,699
Intersegment revenues	3		—		2		—		( 5 )		—
Total revenues	2,176		711		498		319		( 5 )		3,699
Costs of sales	( 673 )		( 325 )		( 8 )		( 21 )
Labor	( 81 )		( 32 )		( 70 )		( 12 )
Fuel and power	( 18 )		( 26 )		( 5 )		( 54 )
Field - non-labor(a)	( 236 )		( 56 )		( 142 )		( 54 )

Taxes, other than income taxes	( 64 )		( 11 )		( 13 )		( 17 )
Earnings from equity investments	174		16		2		7
Other segment items(b)	7		—		6		—

Total Segment EBDA(e)(f)	$	1,285	$	277	$	268	$	168			1,998
DD&A											( 587 )

General and administrative and corporate charges											( 181 )
Interest, net(d)											( 466 )
Income tax expense											( 113 )
Net income											$	651

Other segment activity information:
DD&A	$	276	$	90	$	126	$	87	$	8	$	587
Capital expenditures	415		53		80		100		9		657


	Nine Months Ended September 30, 2025
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	7,953	$	2,031	$	1,563	$	882	$	—	$	12,429
Intersegment revenues	13		—		6		2		( 21 )		—
Total revenues	7,966		2,031		1,569		884		( 21 )		12,429
Costs of sales	( 3,124 )		( 866 )		( 38 )		( 70 )
Labor	( 248 )		( 99 )		( 209 )		( 39 )
Fuel and power	( 62 )		( 68 )		( 15 )		( 108 )
Field - non-labor(a)	( 659 )		( 160 )		( 411 )		( 181 )

Taxes, other than income taxes	( 215 )		( 33 )		( 43 )		( 37 )
Earnings (loss) from equity investments	593		44		( 6 )		16
Other segment items(b)	29		1		2		1

Total Segment EBDA(c)	$	4,280	$	850	$	849	$	466			6,445
DD&A											( 1,835 )

General and administrative and corporate charges											( 564 )
Interest, net(d)											( 1,359 )
Income tax expense											( 548 )
Net income											$	2,139

Other segment activity information:
DD&A	$	875	$	274	$	388	$	279	$	19	$	1,835
Capital expenditures	1,474		192		232		264		44		2,206


	Nine Months Ended September 30, 2024
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	6,496	$	2,215	$	1,498	$	904	$	—	$	11,113
Intersegment revenues	9		—		5		1		( 15 )		—
Total revenues	6,505		2,215		1,503		905		( 15 )		11,113
Costs of sales	( 1,971 )		( 1,047 )		( 30 )		( 61 )
Labor	( 239 )		( 95 )		( 205 )		( 38 )
Fuel and power	( 57 )		( 68 )		( 15 )		( 121 )
Field - non-labor(a)	( 626 )		( 150 )		( 416 )		( 173 )

Taxes, other than income taxes	( 202 )		( 33 )		( 41 )		( 45 )
Earnings from equity investments	556		43		6		20
Other segment items(b)	44		—		16		41

Total Segment EBDA(e)(f)	$	4,010	$	865	$	818	$	528			6,221
DD&A											( 1,758 )

General and administrative and corporate charges											( 545 )
Interest, net(d)											( 1,402 )
Income tax expense											( 490 )
Net income											$	2,026

Other segment activity information:
DD&A	$	826	$	269	$	378	$	265	$	20	$	1,758
Capital expenditures	1,126		154		290		245		42		1,857


	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO 2		Corporate and Eliminations		Total
	(In millions)
Segment balance sheet information:
As of September 30, 2025
Investments	$	7,171	$	386	$	122	$	68	$	—	$	7,747
Other intangibles, net	800		536		13		425		—		1,774
Total assets(g)	51,605		8,509		7,938		3,593		671		72,316
As of December 31, 2024
Investments	$	7,252	$	387	$	132	$	74	$	—	$	7,845
Other intangibles, net	687		597		18		458		—		1,760
Total assets(g)	50,402		8,639		8,086		3,583		697		71,407

(a) Includes outside services, pipeline integrity maintenance, materials and supplies, and other operating costs.

(b) Includes miscellaneous operating and non-operating items primarily related to gains and losses associated with divestitures, impairments and/or equity investments, as applicable.

(c) Includes non-cash mark-to-market derivative hedge contract gain (loss) amounts for the three and nine months ended September 30, 2025 of $( 12 ) million and $( 3 ) million, none and $( 1 ) million, and $( 1 ) million and $ 3 million, respectively, for our Natural Gas Pipelines, Products Pipelines, and CO 2 business segments, respectively.

(d) We do not attribute interest and debt expense to any of our reportable business segments.

(e) Includes non-cash mark-to-market derivative hedge contract gain (loss) amounts for the three and nine months ended September 30, 2024 of $ 14 million and $( 29 ) million, $ 1 million and none , $ 1 million and $ 1 million, and $ 8 million and $ 1 million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, and CO 2 business segments, respectively.

(f) Segment EBDA previously reported (before reclassifications) for the three and nine months ended September 30, 2024 was $ 1,294 million and $ 4,035 million, $ 278 million and $ 871 million, $ 268 million and $ 818 million, and $ 170 million and $ 534 million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, and CO 2 business segments, respectively.

(g) Corporate 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 IT, 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 September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
	(In millions, except percentages)
Income tax expense	$	185		$	113		$	548		$	490
Effective tax rate	22.0		%	14.8		%	20.4		%	19.5		%

The effective tax rate for the three months ended September 30, 2025 is higher than the statutory federal rate of 21 % primarily due to state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings LLC, and Products (SE) Pipe Line Company (PPL).

The effective tax rate for the nine months ended September 30, 2025 is lower than the statutory federal rate of 21 % primarily due to (i) the recognition of investment tax credits generated by a biogas project; (ii) an adjustment to our deferred tax liability as a result of modified income allocations; and (iii) dividend-received deductions from our investments in Citrus, NGPL Holdings LLC, and PPL, partially offset by state income taxes.

The effective tax rate for the three and nine months ended September 30, 2024 is lower than the statutory federal rate of 21 % primarily due to (i) the recognition of investment tax credits generated by biogas projects reported on the 2023 filed tax return; (ii) an adjustment to our deferred tax liability as a result of a reduction in state income tax rates; and (iii) dividend-received deductions from our investments in Citrus, NGPL Holdings LLC, and PPL, partially offset by state income taxes.

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (OBBBA) that includes tax reform provisions that amend, eliminate and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. The most significant impact to the Company of the OBBBA at this time is the permanent reinstatement of bonus depreciation on qualified property and modifications to the calculation for excess business interest expense limitation under §163(j) to the current tax estimate. Based on our current projections, we anticipate the impact will defer the payment of a significant portion of our current federal tax for multiple years. The impact to current and deferred tax has been recorded with no overall impact to our income statement.

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 accrued liabilities and insurance, that the ultimate resolution of such items will not have a material adverse impact to our financial position, cash flows or operating results, unless otherwise indicated below. We believe we have numerous and substantial defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

Gulf LNG Facility Disputes

Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit in 2018 against Eni S.p.A. in the Supreme Court of the State of New York to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a contemporaneous terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG filed suit to enforce the Guarantee against Eni S.p.A. after an arbitration tribunal delivered an award 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, Eni S.p.A. filed counterclaims 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 based on the same substantive allegations that were dismissed with prejudice in previous separate arbitrations with Eni USA described above and with GLNG’s remaining customer Angola LNG Supply Services LLC, a consortium of international oil companies including Eni S.p.A. In early 2022, the trial court granted Eni S.p.A’s motion for summary judgment on GLNG’s claims to enforce the Guarantee. The Appellate Division denied GLNG’s appeal. GLNG elected not to pursue further recourse to the state Court of Appeals, which is the state’s highest appellate court, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment and entered judgment dismissing all of Eni S.p.A.’s claims with prejudice on September 15, 2023. On September 24, 2024, the Appellate Division affirmed the entry of summary judgment in GLNG’s favor. On September 16, 2025, the Court of Appeals denied Eni S.p.A.’s motion for leave to appeal, thereby terminating Eni S.p.A.’s recourse in state court against GLNG.

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 14 th Court of Appeals. On April 15, 2025, the 14th Court of Appeals reversed and remanded the case to the trial court for further proceedings to resolve disputed issues of material fact. We believe we have numerous and substantial defenses and 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 complaint, which was transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590) and amended to include the Kinder Morgan Retirement Plan B, alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits which are now contested on a 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 challenge plan provisions that are alleged to constitute impermissible “backloading” or “cutback” of benefits and seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. 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. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three subclasses of individuals who are allegedly due benefits under one or more of the six claims asserted in the complaint. On July 25, 2024, the Court decided the parties’ respective cross-motions for summary judgment. The Court granted our motion for summary judgment with respect to Claims I and II based on the Court’s determination that the formula used to calculate projected service was neither backloaded nor a violation of ERISA’s anti-cutback rule. The Court granted plaintiffs’ motion for partial summary judgment with respect to Claim III because the Court found that the summary plan description did not include any clarifying examples or illustrations of accrued benefits using the applicable formula. The Court granted plaintiffs’ motion for partial summary judgment as to Claim IV based upon the Court’s finding that an amendment to the plan in 2007 violated ERISA’s anti-cutback protection by terminating the accrual of early retirement benefits in connection with the sale of ANR. The Court

granted plaintiffs’ motion for partial summary judgment as to Claim V because the Court found that the plan administrator used an inconsistent interpretation to calculate benefits for some retirees. The Court dismissed Claim VI without prejudice based upon its determination that the claim is moot given that the Court allowed plaintiffs’ motion as to Counts IV and V. The Court’s decision on partial summary judgment did not address the extent of potential plan liabilities for past or future benefits or other potential damages or equitable relief. On March 11, 2025, the case was mediated without resolution. Pursuant to the Court’s subsequent briefing schedule, the parties filed summary judgment briefs to address potential remedies for Claims III, IV, and V. Plaintiffs seek equitable and other relief including early retirement benefits, monetary damages or other equitable relief estimated to be in excess of $ 100 million. We vigorously oppose the form and scope of relief sought by the plaintiffs and believe we have numerous and substantial defenses to support our vigorous defense at the trial or appellate levels if necessary. To the extent an adverse judgment or settlement results in an increase in plan liabilities, we may elect as the sponsor of the plans to address them in accordance with applicable ERISA provisions, including provisions that allow for contributions to the plans over multiple years.

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.

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, CO 2 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. 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 financial position, cash flows or operating results.

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 financial position, cash flows or operating results, 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 accrued for 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 liabilities have been established for those sites where our contribution is probable and reasonably estimable. Because costs associated with remedial plans are generally expected to be spread over at least several years, we do not anticipate that our share of the cost of remediation will have a material adverse impact to our financial position, cash flows or operating results. 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 CO 2 , 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 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 by December 31, 2026. 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. In August 2024, we reached an agreement to settle claims first made in January 2021 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 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 the 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 in a captioned USA v. Alden Leeds, et al . On January 17, 2024, the DOJ on behalf of the EPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a modified Consent Decree in the U.S. District Court. On January 31, 2024, the DOJ on behalf of the EPA filed a Motion to Enter Consent Decree in the U.S. District Court. On January 16, 2025, the U.S. District Court entered the Consent Decree, after which time, the Consent Decree was appealed to the U.S. Court of Appeals for the Third Circuit by two PRPs alleging, inter alia , that the Consent Decree is not procedurally and substantively fair, reasonable, and consistent with the purpose of CERCLA.

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. The lawsuits 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. Plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and restoration costs. 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 petitions in the state district court for Plaquemines Parish 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. Plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and restoration costs. In May 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana and has been stayed pending the resolution of federal question jurisdictional issues in separate consolidated cases to which TGP is not a party. 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 (Orleans) filed a petition 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 restoration costs. In April 2019, the case was removed to the U.S. District Court for the Eastern District of Louisiana. On February 28, 2024, the U.S. District Court entered partial final judgment dismissing a co-defendant and stayed the case pending an appeal by Orleans to the U.S. Court of Appeals for the Fifth Circuit. On January 23, 2025, the U.S. Court of Appeals for the Fifth Circuit affirmed the U.S. District Court’s judgment,

thereby retaining jurisdiction and dismissing a co-defendant on the basis that SLCRMA does not apply to a co-defendant’s pipeline constructed prior to the regulation’s effective date. Considering this ruling and that SNG’s pipelines were constructed prior to the regulation’s effective date, SNG filed a motion for summary judgment seeking to be dismissed on the same basis. Shortly after SNG’s motion for summary judgment was filed and before Orleans filed any opposition thereto, Orleans agreed to a settlement in principle requiring the petition to be dismissed with prejudice.

General

As of September 30, 2025 and December 31, 2024, we had liabilities of $ 183 million and $ 188 million, respectively, recorded for environmental matters. In addition, as of both September 30, 2025 and December 31, 2024, we had receivables of $ 10 million, 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 (the DC Circuit) seeking review of the EPA’s final action promulgating 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 (NAAQS), known as the “Good Neighbor Plan” (the Plan) ( Kinder Morgan, Inc., et al. v. EPA, et al. consolidated into Utah, et al. v. EPA, et al.). On October 13, 2023, in combination with other parties, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court ( Kinder Morgan, Inc., et al. v. EPA, et al. consolidated into Ohio, et al. v. EPA, et al.) , which the court granted on June 27, 2024, ruling that enforcement of the Plan shall be stayed pending the disposition of the case on the merits by the DC Circuit and any subsequent timely appeals.

Subsequently, the EPA filed a Motion for Remand asking the DC Circuit to remand without vacatur the Plan to the EPA for voluntary reconsideration, explaining that the “EPA has identified specific issues with the Rule that make reconsideration appropriate, including issues raised by Petitioners in this litigation.” On April 14, 2025, the DC Circuit held the case in abeyance pending further order of the court and ordered the parties to file periodic status reports until the EPA completes its review of the Plan.

10. Recent Accounting Pronouncements

Accounting Standards Updates (ASU)

ASU No. 2023-09

On December 14, 2023, the FASB issued ASU No. 2023-09, “ Income Taxes (Topic 740): Improvements to Income Tax Disclosures .” This ASU improves the transparency of annual income tax disclosures by requiring (i) consistent categories and greater disaggregation of information in the rate reconciliation and (ii) income taxes paid disaggregated by jurisdiction. We expect to implement this ASU beginning with our Annual Report on Form 10-K for the year ended December 31, 2025.

ASU No. 2024-03

On November 4, 2024, the FASB issued ASU No. 2024-03, “ Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40). ” This ASU improves financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU will be effective for annual periods beginning after December 15, 2026, for interim reporting periods beginning after December 15, 2027, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures.

ASU No. 2025-06

On September 18, 2025, the FASB issued ASU No. 2025-06, “ Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software. ” This ASU modernizes the accounting guidance for the costs to develop software for internal use by removing outdated stage-based cost capitalization rules and replacing them with a probability-based cost-capitalization framework that aligns better with current software development methods. This ASU will be effective for annual periods beginning after December 15, 2027, for interim reporting periods beginning within those annual periods, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s financial statements.

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 2024 Form 10-K; (ii) our management’s discussion and analysis of financial condition, and results of operations included in our 2024 Form 10-K; (iii) “ Information Regarding Forward-Looking Statements ” at the beginning of this report, and in our 2024 Form 10-K; and (iv) “ Risk Factors ” in this report, in Part II, Item 1A in our March 31, 2025 Form 10-Q, and in Part I, Item 1 in our 2024 Form 10-K.

Acquisition

The following acquisition was made during the 2025 period. See Note 2. “Acquisitions and Divestiture” to our consolidated financial statements for further information on this transaction.


Event	Description	Business Segment
Outrigger Energy acquisition $648 million (February 2025)	Natural gas gathering and processing system in North Dakota from Outrigger Energy II LLC which includes a 0.27 Bcf/d processing facility and a 104-mile, large-diameter, high-pressure rich gas gathering header pipeline with 0.35 Bcf/d of capacity connecting supplies from the Williston Basin area to high-demand markets.	Natural Gas Pipelines (Midstream)

2025 Dividends and Discretionary Capital

We expect to declare dividends of $1.17 per share for 2025, a 2% increase from the 2024 declared dividends of $1.15 per share. W e expect to invest $3.0 billion in e xpansion projects, acquisitions, and contributions to joint ventures during 2025.

The expectations for 2025 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. an d Segment earnings before DD&A expenses (EBDA) (as presente d in Note 7 “Reportable Segments”), along with the non-GAAP financial measures of Adjusted Net Income Attributable to Common Stock, in the aggregate and per share, Adjusted Segment EBDA, Adjusted Net Income Attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses and amortization of basis differences related to our joint ventures (previously known as amortization of excess cost of equity investments) (EBITDA), and Net Debt.

GAAP Financial Measures

Our Consolidated Earnings Results for the three and nine months ended September 30, 2025 and 2024 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.

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 Net Income Attributable to Kinder Morgan, Inc., ” “ —Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock, ” 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 associated with Joint Ventures” below). The following table summarizes our Certain Items for the three and nine months ended September 30, 2025 and 2024, which are also described in more detail in the footnotes to tables included in “ —Segment Earnings Results ” below.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
Certain Items


Change in fair value of derivative contracts(a)	$	24	$	(20)	$	13	$	32
Gain on divestitures(b)	—		—		—		(70)

Income tax Certain Items(c)	(4)		(49)		(41)		(48)
Other	—		1		1		3
Total Certain Items(d)(e)	$	20	$	(68)	$	(27)	$	(83)

(a) Gains or losses are reflected within non-GAAP financial measures when realized.

(b) 2024 amount for the nine-month period includes a gain of $41 million on the divestiture of CO 2 assets and a gain of $29 million on the divestiture of Oklahoma midstream assets.

(c) 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.

(d) 2025 amounts for the three and nine-month periods each include the $(1) million report ed within “Earnings from equity investments” on the accompanying consolidated statement of income of “Change in fair value of derivative contracts.”

(e) Amounts for the periods ending September 30, 2025 and 2024 inclu de $11 million and $4 million, respectively, for the three-month periods and $12 million and $5 million for the nine-month periods, respectively, reported within “Interest, net” on the accompanying consolidated statements of income of “Change in fair value of derivative contracts.”

Adjusted Net Income Attributable to Kinder Morgan, Inc.

Adjusted Net Income Attributable to Kinder Morgan, Inc. is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. 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 ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to

Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.” below.

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities . We believe Adjusted Net Income Attributable to Common Stock allows for calculation of adjusted earnings per share (Adjusted EPS) on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculat ed as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors, and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting segment earnings before DD&A, general and administrative expenses and corporate charges, interest expense, and income taxes (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 “ —Segment Earnings Results ” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A, amortization of basis differences related to our joint ventures, income tax expense, and interest. We also include amounts from joint ventures for income taxes and DD&A (see “ — Amounts associated with 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 associated with Joint Ventures

Certain Items 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 calculation of Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include DD&A, amortization of basis differences, and income tax expense with respect to the joint ventures as those included in the calculation of 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 Adjusted EBITDA ” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculation of Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses, or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of September 30, 2025, by subtracting the following amounts from our debt balance of $ 32,580 million: (i) cash and cash equivalents of $71 million; (ii) debt fair value adjustments of $196 million; and

(iii) the foreign exchange impact on Euro-denominated bonds of $44 million f or 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 September 30,
	2025		2024		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	4,146	$	3,699	$	447	12	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(1,395)		(1,024)		(371)		(36)	%
Operations and maintenance	(786)		(790)		4		1	%
DD&A	(609)		(587)		(22)		(4)	%
General and administrative	(183)		(176)		(7)		(4)	%
Taxes, other than income taxes	(111)		(107)		(4)		(4)	%

Other income, net	1		—		1		—	%
Total Operating Costs, Expenses and Other	(3,083)		(2,684)		(399)		(15)	%
Operating Income	1,063		1,015		48		5	%
Other Income (Expense)
Earnings from equity investments	221		199		22		11	%

Interest, net	(456)		(466)		10		2	%
Other, net	11		16		(5)		(31)	%
Total Other Expense	(224)		(251)		27		11	%
Income Before Income Taxes	839		764		75		10	%
Income Tax Expense	(185)		(113)		(72)		(64)	%
Net Income	654		651		3		—	%
Net Income Attributable to Noncontrolling Interests	(26)		(26)		—		—	%
Net Income Attributable to Kinder Morgan, Inc.	$	628	$	625	$	3	—	%
Basic and diluted earnings per share	$	0.28	$	0.28	$	—	—	%
Basic and diluted weighted average shares outstanding	2,224		2,221		3		—	%
Declared dividends per share	$	0.2925	$	0.2875	$	0.005	2	%


	Nine Months Ended September 30,
	2025		2024		Earnings increase/(decrease)
	(In millions, except percentages)
Revenues	$	12,429	$	11,113	$	1,316	12	%
Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	(4,082)		(3,098)		(984)		(32)	%
Operations and maintenance	(2,270)		(2,211)		(59)		(3)	%
DD&A	(1,835)		(1,758)		(77)		(4)	%
General and administrative	(558)		(530)		(28)		(5)	%
Taxes, other than income taxes	(334)		(327)		(7)		(2)	%

Other income, net	10		87		(77)		(89)	%
Total Operating Costs, Expenses and Other	(9,069)		(7,837)		(1,232)		(16)	%
Operating Income	3,360		3,276		84		3	%
Other Income (Expense)
Earnings from equity investments	647		625		22		4	%

Interest, net	(1,359)		(1,402)		43		3	%
Other, net	39		17		22		129	%
Total Other Expense	(673)		(760)		87		11	%
Income Before Income Taxes	2,687		2,516		171		7	%
Income Tax Expense	(548)		(490)		(58)		(12)	%
Net Income	2,139		2,026		113		6	%
Net Income Attributable to Noncontrolling Interests	(79)		(80)		1		1	%
Net Income Attributable to Kinder Morgan, Inc.	$	2,060	$	1,946	$	114	6	%
Basic and diluted earnings per share	$	0.92	$	0.87	$	0.05	6	%
Basic and diluted weighted average shares outstanding	2,223		2,220		3		—	%
Declared dividends per share	$	0.8775	$	0.8625	$	0.015	2	%

Our consolidated revenues primarily consist of services and sales revenue. Our services 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 sales revenues include sales of natural gas (includes natural gas and RNG), products (includes NGL, crude oil, CO 2 , and transmix), and other (includes RINs). Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the costs of sales associated with purchases will usually have a commensurate and offsetting impact, except for the CO 2 segment, which produces, instead of purchases, the crude oil, CO 2 , and RINs 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 nine-month periods ended September 30, 2025 and 2024:

Revenues

Revenues increased $447 million and $1,316 million for the three and nine months ended September 30, 2025, respectively, as compared to the respective prior year periods.

The increases were primarily due to (i) increases in natural gas sales of $392 million and $1,173 million, respectively, due to higher natural gas commodity prices and volumes; (ii) increases in services revenues of $112 million and $341 million, respectively , resulting from higher volumes, primarily driven by increased demand for services and expansion projects placed into service, higher rates, and the Outrigger Energy assets acquired in February 2025; an d (iii) an increase in other sales for the nine-month period of $20 million driven by higher RIN sales. Revenues were further increased by $26 million in the nine-month period for the impacts of derivative contracts used to hedge commodity sales. These increases in revenues were partially

offset by lower product sales of $65 million and $254 million, respectively, driven primarily by lowe r prices partially offset by higher volumes and in the nine-month period, by asset divestitures in 2024 partially offset by assets acquired in 2024. The increase in sales revenues had corresponding increases in our costs of sales as described below under “ Operati ng Costs, Expenses and Other—Costs of sales .”

Operating Costs, Expenses and Other

Costs of sales

Costs of sales increased $371 million and $984 million for the three and nine months ended September 30, 2025, respectively, as compared to the respective prior year periods. The increases, which are net of the impact of our divested assets for the nine-month period, were primarily due to higher costs of sales for natural gas of $403 million and $1,112 million, respectively, primarily due to higher commodity prices and volumes. These increases were partially offset by lower costs of sales for products of $48 million and $153 million , respectively, driven by lower commodity prices partially offset by higher volumes.

Operations and Maintenance

Operations and maintenance decreased $4 million and increased $59 million for the three and nine months ended September 30, 2025, respectively, as compared to the respective prior year periods . The nine-month period increase was primarily driven by greater activity levels, including from expansions, and inflation, including labor costs.

Other Income, net

Other income, net increased $1 million and decreased $77 million for the three and nine months ended September 30, 2025, respectively, as compared to the respective prior year periods. The nine-month period decrease was primarily the result of gains on the divestitures of CO 2 assets and of Oklahoma midstream assets in 2024.

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. Interest, ne t decreased $10 million and $43 million for the three and nine months ended September 30, 2025, respectively, compared to the respective prior year periods. The decreases were primarily due to lower interest rates associated with our fixed-to-variable interest rate swap agreements partially offset by higher interest rates on our long-term debt, and in the nine-month period, higher average total debt balances.

Non-GAAP Financial Measures

Reconciliations from Net Income Attributable to Kinder Morgan, Inc.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions, except per share amounts)
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.
Net income attributable to Kinder Morgan, Inc.	$	628	$	625	$	2,060	$	1,946
Certain Items(a)


Change in fair value of derivative contracts	24		(20)		13		32
Gain on divestitures	—		—		—		(70)

Income tax Certain Items	(4)		(49)		(41)		(48)
Other	—		1		1		3
Total Certain Items	20		(68)		(27)		(83)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	648	$	557	$	2,033	$	1,863

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock
Net income attributable to Kinder Morgan, Inc.	$	628	$	625	$	2,060	$	1,946
Total Certain Items(b)	20		(68)		(27)		(83)
Net income allocated to participating securities and other(c)	(4)		(4)		(11)		(10)

Adjusted Net Income Attributable to Common Stock	$	644	$	553	$	2,022	$	1,853

Adjusted EPS	$	0.29	$	0.25	$	0.91	$	0.83

Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA
Net income attributable to Kinder Morgan, Inc.	$	628	$	625	$	2,060	$	1,946








Total Certain Items(b)	20		(68)		(27)		(83)
DD&A	609		587		1,835		1,758

Income tax expense(d)	189		162		589		538
Interest, net(e)	445		462		1,347		1,397
Amounts associated with joint ventures
Unconsolidated joint venture DD&A(f)	96		111		296		308
Remove consolidated joint venture partners’ DD&A	(16)		(16)		(47)		(47)
Unconsolidated joint venture income tax expense(g)	20		17		67		58
Adjusted EBITDA	$	1,991	$	1,880	$	6,120	$	5,875

(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 Net Income Attributable to Kinder Morgan, Inc. ” for a detailed listing.

(c) Other includes Adjusted net income in excess of distributions for participating securities of $1 million for the nine-month period ended September 30, 2024.

(d) To avoid duplication, adjustments for income tax expense for the periods ended September 30, 2025 and 2024 exclude $(4) million and $(49) million for the three-month periods, respectively, and $(41) million and $(48) million for the nine-month periods, respect ively, which amounts are already included within “Certain Items.” See table included in “ —Overview—Non-GAAP Financial Measu res— Certain Items” above.

(e) To avoid duplication, adjustments for interest, net for the periods ended September 30, 202 5 and 2024 exclude $11 million and $4 million for the three-month periods, respectively, and $12 million and $5 million for the nine-month periods, respectively, which amounts are already included within “Certain Items.” See table included in “ —Overview—Non-GAAP Fin ancial Measures— Certain Items,” above.

(f) Includes amortization of basis differences related to our joint ventures which was previously presented separately as amortization of excess cost of equity investments .

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

Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc. and Adjusted EBITDA :


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	648	$	557	$	2,033	$	1,863
Adjusted EBITDA	1,991		1,880		6,120		5,875

Change from prior period	Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	91			$	170
Adjusted EBITDA	$	111			$	245

Adjusted Net Income Attributable to Kinder Morgan, Inc. increased $91 million and $170 million for the three and nine months ended September 30, 2025, respectively, as compared to the respective prior year periods. The increases resulted primarily from favorable earnings in our Natural Gas Pipelines business segment, which was also a primary driver of the increase in Adjusted EBITDA of $111 million and $245 million, respectively.

General and Administrative and Corporate Charges


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
General and administrative	$	(183)	$	(176)	$	(558)	$	(530)
Corporate charges	(1)		(5)		(6)		(15)
Certain Items(a)	—		1		1		3
General and administrative and corporate charges	$	(184)	$	(180)	$	(563)	$	(542)

Change from prior period	Earnings increase/(decrease)
General and administrative	$	(7)			$	(28)
Corporate charges	4				9
Total	$	(3)			$	(19)

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

General and administrative expenses increased $7 million and $28 million, and corporate charges decreased $4 million and $9 million for the three and nine months ended September 30, 2025, respectively, when compared with the respective prior year period s. The combined changes primarily include higher benefit-related and labor costs partially offset by lower pension costs.

Segment Earnings Results

Natural Gas Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions, except operating statistics)
Revenues	$	2,676	$	2,176	$	7,966	$	6,505
Costs of sales	(1,089)		(673)		(3,124)		(1,971)
Other operating expenses(a)	(414)		(399)		(1,184)		(1,124)

Other income	1		—		8		39
Earnings from equity investments	212		174		593		556

Other, net	5		7		21		5
Segment EBDA	1,391		1,285		4,280		4,010
Certain Items:

Change in fair value of derivative contracts	12		(14)		3		29
Gain on divestiture	—		—		—		(29)
Certain Items(b)	12		(14)		3		—
Adjusted Segment EBDA	$	1,403	$	1,271	$	4,283	$	4,010

Change from prior period	Increase/(Decrease)
Segment EBDA	$	106			$	270
Adjusted Segment EBDA	$	132			$	273

Volumetric data(c)
Transport volumes (BBtu/d)	47,461		44,827		46,013		44,166
Sales volumes (BBtu/d)	3,712		2,694		3,051		2,584
Gathering volumes (BBtu/d)	4,380		4,005		4,101		4,130
NGLs (MBbl/d)	39		34		37		38

(a) Operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. For the periods ending September 30, 2025 and 2024 Certain Items of (i ) $13 million an d $(14) million for the three-month periods, respectively, and $4 million and $0 for the nine-month periods, respectively, are associated with our Midstream business and (ii) $(1) million fo r each of the 2025 three and nine-month periods is associated with our East business. See “ —Overview—Non-GAAP Financial Measures— Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c) Joint venture throughput is reported at our ownership share . Volumes for acquired assets are included for all periods presented. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

Below are the changes in Natural Gas Pipelines Segment EBDA:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
East	$	687	$	627	$	2,112	$	1,985
Midstream	483		435		1,452		1,324
West	221		223		716		701
Total Natural Gas Pipelines	$	1,391	$	1,285	$	4,280	$	4,010

Change from prior period	Increase/(Decrease)
East	$	60			$	127
Midstream	$	48			$	128
West	$	(2)			$	15

The changes in Natural Gas Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

• The $60 million (10%) and $127 million (6%) increases, respectively, in Ea st were primarily driven by, on T GP, increased rates related to weather-driven demand for services as well as expansion projects that went into service and higher equity earnings from Citrus that primarily resulted from lower DD&A. The increase in the nine-month period was further driven by higher equity earnings from Midcontinent Express Pipeline LLC resulting from increased rates partially offset by (i) an expired customer agreement on our Stagecoach assets; (ii) lower equity earnings from SNG primarily driven by higher legal and operating costs; and (iii) higher pipeline maintenance costs on TGP.

• The $48 million (11%) and $128 million (10%) increases, respectively, in Midstream were primarily driven by (i) increased demand for our services on our Texas intrastate systems; (ii) contributions from the acquired Outrigger Energy assets on our Hiland Midstream assets; and (iii) higher equity earnings from Kinder Morgan Utopia Holdco LLC resulting primarily from increased volumes. The increase in the nine-month period was further impacted by higher gathering rates on KinderHawk Field Services LLC. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, Midstream was impacted by non-cash mark-to-market derivative contracts used to hedge forecasted commodity sales and purchases, primarily increasing costs of sales in the three-month period, and increasing revenues in the nine-month period, offset by a gain on sale of our Oklahoma assets in the nine-month 2024 period, all of which we treated as Certain Items.

• The $15 million (4%) nine-month period increase in West was driven by a new service provided by Cheyenne Plains Gas Pipeline Company, L.L.C. to its customers in 2025.

Products Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions, except operating statistics)
Revenues	$	677	$	711	$	2,031	$	2,215
Costs of sales	(281)		(325)		(866)		(1,047)
Other operating expenses(a)	(121)		(125)		(360)		(346)

Other income	—		—		1		—
Earnings from equity investments	13		16		44		43


Segment EBDA	288		277		850		865
Certain Items:
Change in fair value of derivative contracts	—		(1)		1		—

Certain Items(b)	—		(1)		1		—
Adjusted Segment EBDA	$	288	$	276	$	851	$	865

Change from prior period	Increase/(Decrease)
Segment EBDA	$	11			$	(15)
Adjusted Segment EBDA	$	12			$	(14)

Volumetric data(c)
Gasoline(d)	978		1,010		976		980
Diesel fuel	373		363		359		351
Jet fuel	301		302		309		298
Total refined product volumes	1,652		1,675		1,644		1,629
Crude and condensate	459		472		479		474
Total delivery volumes (MBbl/d)	2,111		2,147		2,123		2,103

(a) Operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. The 2025 and 2024 Certain Items are associated with our Southeast Refined Products business. See “ —Overview—Non-GAAP Financial Measures— Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(d) Volumes include ethanol pipeline volumes.

Below are the changes in Products Pipelines Segment EBDA:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
Southeast Refined Products	$	71	$	60	$	220	$	209
West Coast Refined Products	158		153		462		443
Crude and Condensate	59		64		168		213
Total Products Pipelines	$	288	$	277	$	850	$	865

Change from prior period	Increase (Decrease)
Southeast Refined Products	$	11			$	11
West Coast Refined Products	$	5			$	19
Crude and Condensate	$	(5)			$	(45)

The changes in Products Pipelines Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

• The $11 million (18%) and $11 million (5%) increases, respectively, in Southeast Refined Products were primarily driven by lower price s on costs of sales at our Transmix processing operations.

• The $5 million (3%) and $19 million (4%) increases, respectively , in West Coast Refined Products resulted from, on our Pacific operations, higher transportation rates and, in the nine-month period, higher terminal delivery fees partially offset by unfavorable changes in product gains. The increase in the nine-month period was further impacted by higher rates at our West Coast Terminals.

• The $5 million (8%) and $45 million (21%) decreases, respectively, in Crude and Condensate were drive n by the expiration of legacy crude contracts in advance of the Double H pipeline conversion to NGL service partially offset, in the three-month period, by higher gathering volumes on our Bakken Crude assets. The decrease in the nine-month period was also driven by a planned ten-year turnaround in the first quarter 2025 at our KM Condensate Processing facility and lower margin from our Crude and Condensate business resulting primarily from decreased spreads.

Terminals (including reconciliation of Segment EBDA to Adjusted Segment EBDA)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2025			2024			2025			2024
	(In millions, except operating statistics)
Revenues	$	518		$	498		$	1,569		$	1,503
Costs of sales	(9)			(8)			(38)			(30)
Other operating expenses(a)	(225)			(230)			(678)			(677)

Other income	—			—			—			7
(Loss) earnings from equity investments	(10)			2			(6)			6
Other, net	—			6			2			9
Segment EBDA	$	274		$	268		$	849		$	818
Certain Items:
Change in fair value of derivative contracts	—			(1)			—			(1)
Certain Items(b)	—			(1)			—			(1)
Adjusted Segment EBDA	$	274		$	267		$	849		$	817

Change from prior period	Increase/(Decrease)
Segment EBDA	$	6					$	31
Adjusted Segment EBDA	7						32

Volumetric data(c)
Liquids leasable capacity (MMBbl)	78.7			78.6			78.7			78.6
Liquids utilization %(d)	94.6		%	94.9		%	94.4		%	94.3		%
Bulk transload tonnage (MMtons)	12.3			13.4			37.6			41.1

(a) Operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above. The 2024 Certain Items are associated with our Liquids business. See “ —Overview—Non-GAAP Financial Measures— Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(d) 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 adjusted for all periods presented from the historica l business grouping and included within the Other group.

Below are the changes in Terminals Segment EBDA:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
Jones Act tankers	$	60	$	48	$	179	$	139
Liquids	156		151		484		474
Bulk	58		67		186		201
Other	—		2		—		4



Total Terminals	$	274	$	268	$	849	$	818

Change from prior period	Increase/(Decrease)
Jones Act tankers	$	12			$	40
Liquids	$	5			$	10
Bulk	$	(9)			$	(15)
Other	$	(2)			$	(4)

The changes in Terminals Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

• The $12 million (25%) and $40 million (29%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

• The $5 million (3%) and $10 million (2%) increases, respectively, in Liquid s were driven by (i) higher rates primarily at our Houston Ship Channel facilities; (ii) contributions from expansion projects; and (iii) in the three-month period, lower operating costs, partially offset by lower equity earnings resulting from an impairment of an equity investment in the 2025 three and nine-month periods.

• The $9 million (13%) and $15 million (7%) decreases, respectively, in Bul k were primarily driven by the impact of the 2025 closure of LyondellBasell’s Houston refinery on our petroleum coke handling operations. The decrease in the nine-month period was further driven by decreased volumes and handling activities for coal offset by lower demurrage costs at our International Marine Terminal.

CO 2 (including reconciliation of Segment EBDA to Adjusted Segment EBDA)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions, except operating statistics)
Revenues	$	282	$	319	$	884	$	905
Costs of sales	(22)		(21)		(70)		(61)
Other operating expenses(a)	(131)		(137)		(365)		(377)

Other income	—		—		1		41
Earnings from equity investments	6		7		16		20

Segment EBDA	135		168		466		528
Certain Items:
Change in fair value of derivative contracts	1		(8)		(3)		(1)
Gain on divestitures	—		—		—		(41)
Certain Items(b)	1		(8)		(3)		(42)
Adjusted Segment EBDA	$	136	$	160	$	463	$	486

Change from prior period	Increase/(Decrease)
Segment EBDA	$	(33)			$	(62)
Adjusted Segment EBDA	$	(24)			$	(23)

Volumetric data(c)
SACROC oil production	18.01		19.02		18.56		19.01
Yates oil production	5.90		5.90		5.95		6.08
Other	1.13		1.16		1.11		1.20
Total oil production, net (MBbl/d)(d)	25.04		26.08		25.62		26.29
NGL sales volumes, net (MBbl/d)(d)	9.03		8.69		9.11		8.49

CO 2 sales volumes, net (Bcf/d)	0.274		0.319		0.292		0.323
RNG sales volumes (BBtu/d)	11		10		10		8
Realized weighted average oil price ($ per Bbl)	$	67.74	$	68.42	$	67.91	$	68.86
Realized weighted average NGL price ($ per Bbl)	$	31.09	$	32.38	$	32.85	$	29.36

(a) Operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b) See table included in “ —Overview—Non-GAAP Financial Measures— Certain Items” above . The 2025 and 2024 Certain Items are associated with our Oil and Gas Producing activities. See “ —Overview—Non-GAAP Financial Measures— Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c) Volumes for acquired assets are included for all periods presente d, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

(d) Net of royalties and outside working interests.

Below are the changes in CO 2 Segment EBDA:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2025		2024		2025		2024
	(In millions)
Source and Transportation activities	$	36	$	49	$	121	$	143
Oil and Gas Producing activities	92		95		314		347

Subtotal	128		144		435		490
Energy Transition Ventures	7		24		31		38
Total CO 2	$	135	$	168	$	466	$	528

Change from prior period	Increase/(Decrease)
Source and Transportation activities	$	(13)			$	(22)
Oil and Gas Producing activities	$	(3)			$	(33)
Energy Transition Ventures	$	(17)			$	(7)

The changes in CO 2 Segment EBDA in the comparable three and nine-month periods ended September 30, 2025 and 2024 are explained by the following discussion:

• The $13 million (27%) and $22 million (15%) decreases, respectively, in Source and Transportation activities were driven by lower CO 2 volumes. The nine-month period decrease was further driven by lower realized CO 2 sales prices partially offset by higher volumes on our Wink pipeline.

• T he $3 million (3%) and $33 million (10%) decreases, respectively, in Oil and Gas Producing activities were driven by non-cash mark-to-market sales derivative hedge contracts in the three-month period, and in the nine-month period, a $41 million gain on sale of oil and gas producing fields in the 2024 period, all of which we treated as Certain Items.

In addition, Oil and Gas Producing activities were favorably impacted by lower power costs partially offset by lower crude oil volumes. The nine-month period was further impacted by assets acquired in June 2024 and higher realized NGL prices and volumes partially offset by assets divested in June 2024.

• The $17 million (71%) and $7 million (18%) decreases, respectively, in Energy Transition Ventures were primarily due to higher operating costs and lower RIN sales prices. The nine-month period decrease was partially offset by higher RIN sales volumes.

We believe that our existing hedge contracts in place within our CO 2 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 CO 2 business segment hedges outstanding as of September 30, 2025:


	Remaining 2025		2026		2027		2028
Crude Oil(a)
Price ($ per Bbl)	$	66.98	$	64.63	$	65.22	$	64.51
Volume (MBbl/d)	23.15		20.20		10.00		4.00
NGLs
Price ($ per Bbl)	$	47.01	$	44.64
Volume (MBbl/d)	4.77		1.87

(a) Incl udes WTI hedges.

Liquidity and Capital Resources

General

As of September 30, 2025, we had $71 million of “Cash and cash equivalents,” a decrease of $17 million from December 31, 2024. Additionally, as of September 30, 2025, we had borrowing capacity of approximately $2.9 billion under our credit facility (discussed below in “— Short-term Liquidity ”). As discussed further below, we believe our cash flows from operating activities, cash position, and remaining borrowing capacity on our credit facility is more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flows from operations, providing a source of funds of $4,225 million and $4,125 million in the first nine months of 2025 and 2024, respectively. The period-to-period increase is discussed below in “ —Cash Flows—Operating Activities .” We primarily rely on cash provided by operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time, short-term borrowings are used to fund working capital and finance incremental capital investments, if any. Incremental capital investments initially funded through short-term borrowings may periodically be replaced with long-term financing and/or paid down using retained cash from operations.

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 detailed below:


	September 30, 2025		December 31, 2024

	(In millions)


Variable rate debt(a)	$	568		$	371
Notional principal amount of fixed-to-variable interest rate swap agreements	3,500			4,750
Notional principal amount of variable-to-fixed interest rate swap agreements(b)	(1,500)			(1,500)
Debt balances subject to variable interest rates	$	2,568		$	3,621

(a) Includes $568 million and $331 million at September 30, 2025 and December 31, 2024, respectively, of commercial paper notes.

(b) Consist of interest rate swap agreements set to expire December 2025.

Our board of directors declared a quarterly dividend of $0.2925 per share for the third quarter of 2025, a 2% increase over the dividend declared for the third quarter of 2024.

In February 2025 and June 2025, Standard and Poor’s and Moody’s Investor Services, respectively, upgraded our rating outlook to positive. In August 2025, Fitch Ratings, Inc. upgraded our senior unsecured rating from BBB to BBB+.

Short-term Liquidity

As of September 30, 2025, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $3.5 billion credit facility with an available capacity of approximately $2.9 billion and an associated $3.5 billion commercial paper program. The loan commitments under our credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings and letters of credit reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.

As of September 30, 2025, our $1,081 million of short-term debt consisted primarily of commercial paper borrowings and 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 as of December 31, 2024 was $2,009 million.

We had working capital (defined as current assets less current liabilities) deficits of $1,420 million and $2,580 million as of September 30, 2025 and December 31, 2024, respectively. The overall $1,160 million favorable change from year-end 2024 was primarily due to (i) a $1,125 million decrease in senior notes that mature in the next twelve months resulting from $1,500 million of senior notes that matured in June 2025; and (ii) a $181 million decrease in accrued interest, partially offset by a $237 million increase in commercial paper borrowings partly used to fund our Outrigger Energy acquisition. Generally, our working capital 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 equivalents as a result of excess cash from operations after payments for investing and financing activities.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. 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 capital expenditures 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.

Our capital expenditures for the nine months ended September 30, 2025, and the amount we expect to spend for the remainder of 2025 to sustain our assets and expand our business are as follows:


	Nine Months Ended September 30, 2025		2025 Remaining		Expected 2025
	(In millions)
Capital expenditures:
Sustaining capital expenditures	$	678	$	260	$	938
Expansion capital expenditures	1,460		722		2,182
Accrued capital expenditures, contractor retainage, and other	68		—		—
Capital expenditures	$	2,206	$	982	$	3,120
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)	$	131	$	53	$	184
Investments in unconsolidated joint ventures(b)	150		16		166
Less: Consolidated joint venture partners’ sustaining capital expenditures	(6)		(4)		(10)
Less: Consolidated joint venture partners’ expansion capital expenditures	(8)		—		(8)
Less: Insurance reimbursement related to a sustaining capital expenditure	(14)		—		(14)
Acquisition	648		—		648
Accrued capital expenditures, contractor retainage, and other	(68)		—		—
Total capital investments	$	3,039	$	1,047	$	4,086

(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.

Our capital investments consist of the following:


	Nine Months Ended September 30, 2025		2025 Remaining		Expected 2025
	(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment	$	678	$	260	$	938
Sustaining capital expenditures of unconsolidated joint ventures(a)	131		53		184
Less: Consolidated joint venture partners’ sustaining capital expenditures	(6)		(4)		(10)
Less: Insurance reimbursement related to a sustaining capital expenditure	(14)		—		(14)
Total sustaining capital investments	789		309		1,098
Expansion capital investments
Capital expenditures for property, plant and equipment	1,460		722		2,182
Investments in unconsolidated joint ventures(b)	150		16		166
Less: Consolidated joint venture partners’ expansion capital expenditures	(8)		—		(8)
Acquisition	648		—		648
Total expansion capital investments	2,250		738		2,988
Total capital investments	$	3,039	$	1,047	$	4,086

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

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2024 in our 2024 Form 10-K.

Commitments for the purchase of property, plant and equipment as of September 30, 2025 and December 31, 2024 were $1,173 million and $809 million, respectively. The increase of $364 million was primarily driven by an increase of capital commitments related to our Natural Gas Pipelines business segment.

Cash Flows

The following table summarizes our net cash flows provided by (used in) operating, investing, and financing activities between 2025 and 2024:


	Nine Months Ended September 30,
	2025		2024		Changes
	(In millions)
Net Cash Provided by (Used in)
Operating activities	$	4,225	$	4,125	$	100
Investing activities	(2,702)		(1,858)		(844)
Financing activities	(1,604)		(2,230)		626

Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Deposits	$	(81)	$	37	$	(118)

Operating Activities

Net cash provided by operating activities was higher for the comparable nine-month periods ended September 30, 2025 and 2024 driven by greater contributions from our Natural Gas Pipelines business segment.

Investing Activities

$844 million more cash used in investing activities in the comparable nine-month periods ended September 30, 2025 and 2024 is explained by the following discussion:

• $648 million in cash used for the Outrigger Energy acquisition in the 2025 period; and

• a $349 million increase in capital expenditures primarily driven by expansion projects in our Natural Gas Pipelines, CO 2 , and Products Pipelines business segments, partially offset by a decrease in our Terminals business segment; partially offset by

• a $152 million increase in distributions from equity investments primarily driven by our investment in SNG resulting from the receipt of our proportional share of debt refinancing.

Financing Activities

$626 million less cash used in financing activities in the comparable nine-month periods ended September 30, 2025 and 2024 primarily due to debt raised for our Outrigger Energy acquisition in 2025.

Dividends

We expect to declare dividends of $1.17 per share on our stock for 2025. The table below reflects our 2025 dividends declared:

Three months ended

Total quarterly dividend per share for the period

Date of declaration

Date of record

Date of dividend

March 31, 2025

0.2925

April 16, 2025

April 30, 2025

May 15, 2025

June 30, 2025

0.2925

July 16, 2025

July 31, 2025

August 15, 2025

September 30, 2025

0.2925

October 22, 2025

November 3, 2025

November 17, 2025

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—Risks Related to Ownership of Our Capital Stock—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 2024 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.

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 KMI and certain of its subsidiaries, with schedules updated as of September 30, 2025. ”

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

Excluding fair value adjustments, as of September 30, 2025 and December 31, 2024, the Obligated Group had $31,707 million and $31,052 million, respectively, of Guaranteed Notes outstanding.

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


Summarized Combined Balance Sheet Information	September 30, 2025		December 31, 2024
	(In millions)

Current assets	$	2,146	$	2,216
Current assets - affiliates	753		735
Noncurrent assets	64,353		63,267
Noncurrent assets - affiliates	781		813
Total Assets	$	68,033	$	67,031


Current liabilities	$	3,534	$	4,737
Current liabilities - affiliates	755		758
Noncurrent liabilities	36,034		34,052
Noncurrent liabilities - affiliates	1,760		1,561
Total Liabilities	42,083		41,108

Kinder Morgan, Inc.’s stockholders’ equity	25,950		25,923
Total Liabilities and Stockholders’ Equity	$	68,033	$	67,031


Summarized Combined Income Statement Information	Three Months Ended September 30, 2025		Nine Months Ended September 30, 2025
	(In millions)
Revenues	$	3,784	$	11,377
Operating income	923		2,955
Net income	505		1,708

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, 2024, in Part II, Item 7A in our 2024 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 September 30, 2025, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended September 30, 2025 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

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

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2024 Form 10-K and in Part II, Item 1A. “ Risk Factors ” of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2025.

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

None.

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 Act. 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 Act for the quarter ended September 30, 2025.

Item 5. Other Information.

During the quarter ending September 30, 2025, 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).

Item 6. Exhibits.


Exhibit Number						Description
3.1						Amended and Restated Certificate of Incorporation of KMI dated May 8, 2015 (filed as Exhibit 3.1 to KMI’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-35081)).

3.2						Certificate of Amendment to Amended and Restated Certificate of Incorporation of KMI dated May 10, 2023 (filed as Exhibit 3.1 to KMI’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 KMI and certain of its subsidiaries, with schedules updated as of September 30, 2025.

22.1						Subsidiary guarantors and issuers of guaranteed securities.

31.1						Certification of 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 of 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 of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

32.2						Certification of Chief Financial Officer 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 (formatted as Inline XBRL).

104						Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101).

SIGNATURE

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


			KINDER MORGAN, INC.
			Registrant

Date:

October 24, 2025

By:

/s/ David P. Michels

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

TABLE OF CONTENTS

Part I. Financial Information Item 1. Financial Statements Item 2. Management S Discussion and Analysis Of Financial Condition and Results Of Operations Item 3. Quantitative and Qualitative Disclosures About Market Risk Item 4. Controls and Procedures Part II. Other Information Item 1. Legal Proceedings Item 1A. Risk Factors Item 2. Unregistered Sales Of Equity Securities and Use Of Proceeds Item 3. Defaults Upon Senior Securities Item 4. Mine Safety Disclosures Item 5. Other Information Item 6. Exhibits

Exhibits

3.1 Amended and Restated Certificate of Incorporation of KMI dated May 8, 2015 (filed as Exhibit 3.1 to KMIs Quarterly Report on Form 10-Q for the quarter ended June 30, 2015 (File No. 001-35081)). 3.2 Certificate of Amendment to Amended and Restated Certificate of Incorporation of KMI dated May 10, 2023 (filed as Exhibit 3.1 to KMIs 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 KMI and certain of its subsidiaries, with schedules updated as of September 30, 2025. 22.1 Subsidiary guarantors and issuers of guaranteed securities. 31.1 Certification of 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 of 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 of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

Customer name	Ticker
American Axle & Manufacturing Holdings, Inc.	AXL
EQT Corporation	EQT
Exxon Mobil Corporation	XOM
Union Pacific Corporation	UNP
Valero Energy Corporation	VLO

KMI 10-Q Quarter ended Sept. 30, 2025

Exhibits