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 June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Revenues
Services	$	2,326	$	2,178	$	4,686	$	4,410
Commodity sales	1,668		1,346		3,504		2,866
Other	48		48		93		138
Total Revenues	4,042		3,572		8,283		7,414

Operating Costs, Expenses and Other
Costs of sales (exclusive of items shown separately below)	1,211		967		2,687		2,074
Operations and maintenance	773		741		1,484		1,421
Depreciation, depletion and amortization	616		584		1,226		1,171
General and administrative	188		179		375		354
Taxes, other than income taxes	111		109		223		220

Other income, net	(9)		(46)		(9)		(87)
Total Operating Costs, Expenses and Other	2,890		2,534		5,986		5,153

Operating Income	1,152		1,038		2,297		2,261

Other Income (Expense)
Earnings from equity investments	206		195		426		426


Interest, net	(452)		(464)		(903)		(936)
Other, net	13		1		28		1
Total Other Expense	(233)		(268)		(449)		(509)

Income Before Income Taxes	919		770		1,848		1,752

Income Tax Expense	(177)		(168)		(363)		(377)

Net Income	742		602		1,485		1,375






Net Income Attributable to Noncontrolling Interests	(27)		(27)		(53)		(54)

Net Income Attributable to Kinder Morgan, Inc.	$	715	$	575	$	1,432	$	1,321





Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.32	$	0.26	$	0.64	$	0.59

Basic and Diluted Weighted Average Shares Outstanding	2,222		2,219		2,222		2,219

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 June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Net income	$	742	$	602	$	1,485	$	1,375
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(40), $3, $(37) and $24, respectively)	130		(12)		123		(81)
Reclassification into earnings of net derivative instruments (gain) loss to net income (net of taxes of $15, $(8), $16 and $(7), respectively)	(44)		25		(49)		22

Benefit plan adjustments (net of taxes of $1, $—, $1 and $(4), respectively)	(1)		1		(3)		14
Total other comprehensive income (loss)	85		14		71		(45)

Comprehensive income	827		616		1,556		1,330
Comprehensive income attributable to noncontrolling interests	(27)		(27)		(53)		(54)
Comprehensive income attributable to KMI	$	800	$	589	$	1,503	$	1,276

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)


	June 30, 2025		December 31, 2024
ASSETS
Current Assets
Cash and cash equivalents	$	82	$	88
Restricted deposits	115		126
Accounts receivable	1,453		1,506

Inventories	560		555


Other current assets	276		246
Total current assets	2,486		2,521

Property, plant and equipment, net	38,818		38,013
Investments	7,854		7,845
Goodwill	20,084		20,084
Other intangibles, net	1,818		1,760


Deferred charges and other assets	1,311		1,184
Total Assets	$	72,371	$	71,407

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	788	$	2,009
Accounts payable	1,301		1,395

Accrued interest	530		543
Accrued taxes	212		276


Other current liabilities	802		878
Total current liabilities	3,633		5,101

Long-term liabilities and deferred credits
Long-term debt
Outstanding	31,688		29,779

Debt fair value adjustments	183		102
Total long-term debt	31,871		29,881
Deferred income taxes	2,417		2,070

Other long-term liabilities and deferred credits	2,369		2,488

Total long-term liabilities and deferred credits	36,657		34,439
Total Liabilities	40,290		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, 2,222,067,557 and 2,221,647,775 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	41,269		41,237
Accumulated deficit	(10,497)		(10,633)
Accumulated other comprehensive loss	(24)		(95)
Total Kinder Morgan, Inc.’s stockholders’ equity	30,770		30,531
Noncontrolling interests	1,311		1,336
Total Stockholders’ Equity	32,081		31,867
Total Liabilities and Stockholders’ Equity	$	72,371	$	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)

	Six Months Ended June 30,
	2025		2024
Cash Flows From Operating Activities
Net income	$	1,485	$	1,375
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	1,226		1,171
Deferred income taxes	327		357


Change in fair value of derivative contracts	(11)		52
Gain on divestitures, net	(2)		(77)

Earnings from equity investments	(426)		(426)
Distributions of equity investment earnings	397		416
Changes in components of working capital
Accounts receivable	67		267
Inventories	(2)		(7)
Other current assets	14		(10)
Accounts payable	(53)		(121)
Accrued interest, net of interest rate swaps	(18)		25
Accrued taxes	(60)		(48)
Other current liabilities	(30)		(78)


Other, net	(103)		(20)
Net Cash Provided by Operating Activities	2,811		2,876

Cash Flows From Investing Activities

Acquisition of assets (Note 2)	(648)		(58)
Capital expenditures	(1,413)		(1,200)

Contributions to investments	(69)		(44)
Distributions from equity investments in excess of cumulative earnings	92		81

Other, net	(1)		49
Net Cash Used in Investing Activities	(2,039)		(1,172)

Cash Flows From Financing Activities
Issuances of debt	6,523		5,943
Payments of debt	(5,910)		(6,239)
Debt issue costs	(16)		(19)
Dividends	(1,296)		(1,272)

Repurchases of shares	—		(7)





Distributions to noncontrolling interests	(78)		(81)
Other, net	(12)		(1)
Net Cash Used in Financing Activities	(789)		(1,676)


Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	(17)		28
Cash, Cash Equivalents and Restricted Deposits, beginning of period	214		96
Cash, Cash Equivalents and Restricted Deposits, end of period	$	197	$	124


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

	Six Months Ended June 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	82		98
Restricted Deposits, end of period	115		26
Cash, Cash Equivalents and Restricted Deposits, end of period	197		124

Net (decrease) increase in Cash, Cash Equivalents and Restricted Deposits	$	(17)	$	28

Non-cash Investing and Financing Activities

ROU assets and operating lease obligations recognized including adjustments	$	11	$	25


Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	926		914
Cash paid during the period for income taxes, net	38		11

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 March 31, 2025	2,222	$	22	$	41,250	$	(10,558)	$	(109)	$	30,605	$	1,321	$	31,926





Restricted shares				19						19				19
Net income						715				715		27		742
Dividends						(654)				(654)				(654)
Distributions										—		(37)		(37)



Other comprehensive income								85		85				85
Balance at June 30, 2025	2,222	$	22	$	41,269	$	(10,497)	$	(24)	$	30,770	$	1,311	$	32,081


	Common stock			Additional paid-in capital		Accumulated deficit		Accumulated other comprehensive loss		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at March 31, 2024	2,219	$	22	$	41,200	$	(10,574)	$	(276)	$	30,372	$	1,371	$	31,743



Restricted shares				18						18				18
Net income						575				575		27		602
Dividends						(641)				(641)				(641)
Distributions										—		(42)		(42)


Other comprehensive income								14		14				14
Balance at June 30, 2024	2,219	$	22	$	41,218	$	(10,640)	$	(262)	$	30,338	$	1,356	$	31,694


	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				32						32				32
Net income						1,432				1,432		53		1,485
Dividends						(1,296)				(1,296)				(1,296)
Distributions										—		(78)		(78)



Other comprehensive income								71		71				71
Balance at June 30, 2025	2,222	$	22	$	41,269	$	(10,497)	$	(24)	$	30,770	$	1,311	$	32,081


	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				35						35				35
Net income						1,321				1,321		54		1,375
Dividends						(1,272)				(1,272)				(1,272)
Distributions										—		(81)		(81)

Acquisition adjustment (Note 2)										—		(38)		(38)
Other										—		(2)		(2)
Other comprehensive loss								(45)		(45)				(45)
Balance at June 30, 2024	2,219	$	22	$	41,218	$	(10,640)	$	(262)	$	30,338	$	1,356	$	31,694

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 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 June 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

We calculate earnings per share using the two-class method. Earnings were allocated to Class P common stock and participating securities based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in undistributed earnings or excess distributions over earnings. Our unvested restricted stock awards, which may be restricted stock units or restricted stock issued to employees and non-employee directors and include dividend equivalent payments, do not participate in excess distributions over earnings.

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


	Three Months Ended June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	715	$	575	$	1,432	$	1,321
Participating securities:
Less: Net Income Allocated to Restricted Stock Awards(a)	(4)		(3)		(8)		(7)
Net Income Allocated to Common Stockholders	$	711	$	572	$	1,424	$	1,314

Basic Weighted Average Shares Outstanding	2,222		2,219		2,222		2,219
Basic Earnings Per Share	$	0.32	$	0.26	$	0.64	$	0.59

(a)As of June 30, 2025, there were approximately 13 million restricted stock awards outstanding.

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


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

2. Acquisitions and Divestiture

Acquisitions

As of June 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 six months ended June 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:


	June 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)	650		331
Current portion of senior notes
4.30% due June 2025	—		1,500
Trust I preferred securities, 4.75%, due March 2028(b)	111		111
Current portion of other debt	27		67
Total current portion of debt	788		2,009

Long-term debt (excluding current portion)
Senior notes	31,142		29,221
EPC Building, LLC, promissory note, 3.967%, due 2023 through 2035	279		289

Trust I preferred securities, 4.75%, due March 2028	110		110
Other	157		159
Total long-term debt	31,688		29,779
Total debt(c)	$	32,476	$	31,788

(a)Weighted average interest rate on borrowings at June 30, 2025 and December 31, 2024 was 4.65% 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 June 30, 2025 and December 31, 2024, increased our total debt balances by $183 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 June 30, 2025, we had no borrowings outstanding under our credit facility, $650 million borrowings outstanding under our commercial paper program and $11 million in letters of credit. Our availability under our credit facility as of June 30, 2025 was $2.8 billion. For the periods ended June 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:


	June 30, 2025				December 31, 2024
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	32,659	$	32,041	$	31,890	$	30,794

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $213 million and $201 million as of June 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 June 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 June 30,				Six Months Ended June 30,
	2025		2024		2025		2024
Per share cash dividend declared for the period	$	0.2925	$	0.2875	$	0.585	$	0.575
Per share cash dividend paid in the period	0.2925		0.2875		0.58		0.57

On July 16, 2025, our board of directors declared a cash dividend of $0.2925 per share for the quarterly period ended June 30, 2025, which is payable on August 15, 2025 to shareholders of record as of the close of business on July 31, 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	123		(3)		120
Gain reclassified from accumulated other comprehensive loss	(49)		—		(49)
Net current-period change in accumulated other comprehensive loss	74		(3)		71
Balance as of June 30, 2025	$	41	$	(65)	$	(24)


	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 (loss) gain before reclassifications	(81)		14		(67)
Loss reclassified from accumulated other comprehensive loss	22		—		22
Net current-period change in accumulated other comprehensive loss	(59)		14		(45)
Balance as of June 30, 2024	$	(103)	$	(159)	$	(262)

5. Risk Management

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

Energy Commodity Price Risk Management

As of June 30, 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	(16.5)	MMBbl

Natural gas fixed price	(55.4)	Bcf
Natural gas basis	(39.4)	Bcf

Derivatives not designated as hedging contracts
Crude oil fixed price	(1.4)	MMBbl
Crude oil basis	(1.5)	MMBbl
Natural gas fixed price	(10.9)	Bcf
Natural gas basis	(41.5)	Bcf
NGL fixed price	(1.6)	MMBbl

As of June 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 June 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	March 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 June 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
		June 30, 2025		December 31, 2024		June 30, 2025		December 31, 2024
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	$	49	$	10	$	(16)	$	(46)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	28		9		(1)		(8)
	Subtotal	77		19		(17)		(54)
Interest rate contracts
	Other current assets/(Other current liabilities)	2		1		(35)		(51)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	39		19		(117)		(203)
	Subtotal	41		20		(152)		(254)
Foreign currency contracts
	Other current assets/(Other current liabilities)	—		—		(8)		(3)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	50		—		—		(26)
	Subtotal	50		—		(8)		(29)
	Total	168		39		(177)		(337)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	16		14		(38)		(35)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	4		1		(7)		(15)
	Subtotal	20		15		(45)		(50)
Interest rate contracts
	Other current assets/(Other current liabilities)	3		4		—		—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		4		—		(2)
	Subtotal	3		8		—		(2)
	Total	23		23		(45)		(52)
	Total derivatives	$	191	$	62	$	(222)	$	(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 June 30, 2025
Energy commodity derivative contracts(b)	$	15	$	82	$	—	$	97	$	(24)	$	—	$	73
Interest rate contracts	—		44		—		44		(8)		—		36
Foreign currency contracts	—		50		—		50		—		—		50
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 June 30, 2025
Energy commodity derivative contracts(b)	$	(14)	$	(48)	$	—	$	(62)	$	24	$	24	$	(14)
Interest rate contracts	—		(152)		—		(152)		8		—		(144)
Foreign currency contracts	—		(8)		—		(8)		—		—		(8)
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 June 30,				Six Months Ended June 30,
		2025		2024		2025		2024
		(In millions)
Interest rate contracts	Interest, net	$	41	$	1	$	121	$	(55)

Hedged fixed rate debt(a)	Interest, net	$	(41)	$	—	$	(120)	$	57

(a)As of June 30, 2025, the cumulative amount of fair value hedging adjustments resulted in a decrease of $121 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 June 30,					Three Months Ended June 30,
	2025		2024			2025		2024
	(In millions)					(In millions)
Energy commodity derivative contracts	$	120	$	(12)	Revenues—Commodity sales	$	10	$	(27)

					Costs of sales	—		(2)


Foreign currency contracts	50		(3)		Other, net	49		(4)
Total	$	170	$	(15)	Total	$	59	$	(33)


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivative(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income
	Six Months Ended June 30,					Six Months Ended June 30,
	2025		2024			2025		2024
	(In millions)					(In millions)
Energy commodity derivative contracts	$	90	$	(105)	Revenues—Commodity sales	$	(6)	$	(7)

					Costs of sales	(1)		(9)
Interest rate contracts	—		13		Interest, net	—		4

Foreign currency contracts	70		(13)		Other, net	72		(17)
Total	$	160	$	(105)	Total	$	65	$	(29)

(a)We expect to reclassify approximately $37 million of gains associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 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 June 30,				Six Months Ended June 30,
		2025		2024		2025		2024
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	13	$	2	$	16	$	(9)
	Costs of sales	63		(18)		(20)		(32)
	Earnings from equity investments	2		—		—		—
Interest rate contracts	Interest, net	—		—		(2)		(2)
Total(a)		$	78	$	(16)	$	(6)	$	(43)

(a)The three and six months ended June 30, 2025 amounts include approximate losses of $15 million and $16 million, respectively, and the three and six months ended June 30, 2024 amounts include approximate losses of $14 million and approximate gains of $10 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 June 30, 2025 and December 31, 2024, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2025 and December 31, 2024, we had cash margins of $94 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 June 30, 2025 represents the initial margin requirements of $70 million, and variation margin requirements of $24 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 June 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 June 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)	$	1,018	$	47	$	228	$	1	$	(1)	$	1,293
Fee-based services	281		278		99		10		(2)		666
Total services	1,299		325		327		11		(3)		1,959
Commodity sales
Natural gas sales	870		—		—		11		(2)		879
Product sales	211		305		16		210		(2)		740
Other sales	7		—		—		22		(1)		28
Total commodity sales	1,088		305		16		243		(5)		1,647
Total revenues from contracts with customers	2,387		630		343		254		(8)		3,606
Other revenues(c)
Leasing services(d)	113		55		190		18		—		376
Derivatives adjustments on commodity sales	9		—		—		14		—		23
Other	27		6		—		4		—		37
Total other revenues	149		61		190		36		—		436
Total revenues	$	2,536	$	691	$	533	$	290	$	(8)	$	4,042


	Three Months Ended June 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)	$	920	$	49	$	215	$	—	$	(1)	$	1,183
Fee-based services	257		276		115		10		(1)		657
Total services	1,177		325		330		10		(2)		1,840
Commodity sales
Natural gas sales	455		—		—		10		(1)		464
Product sales	211		392		15		266		(1)		883
Other sales	6		—		—		20		—		26
Total commodity sales	672		392		15		296		(2)		1,373
Total revenues from contracts with customers	1,849		717		345		306		(4)		3,213
Other revenues(c)
Leasing services(d)	114		53		164		17		—		348
Derivatives adjustments on commodity sales	5		—		—		(30)		—		(25)
Other	25		6		—		5		—		36
Total other revenues	144		59		164		(8)		—		359
Total revenues	$	1,993	$	776	$	509	$	298	$	(4)	$	3,572


	Six Months Ended June 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)	$	2,091	$	100	$	445	$	1	$	(2)	$	2,635
Fee-based services	582		535		200		20		(3)		1,334
Total services	2,673		635		645		21		(5)		3,969
Commodity sales
Natural gas sales	1,850		—		—		27		(4)		1,873
Product sales	473		606		32		453		(4)		1,560
Other sales	14		—		—		53		(1)		66
Total commodity sales	2,337		606		32		533		(9)		3,499
Total revenues from contracts with customers	5,010		1,241		677		554		(14)		7,468
Other revenues(c)
Leasing services(d)	225		100		374		35		—		734
Derivatives adjustments on commodity sales	6		—		—		4		—		10
Other	49		13		—		9		—		71
Total other revenues	280		113		374		48		—		815
Total revenues	$	5,290	$	1,354	$	1,051	$	602	$	(14)	$	8,283


	Six Months Ended June 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)	$	1,912	$	107	$	427	$	—	$	(2)	$	2,444
Fee-based services	528		524		224		22		(2)		1,296
Total services	2,440		631		651		22		(4)		3,740
Commodity sales
Natural gas sales	1,073		—		—		22		(3)		1,092
Product sales	434		756		28		533		(2)		1,749
Other sales	12		—		—		31		(1)		42
Total commodity sales	1,519		756		28		586		(6)		2,883
Total revenues from contracts with customers	3,959		1,387		679		608		(10)		6,623
Other revenues(c)
Leasing services(d)	229		106		326		29		—		690
Derivatives adjustments on commodity sales	47		(1)		—		(62)		—		(16)
Other	94		12		—		11		—		117
Total other revenues	370		117		326		(22)		—		791
Total revenues	$	4,329	$	1,504	$	1,005	$	586	$	(10)	$	7,414

(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 June 30, 2025 and December 31, 2024, our contract asset balances were $26 million and $15 million, respectively. Of the contract asset balance at December 31, 2024, $7 million was transferred to accounts receivable during the six months ended June 30, 2025. As of June 30, 2025 and December 31, 2024, our contract liability balances were $432 million and $377 million, respectively. Of the contract liability balance at December 31, 2024, $52 million was recognized as revenue during the six months ended June 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 $559 million and $587 million as of June 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 June 30, 2025 that we will invoice or transfer from contract liabilities and recognize in future periods:


Year	Estimated Revenue
	(In millions)
Six months ended December 31, 2025	$	2,678
2026	4,872
2027	4,022
2028	3,467
2029	3,056
Thereafter	18,051
Total	$	36,146

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 six months ended June 30, 2025 and 2024, and therefore is included within Segment EBDA. As a result, Segment EBDA for the three and six months ended June 30, 2024 has been adjusted to conform to the current presentation in the tables below.

Financial information by segment follows:


	Three Months Ended June 30, 2025
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	2,531	$	691	$	531	$	289	$	—	$	4,042
Intersegment revenues	5		—		2		1		(8)		—
Total revenues	2,536		691		533		290		(8)		4,042
Costs of sales	(890)		(292)		(14)		(21)
Labor	(84)		(33)		(69)		(14)
Fuel and power	(20)		(22)		(5)		(34)
Field - non-labor(a)	(231)		(60)		(136)		(64)

Taxes, other than income taxes	(73)		(11)		(14)		(12)
Earnings from equity investments	185		15		2		4
Other segment items(b)	13		1		3		1

Total Segment EBDA(c)	$	1,436	$	289	$	300	$	150			2,175
DD&A											(616)

General and administrative and corporate charges											(188)
Interest, net											(452)
Income tax expense											(177)
Net income											$	742

Other segment activity information:
DD&A	$	294	$	97	$	129	$	88	$	8	$	616
Capital expenditures	409		58		77		88		15		647


	Three Months Ended June 30, 2024
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	1,990	$	776	$	508	$	298	$	—	$	3,572
Intersegment revenues	3		—		1		—		(4)		—
Total revenues	1,993		776		509		298		(4)		3,572
Costs of sales	(567)		(373)		(12)		(19)
Labor	(80)		(32)		(68)		(13)
Fuel and power	(19)		(22)		(5)		(32)
Field - non-labor(a)	(213)		(52)		(139)		(62)

Taxes, other than income taxes	(69)		(11)		(14)		(14)
Earnings from equity investments	175		12		2		6
Other segment items(b)	(1)		—		8		40

Total Segment EBDA(d)(e)	$	1,219	$	298	$	281	$	204			2,002
DD&A											(584)

General and administrative and corporate charges											(184)
Interest, net											(464)
Income tax expense											(168)
Net income											$	602

Other segment activity information:
DD&A	$	275	$	90	$	125	$	89	$	5	$	584
Capital expenditures	350		51		104		66		10		581


	Six Months Ended June 30, 2025
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	5,281	$	1,354	$	1,047	$	601	$	—	$	8,283
Intersegment revenues	9		—		4		1		(14)		—
Total revenues	5,290		1,354		1,051		602		(14)		8,283
Costs of sales	(2,035)		(585)		(29)		(48)
Labor	(164)		(65)		(139)		(26)
Fuel and power	(39)		(43)		(11)		(66)
Field - non-labor(a)	(422)		(108)		(276)		(117)

Taxes, other than income taxes	(145)		(23)		(27)		(25)
Earnings from equity investments	381		31		4		10
Other segment items(b)	23		1		2		1

Total Segment EBDA(c)	$	2,889	$	562	$	575	$	331			4,357
DD&A											(1,226)

General and administrative and corporate charges											(380)
Interest, net											(903)
Income tax expense											(363)
Net income											$	1,485

Other segment activity information:
DD&A	$	581	$	193	$	258	$	181	$	13	$	1,226
Capital expenditures	902		139		153		185		34		1,413


	Six Months Ended June 30, 2024
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	4,323	$	1,504	$	1,002	$	585	$	—	$	7,414
Intersegment revenues	6		—		3		1		(10)		—
Total revenues	4,329		1,504		1,005		586		(10)		7,414
Costs of sales	(1,298)		(722)		(22)		(40)
Labor	(158)		(63)		(135)		(26)
Fuel and power	(39)		(42)		(10)		(67)
Field - non-labor(a)	(390)		(94)		(274)		(119)

Taxes, other than income taxes	(138)		(22)		(28)		(28)
Earnings from equity investments	382		27		4		13
Other segment items(b)	37		—		10		41

Total Segment EBDA(d)(e)	$	2,725	$	588	$	550	$	360			4,223
DD&A											(1,171)

General and administrative and corporate charges											(364)
Interest, net											(936)
Income tax expense											(377)
Net income											$	1,375

Other segment activity information:
DD&A	$	550	$	179	$	252	$	178	$	12	$	1,171
Capital expenditures	711		101		210		145		33		1,200


	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Segment balance sheet information:
As of June 30, 2025
Investments	$	7,258	$	394	$	132	$	70	$	—	$	7,854
Other intangibles, net	816		552		14		436		—		1,818
Total assets(f)	51,463		8,549		7,974		3,636		749		72,371
As of December 31, 2024
Investments	$	7,252	$	387	$	132	$	74	$	—	$	7,845
Other intangibles, net	687		597		18		458		—		1,760
Total assets(f)	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 six months ended June 30, 2025 of $89 million and $9 million, none and $(1) million and $5 million and $4 million, respectively, for our Natural Gas Pipelines, Products Pipelines and CO2 business segments, respectively.

(d)Includes non-cash mark-to-market derivative hedge contract gain (loss) amounts for the three and six months ended June 30, 2024 of $(4) million and $(43) million, none and $(1) million, and $1 million and $(7) million, respectively, for our Natural Gas Pipelines, Products Pipelines and CO2 business segments, respectively.

(e)Segment EBDA previously reported (before reclassifications) for the three and six months ended June 30, 2024 was $1,227 million and $2,741 million, $301 million and $593 million, $281 million and $550 million, and $206 million and $364 million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, and CO2 business segments, respectively.

(f)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.

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

8. Income Taxes

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


	Three Months Ended June 30,						Six Months Ended June 30,
	2025			2024			2025			2024
	(In millions, except percentages)
Income tax expense	$	177		$	168		$	363		$	377
Effective tax rate	19.3		%	21.8		%	19.6		%	21.5		%

The effective tax rate for the three months ended June 30, 2025 is lower than the statutory federal rate of 21% primarily due to (i) an adjustment to our deferred tax liability as a result of modified income allocations; and (ii) dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings LLC and Products (SE) Pipe Line Company (PPL), partially offset by state income taxes.

The effective tax rate for the six months ended June 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 ended June 30, 2024 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 Citrus, NGPL Holdings LLC and PPL.

The effective tax rate for the six months ended June 30, 2024 is higher than the statutory federal rate of 21% primarily due to state income taxes, partially offset by (i) dividend-received deductions from our investments in Citrus, NGPL Holdings LLC and PPL; and (ii) an adjustment to our deferred tax liability as a result of a reduction in the state tax rate.

Subsequent Event

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. However, because our tax provision is based on both current and deferred tax, we believe the impact to our income statement will be immaterial.

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 January 16, 2025, Eni S.p.A. filed a motion for leave to appeal to the Court of Appeals which we opposed and remains pending.

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. On June 3, 2025, the Court established a briefing schedule through September 2025 to address potential remedies for Claims III, IV and V. We anticipate plaintiffs will seek equitable and other relief including early retirement benefits, monetary damages or other equitable relief in excess of $100 million. We intend to vigorously oppose the form and scope of relief sought by the plaintiffs. We 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 intends to seek to be dismissed from this suit on the same basis through subsequent motion practice. We intend to vigorously defend this case.

General

As of June 30, 2025 and December 31, 2024, we had liabilities of $185 million and $188 million, respectively, recorded for environmental matters. In addition, as of both June 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 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. This ASU is effective for annual periods beginning after December 15, 2024, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s annual disclosures.

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.

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