Item 1. Financial Statements.

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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, CO2, renewable fuels, and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.

Basis of Presentation

General

Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 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) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates, which include assumptions primarily involving management’s judgments and estimates. For all reporting units other than the Energy Transition Ventures reporting unit within our CO2 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 CO2 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 CO2 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		CO2		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		CO2		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		CO2		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		CO2		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		CO2		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		CO2		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		CO2		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		CO2		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		CO2		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 CO2 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 CO2 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 CO2 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 14th 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, CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations. 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 CO2, including natural resource damage (NRD) claims.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are

participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT 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.

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