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,
	2026		2025		2026		2025
Revenues
Services	$	2,456	$	2,326	$	4,981	$	4,686
Commodity sales	1,978		1,668		4,223		3,504
Other	43		48		101		93
Total Revenues	4,477		4,042		9,305		8,283

Operating Costs, Expenses, and Other
Costs of sales (exclusive of items shown separately below)	1,405		1,211		3,154		2,687
Operations and maintenance	806		773		1,517		1,484
Depreciation, depletion, and amortization	620		616		1,253		1,226
General and administrative	192		188		376		375
Taxes, other than income taxes	120		111		234		223

Other income, net	(12)		(9)		(19)		(9)
Total Operating Costs, Expenses, and Other	3,131		2,890		6,515		5,986

Operating Income	1,346		1,152		2,790		2,297

Other Income (Expense)
Earnings from equity investments	225		206		479		426


Interest, net	(425)		(452)		(855)		(903)
Other, net	20		13		40		28
Total Other Expense	(180)		(233)		(336)		(449)

Income Before Income Taxes	1,166		919		2,454		1,848

Income Tax Expense	(272)		(177)		(559)		(363)

Net Income	894		742		1,895		1,485






Net Income Attributable to Noncontrolling Interests	(27)		(27)		(52)		(53)

Net Income Attributable to Kinder Morgan, Inc.	$	867	$	715	$	1,843	$	1,432





Class P Common Stock
Basic and Diluted Earnings Per Share	$	0.39	$	0.32	$	0.82	$	0.64

Basic and Diluted Weighted Average Shares Outstanding	2,225		2,222		2,225		2,222

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,
	2026		2025		2026		2025
Net income	$	894	$	742	$	1,895	$	1,485
Other comprehensive income (loss), net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(10), $(40), $46, and $(37), respectively)	39		130		(160)		123
Reclassification into earnings of net derivative instruments loss (gain) to net income (net of taxes of $(15), $15, $(21), and $16, respectively)	51		(44)		71		(49)

Benefit plan adjustments (net of taxes of $1, $1, $2, and $1, respectively)	(3)		(1)		(6)		(3)
Total other comprehensive income (loss)	87		85		(95)		71

Comprehensive income	981		827		1,800		1,556
Comprehensive income attributable to noncontrolling interests	(27)		(27)		(52)		(53)
Comprehensive income attributable to KMI	$	954	$	800	$	1,748	$	1,503

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, 2026		December 31, 2025
ASSETS
Current Assets
Cash and cash equivalents	$	89	$	63
Restricted deposits	30		46
Accounts receivable	1,563		1,714

Inventories	565		574


Other current assets	341		357
Total current assets	2,588		2,754

Property, plant, and equipment, net	40,522		39,331
Investments	7,705		7,532
Goodwill	20,084		20,084
Other intangibles, net	1,872		1,730


Deferred charges and other assets	1,291		1,317
Total Assets	$	74,062	$	72,748

LIABILITIES AND STOCKHOLDERS’ EQUITY
Current Liabilities
Current portion of debt	$	2,443	$	1,226
Accounts payable	1,567		1,408

Accrued interest	514		534
Accrued taxes	216		256


Other current liabilities	907		898
Total current liabilities	5,647		4,322

Long-term liabilities and deferred credits
Long-term debt
Outstanding	29,701		30,597

Debt fair value adjustments	104		180
Total long-term debt	29,805		30,777
Deferred income taxes	3,439		2,891

Other long-term liabilities and deferred credits	2,292		2,309

Total long-term liabilities and deferred credits	35,536		35,977
Total Liabilities	41,183		40,299
Commitments and contingencies (Notes 3 and 9)
Stockholders’ Equity

Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,224,819,927 and 2,224,777,750 shares, respectively, issued and outstanding	22		22
Additional paid-in capital	41,316		41,276
Accumulated deficit	(9,657)		(10,181)
Accumulated other comprehensive (loss)/income	(50)		45
Total Kinder Morgan, Inc.’s stockholders’ equity	31,631		31,162
Noncontrolling interests	1,248		1,287
Total Stockholders’ Equity	32,879		32,449
Total Liabilities and Stockholders’ Equity	$	74,062	$	72,748

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,
	2026		2025
Cash Flows From Operating Activities
Net income	$	1,895	$	1,485
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion, and amortization	1,253		1,226
Deferred income taxes	576		327
Change in fair value of derivative contracts	13		(11)


Earnings from equity investments	(479)		(426)
Distributions of equity investment earnings	363		397
Changes in components of working capital
Accounts receivable	157		67
Inventories	12		(2)
Other current assets	(34)		14
Accounts payable	(85)		(53)
Accrued interest, net of interest rate swaps	(18)		(18)
Accrued taxes	(40)		(60)
Other current liabilities	2		(30)


Other, net	(164)		(105)
Net Cash Provided by Operating Activities	3,451		2,811

Cash Flows From Investing Activities
Acquisition of assets, net of cash acquired (Note 2)	(503)		(648)
Capital expenditures	(1,786)		(1,413)

Contributions to investments	(142)		(69)
Distributions from equity investments in excess of cumulative earnings	96		92
Other, net	(20)		(1)
Net Cash Used in Investing Activities	(2,355)		(2,039)

Cash Flows From Financing Activities
Issuances of debt	4,026		6,523
Payments of debt	(3,715)		(5,910)
Debt issue costs	(10)		(16)
Dividends	(1,319)		(1,296)



Distributions to noncontrolling interests	(77)		(78)
Other, net	9		(12)
Net Cash Used in Financing Activities	(1,086)		(789)


Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Deposits	10		(17)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	109		214
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	119	$	197


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

	Six Months Ended June 30,
	2026		2025
Non-cash Investing and Financing Activities
ROU assets and operating lease obligations recognized including adjustments	$	45	$	11

Net increase in property, plant, and equipment from both accruals and contractor retainage	242
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	879		926
Cash (refund) paid during the period for income taxes, net	(11)		38

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, 2026	2,225	$	22	$	41,296	$	(9,859)	$	(137)	$	31,322	$	1,261	$	32,583





Stock awards				20						20				20
Net income						867				867		27		894
Dividends						(665)				(665)				(665)
Distributions										—		(40)		(40)



Other comprehensive income								87		87				87
Balance at June 30, 2026	2,225	$	22	$	41,316	$	(9,657)	$	(50)	$	31,631	$	1,248	$	32,879


	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



Stock awards				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 income/(loss)		Stockholders’ equity attributable to KMI		Non- controlling interests		Total
	Issued shares	Par value
Balance at December 31, 2025	2,225	$	22	$	41,276	$	(10,181)	$	45	$	31,162	$	1,287	$	32,449





Stock awards				40						40				40
Net income						1,843				1,843		52		1,895
Dividends						(1,319)				(1,319)				(1,319)
Distributions										—		(77)		(77)


Other										—		(14)		(14)
Other comprehensive loss								(95)		(95)				(95)
Balance at June 30, 2026	2,225	$	22	$	41,316	$	(9,657)	$	(50)	$	31,631	$	1,248	$	32,879


	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





Stock awards				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

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 78,000 miles of pipelines, 136 terminals, over 700 Bcf of working natural gas storage capacity, and 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 2025 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, 2026 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 (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 the Energy Transition Ventures reporting unit, which had a goodwill balance of $114 million as of June 30, 2026, 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, 2026 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value (by at least 10%). We did not identify any triggers requiring further impairment analysis subsequent to our annual goodwill impairment test. Changes to any one or a combination of the factors described 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 June 30,				Six Months Ended June 30,
	2026		2025		2026		2025
	(In millions, except per share amounts)
Net Income Available to Stockholders	$	867	$	715	$	1,843	$	1,432
Less: Net Income Allocated to Participating Securities(a)	(4)		(4)		(10)		(8)
Net Income Allocated to Common Stockholders	$	863	$	711	$	1,833	$	1,424

Basic and Diluted Weighted Average Shares Outstanding	2,225		2,222		2,225		2,222
Basic and Diluted EPS	$	0.39	$	0.32	$	0.82	$	0.64

(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.

Our potential common stock equivalents, consisting of outstanding unvested stock awards and convertible trust preferred securities, were excluded from the diluted EPS calculation for all periods presented above, as their inclusion would have been antidilutive.

2. Acquisitions

As of June 30, 2026, our allocations of purchase price by acquisition are detailed below:


					Assignment of Purchase Price
Ref	Date	Acquisition	Purchase price		Current assets		Property, plant, & equipment		Other long-term assets		Current liabilities		Long-term liabilities		Resulting goodwill
			(In millions)
(1)	5/26	Monument Pipeline	$	503	$	10	$	264	$	236	$	(7)	$	—	$	—
(2)	2/25	Outrigger Energy	648		16		497		160		(5)		(20)		—

(1) Monument Pipeline System Acquisition

On May 1, 2026, we completed the acquisition of the Monument Pipeline natural gas pipeline system serving Houston, Texas and the surrounding metropolitan area from ARM Energy Holdings, for a purchase price of $503 million, including purchase price adjustments for working capital. Other long-term assets within the preliminary purchase price allocation consists of customer relationships intangibles with a weighted average amortization period of approximately 14 years. The acquisition includes approximately 225 miles of pipelines and provides transportation and storage services to gas utilities, LNG shippers, and industrial customers. The acquired assets are included in our Natural Gas Pipelines business segment.

(2) 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.

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.

3. Debt

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


	June 30, 2026		December 31, 2025
	(In millions, unless otherwise stated)
Current portion of debt
$3.5 billion credit facility due May 21, 2031	$	—	$	—
Commercial paper notes(a)	338		13
Current portion of senior notes
4.15%, due August 2026	375		375
1.75%, due November 2026	500		500
7.50%, due November 2026	200		200
6.70%, due February 2027	7		—
2.25%, due March 2027(b)	571		—
7.00%, due March 2027	300		—
Trust I preferred securities, 4.75%, due March 2028(c)	111		111
Current portion of other debt	41		27
Total current portion of debt	2,443		1,226

Long-term debt (excluding current portion)
Senior notes	29,171		30,065
EPC Building, LLC, promissory note, 3.967%, due 2026 through 2035	257		268

Trust I preferred securities, 4.75%, due March 2028	109		110
Other	164		154
Total long-term debt	29,701		30,597
Total debt(d)	$	32,144	$	31,823

(a)Weighted average interest rate on borrowings at June 30, 2026 and December 31, 2025 was 3.92% and 3.85%, respectively.

(b)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the June 30, 2026 exchange rate of $1.1422 U.S. dollars per Euro and at the December 31, 2025 exchange rate of $1.1746 U.S. dollars per Euro. As of June 30, 2026 and December 31, 2025, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $28 million and $44 million, respectively. As of June 30, 2026, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.

(c)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.

(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2026 and December 31, 2025, increased our total debt balances by $104 million and $180 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. In addition, substantially all of our wholly owned domestic subsidiaries guarantee our obligations under our credit facility pursuant to a guarantee agreement executed in connection with our credit facility.

Credit Facilities and Restrictive Covenants

On May 21, 2026, we, as borrower, entered into an Amended and Restated Revolving Credit Agreement (the “Amended Credit Facility”) with Barclays Bank PLC, as administrative agent (“Barclays”), and the lenders listed on the signature pages to such Amended Credit Facility, which amended and restated the Company’s $3.5 billion Revolving Credit Agreement dated August 20, 2021 (as previously amended, the “Existing Credit Facility”).

The Amended Credit Facility amended certain provisions of the Existing Credit Facility to, among other things, (i) extend the stated maturity date from August 20, 2026 to May 21, 2031, and (ii) increase the amount of the facility available for swingline loans from $50 million to $400 million. Substantially all of our wholly owned domestic subsidiaries guarantee our obligations under the Amended Credit Facility pursuant to a guaranty agreement.

Depending on the type of loan request, our borrowings under our Amended Credit Facility bear interest at either (i) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) the Term SOFR for a one-month period plus 1% or (ii) Term SOFR or (iii) Daily Simple SOFR, plus, in each case, an applicable margin ranging from 0.000% to 1.500% per

annum based on our credit rating. Standby fees for the unused portion of the credit facility will be calculated at a rate ranging from 0.075% to 0.200%.

The Amended Credit Facility contains financial and various other covenants that apply to us and our subsidiaries and are common in such agreements, including a maximum ratio of Consolidated Net Indebtedness to Consolidated EBITDA (as defined in the Amended Credit Facility, as amended) of 5.50 to 1.00, for any four-fiscal-quarter period. Other negative covenants include restrictions on our and certain of our subsidiaries’ ability to incur debt, grant liens, make fundamental changes, or engage in certain transactions with affiliates, or in the case of certain material subsidiaries, permit restrictions on dividends, distributions, or making or prepayments of loans to us or any guarantor. The Amended Credit Facility also restricts our ability to make certain restricted payments if an event of default (as defined in the Amended Credit Facility) has occurred and is continuing or would occur and be continuing.

As of June 30, 2026, we had no borrowings outstanding under our credit facility, $338 million borrowings outstanding under our commercial paper program, and $10 million in letters of credit. Our availability under our credit facility as of June 30, 2026 was approximately $3.2 billion. For the periods ended June 30, 2026 and 2025, 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, 2026				December 31, 2025
	Carrying value		Estimated fair value(a)		Carrying value		Estimated fair value(a)
	(In millions)
Total debt	$	32,248	$	31,978	$	32,003	$	31,966

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $217 million as of both June 30, 2026 and December 31, 2025.

We used Level 2 input values to measure the estimated fair value of our outstanding debt balance as of both June 30, 2026 and December 31, 2025.

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,
	2026		2025		2026		2025
Per share cash dividend declared for the period	$	0.2975	$	0.2925	$	0.595	$	0.585
Per share cash dividend paid in the period	0.2975		0.2925		0.590		0.580

On July 22, 2026, our board of directors declared a cash dividend of $0.2975 per share for the quarterly period ended June 30, 2026, which is payable on August 17, 2026 to shareholders of record as of the close of business on August 3, 2026.

Accumulated Other Comprehensive Income (Loss*)*

Changes in the components of our “Accumulated other comprehensive income (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 income (loss)
	(In millions)
Balance as of December 31, 2025	$	67	$	(22)	$	45
Other comprehensive loss before reclassifications	(160)		(6)		(166)
Loss reclassified from accumulated other comprehensive loss	71		—		71
Net current-period change in accumulated other comprehensive loss	(89)		(6)		(95)
Balance as of June 30, 2026	$	(22)	$	(28)	$	(50)


	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)

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, 2026, 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	(15.0)	MMBbl




Derivatives not designated as hedging contracts
Crude oil fixed price	(0.9)	MMBbl
Crude oil basis	(2.6)	MMBbl
Natural gas fixed price	(48.1)	Bcf
Natural gas basis	(134.7)	Bcf
NGL fixed price	(1.5)	MMBbl

As of June 30, 2026, 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, 2026:


	Notional amount		Accounting treatment	Maximum term
	(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)	$	4,250	Fair value hedge	February 2041

(a)The principal amount of hedged senior notes is 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, 2026:


	Notional amount		Accounting treatment	Maturity
	(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 which matures in March 2027.

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, 2026		December 31, 2025		June 30, 2026		December 31, 2025
		(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	$	3	$	56	$	(30)	$	—
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	12		36		(9)		—
	Subtotal	15		92		(39)		—
Interest rate contracts
	Other current assets/(Other current liabilities)	2		4		(32)		(25)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	22		32		(145)		(111)
	Subtotal	24		36		(177)		(136)
Foreign currency contracts
	Other current assets/(Other current liabilities)	25		—		—		(2)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	—		41		—		—
	Subtotal	25		41		—		(2)
	Total	64		169		(216)		(138)

Derivatives not designated as hedging instruments
Energy commodity derivative contracts
	Other current assets/(Other current liabilities)	57		75		(33)		(74)
	Deferred charges and other assets/(Other long-term liabilities and deferred credits)	3		4		(35)		(1)





	Total	60		79		(68)		(75)
	Total derivatives	$	124	$	248	$	(284)	$	(213)

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, 2026
Energy commodity derivative contracts(b)	$	35	$	40	$	—	$	75	$	(66)	$	—	$	9
Interest rate contracts	—		24		—		24		(5)		—		19
Foreign currency contracts	—		25		—		25		—		—		25
As of December 31, 2025
Energy commodity derivative contracts(b)	$	20	$	151	$	—	$	171	$	(68)	$	—	$	103
Interest rate contracts	—		36		—		36		(6)		—		30
Foreign currency contracts	—		41		—		41		—		—		41


	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, 2026
Energy commodity derivative contracts(b)	$	(4)	$	(103)	$	—	$	(107)	$	66	$	9	$	(32)
Interest rate contracts	—		(177)		—		(177)		5		—		(172)

As of December 31, 2025
Energy commodity derivative contracts(b)	$	(12)	$	(63)	$	—	$	(75)	$	68	$	(2)	$	(9)
Interest rate contracts	—		(136)		—		(136)		6		—		(130)
Foreign currency contracts	—		(2)		—		(2)		—		—		(2)

(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 derivatives and related hedged item
		Three Months Ended June 30,				Six Months Ended June 30,
		2026		2025		2026		2025
		(In millions)
Interest rate contracts	Interest, net	$	(34)	$	41	$	(51)	$	121

Hedged fixed rate debt(a)	Interest, net	$	35	$	(41)	$	51	$	(120)

(a)As of June 30, 2026, the cumulative amount of fair value hedging adjustments resulted in a decrease of $152 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 derivatives(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income
	Three Months Ended June 30,					Three Months Ended June 30,
	2026		2025			2026		2025
	(In millions)					(In millions)
Energy commodity derivative contracts	$	53	$	120	Revenues—Commodity sales	$	(60)	$	10




Foreign currency contracts	(4)		50		Other, net	(6)		49
Total	$	49	$	170	Total	$	(66)	$	59


Derivatives in cash flow hedging relationships	Gain/(loss) recognized in OCI on derivatives(a)				Location	Gain/(loss) reclassified from Accumulated OCI into income
	Six Months Ended June 30,					Six Months Ended June 30,
	2026		2025			2026		2025
	(In millions)					(In millions)
Energy commodity derivative contracts	$	(193)	$	90	Revenues—Commodity sales	$	(76)	$	(6)

					Costs of sales	—		(1)


Foreign currency contracts	(13)		70		Other, net	(16)		72
Total	$	(206)	$	160	Total	$	(92)	$	65

(a)We expect to reclassify an approximate $6 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2026 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,
		2026		2025		2026		2025
		(In millions)
Energy commodity derivative contracts	Revenues—Commodity sales	$	34	$	13	$	23	$	16
	Costs of sales	(19)		63		(124)		(20)
	Earnings from equity investments	—		2		1		—
Interest rate contracts	Interest, net	—		—		—		(2)
Total(a)		$	15	$	78	$	(100)	$	(6)

(a)The amounts for the three and six months ended June 30, 2026 include approximate losses of $58 million and $89 million, respectively, and the amounts for the three and six months ended June 30, 2025 include approximate losses of $15 million and $16 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, 2026 and December 31, 2025, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2026 and December 31, 2025, we had cash margins of $20 million and $24 million, respectively, posted with our counterparties by us and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The cash margin balance at June 30, 2026 represents the initial margin requirements of $12 million and variation margin requirements of $8 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, 2026, 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, 2026
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services	$	1,078	$	63	$	224	$	1	$	(1)	$	1,365
Fee-based services	343		272		108		11		(2)		732
Total services	1,421		335		332		12		(3)		2,097
Commodity sales
Natural gas sales	799		—		—		8		(1)		806
Product sales	287		517		28		336		(6)		1,162
Other sales	1		—		—		31		1		33
Total commodity sales	1,087		517		28		375		(6)		2,001
Total revenues from contracts with customers	2,508		852		360		387		(9)		4,098
Other revenues
Leasing services(b)	112		43		198		13		—		366
Derivatives adjustments on commodity sales	24		—		—		(50)		—		(26)
Other	27		7		—		5		—		39
Total other revenues	163		50		198		(32)		—		379
Total revenues	$	2,671	$	902	$	558	$	355	$	(9)	$	4,477


	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	$	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
Leasing services(b)	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


	Six Months Ended June 30, 2026
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues from contracts with customers(a)
Services
Firm services	$	2,225	$	124	$	477	$	1	$	(2)	$	2,825
Fee-based services	673		536		209		25		(4)		1,439
Total services	2,898		660		686		26		(6)		4,264
Commodity sales
Natural gas sales	2,236		—		—		27		(3)		2,260
Product sales	502		829		46		579		(8)		1,948
Other sales	17		—		—		60		—		77
Total commodity sales	2,755		829		46		666		(11)		4,285
Total revenues from contracts with customers	5,653		1,489		732		692		(17)		8,549
Other revenues
Leasing services(b)	222		87		391		30		—		730
Derivatives adjustments on commodity sales	36		(1)		—		(88)		—		(53)
Other	56		14		—		9		—		79
Total other revenues	314		100		391		(49)		—		756
Total revenues	$	5,967	$	1,589	$	1,123	$	643	$	(17)	$	9,305


	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	$	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
Leasing services(b)	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

(a)Differences between the revenue presentation on the consolidated statements of income and the disaggregated revenues by type above are primarily attributable to revenues reflected in the “Other revenues” category above.

(b)Our revenues from leasing services are comprised of operating leases whereby we convey the right to control the use of an identified asset to a customer, including tanks, treating facilities, marine vessels, and gas equipment and pipelines with separate control locations.

Contract Balances

As of June 30, 2026 and December 31, 2025, our contract asset balances were $34 million and $30 million, respectively, and our contract liability balances were $485 million and $459 million, respectively. Of the December 31, 2025 contract asset and liability balances, $16 million was transferred to accounts receivable and $83 million was recognized as revenue during the six months ended June 30, 2026, respectively.

In addition, we had a lease contract liability balance associated with prepaid fixed reservation charges relating to contracts expiring from 2035 to 2040, under a long-term terminal services contract totaling $503 million and $531 million as of June 30, 2026 and December 31, 2025, respectively.

Revenue Allocated to Remaining Performance Obligations

The following table presents our estimated revenue related to unsatisfied performance obligations representing fixed consideration primarily related to commodity sales or service contracts with take-or-pay or minimum volume commitments that we expect to recognize in future periods:


	Remaining 2026		2027		2028 and thereafter
	(In billions)
Estimated revenue as of June 30, 2026	$	3	$	5	$	28

Based on the practical expedient we elected to apply, the amounts presented in the table above exclude remaining performance obligations for variable consideration related to 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 earnings before all non-cash DD&A expenses 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.

Financial information by segment follows:


	Three Months Ended June 30, 2026
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	2,664	$	902	$	556	$	355	$	—	$	4,477
Intersegment revenues	7		—		2		—		(9)		—
Total revenues	2,671		902		558		355		(9)		4,477
Costs of sales	(906)		(464)		(20)		(24)
Labor	(88)		(34)		(71)		(14)
Fuel and power	(25)		(21)		(5)		(33)
Field - non-labor(a)	(258)		(49)		(141)		(64)

Taxes, other than income taxes	(78)		(10)		(15)		(15)
Earnings (loss) from equity investments	193		18		4		10
Other segment items(b)	11		1		—		11

Total Segment EBDA(c)	$	1,520	$	343	$	310	$	226			2,399
DD&A											(620)

General and administrative and corporate charges											(188)
Interest, net(d)											(425)
Income tax expense											(272)
Net income											$	894

Other segment activity information:
DD&A	$	305	$	85	$	130	$	94	$	6	$	620
Capital expenditures	797		38		69		68		10		982


	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(e)	$	1,436	$	289	$	300	$	150			2,175
DD&A											(616)

General and administrative and corporate charges											(188)
Interest, net(d)											(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


	Six Months Ended June 30, 2026
	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Revenues
Revenues from external customers	$	5,955	$	1,589	$	1,118	$	643	$	—	$	9,305
Intersegment revenues	12		—		5		—		(17)		—
Total revenues	5,967		1,589		1,123		643		(17)		9,305
Costs of sales	(2,337)		(745)		(36)		(52)
Labor	(174)		(68)		(140)		(27)
Fuel and power	(51)		(41)		(10)		(58)
Field - non-labor(a)	(457)		(89)		(278)		(121)

Taxes, other than income taxes	(157)		(20)		(27)		(26)
Earnings (loss) from equity investments	418		36		7		18
Other segment items(b)	22		1		—		17

Total Segment EBDA(c)	$	3,231	$	663	$	639	$	394			4,927
DD&A											(1,253)

General and administrative and corporate charges											(365)
Interest, net(d)											(855)
Income tax expense											(559)
Net income											$	1,895

Other segment activity information:
DD&A	$	602	$	169	$	261	$	208	$	13	$	1,253
Capital expenditures	1,407		76		139		131		33		1,786


	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(e)	$	2,889	$	562	$	575	$	331			4,357
DD&A											(1,226)

General and administrative and corporate charges											(380)
Interest, net(d)											(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


	Reportable Segments
	Natural Gas Pipelines		Products Pipelines		Terminals		CO2		Corporate and Eliminations		Total
	(In millions)
Segment balance sheet information:
As of June 30, 2026
Investments	$	7,122	$	388	$	124	$	71	$	—	$	7,705
Other intangibles, net	1,098		371		12		391		—		1,872
Total assets(f)	54,029		8,043		7,840		3,511		639		74,062
As of December 31, 2025
Investments	$	6,962	$	381	$	122	$	67	$	—	$	7,532
Other intangibles, net	900		403		13		414		—		1,730
Total assets(f)	52,546		8,044		7,917		3,608		633		72,748

(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 allowance for equity funds used during construction.

(c)Includes non-cash risk management activities amounts for the three and six months ended June 30, 2026 of $60 million and $(15) million, $4 million and $(1) million, $1 million and none, and $19 million and $(2) million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, 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 risk management activities 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.

(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.

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,
	2026			2025			2026			2025
	(In millions, except percentages)
Income tax expense	$	272		$	177		$	559		$	363
Effective tax rate	23.3		%	19.3		%	22.8		%	19.6		%

The effective tax rate for the three and six months ended June 30, 2026 is higher than the statutory federal rate of 21% primarily due to (i) an increase in deferred tax liability for Texas Margin Tax as a result of the enactment of changes to tax rules and (ii) 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 three months ended June 30, 2025 is lower than the statutory federal tax rate of 21% primarily due to (i) a reduction of our deferred tax liability as a result of changes in state income allocations and (ii) 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 six months ended June 30, 2025 is lower than the statutory federal tax rate of 21% primarily due to (i) the recognition of investment tax credits generated by a biogas project; (ii) a reduction of our deferred tax liability as a result of changes in state income allocations; and (iii) dividend-received deductions from our investments in Citrus, NGPL Holdings LLC, and PPL, partially offset by state income taxes.

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 terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG sought to enforce the Guarantee after an arbitration tribunal delivered an award which resulted in the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response, Eni S.p.A. filed counterclaims seeking unspecified damages based on the same allegations that had been dismissed with prejudice in previous arbitrations. In 2022, the trial court granted Eni S.p.A.’s motion for summary judgment on GLNG’s claims. GLNG elected not to pursue recourse to the Court of Appeals, 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 dismissed Eni S.p.A.’s claims with prejudice. All appellate courts denied Eni S.p.A’s subsequent petitions seeking appellate review, thereby concluding this case.

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 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 that are now contested on a class-wide basis. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III 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. On July 25, 2024, 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 on its 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 based on its finding that the plan administrator used an inconsistent interpretation to calculate benefits for some retirees. The Court dismissed Claim VI without prejudice based on its finding that the claim is moot given the Court’s rulings on Claims 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, after which the parties filed summary judgment motions to address potential remedies for the remaining claims. 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. On April 22, 2025, the case was referred to a Magistrate Judge to conduct all pretrial proceedings including recommended rulings on plaintiffs’ motion for equitable remedies. On February 10, 2026, the Magistrate Judge issued a Memorandum and Recommendation that plaintiffs’ motion for equitable relief should be granted in part and denied in part. The Memorandum and Recommendation rejected or significantly narrowed a number of plaintiffs’ theories of recovery. The presiding U.S. District Court Judge may adopt, modify, or reject the Memorandum and Recommendation. 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 state 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 as described below.

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 other claims first made in January 2021 asserted by natural resource state and federal trustees relating to natural resource damages at 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 case 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 including Occidental Chemical Corporation (OCC), alleging, inter alia, that the Consent Decree is not procedurally and substantively fair, reasonable, and consistent with the purpose of CERCLA. On February 6, 2026, certain corporate parties who are PRPs and parties to the Consent Decree filed BASF Catalysts LLC, et al. v. Occidental Chemical Corporation (OCC) in U.S. District Court for the District of New Jersey alleging that OCC’s recent attempt to contractually transfer environmental liabilities through a corporate reorganization process violated CERCLA. Plaintiffs seek a declaratory judgment that (1) any purported transfer or allocation of CERCLA liability through the reorganization is precluded by CERCLA, and (2) that the Occidental entity that holds the assets of the former OCC is jointly and severally liable for the former OCC’s CERCLA liabilities. While we are not a party to the most recent lawsuit, the results could potentially impact the amount we and other PRPs ultimately are required to contribute to this CERCLA site.

Louisiana Governmental Coastal Zone Erosion Litigation

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 the State and Local Coastal Resources Management Act of 1978, as amended 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 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana and then stayed. We expect the case will remain in federal court. 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.

General

As of June 30, 2026 and December 31, 2025, we had liabilities of $174 million and $176 million, respectively, recorded for environmental matters. In addition, as of June 30, 2026 and December 31, 2025, we had receivables of $9 million and $10 million, respectively, recorded for expected cost recoveries that have been deemed probable.

Challenge to Federal “Good Neighbor Plan”

On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit (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. On January 27, 2026, the EPA proposed approving eight state implementation plans to address ozone emissions which were originally disapproved by the EPA. If finalized, those states would be removed from the EPA’s federal Good Neighbor Plan and its requirements would not apply to our facilities.

10. Recent Accounting Pronouncements

Accounting Standards Updates (ASU)

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.

ASU No. 2025-09

On November 25, 2025, the FASB issued ASU No. 2025-09, “Derivatives and Hedging (Topic 815): Hedge Accounting Improvements.” This ASU makes targeted improvements to Topic 815 to better align hedge accounting with the economics of an entity’s risk-management activities. This ASU will be effective for annual periods beginning after December 15, 2026, 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.

ASU No. 2025-10

On December 4, 2025, the FASB issued ASU No. 2025-10, “Government Grants (Topic 832): Accounting for Government Grants Received by Business Entities.” This ASU establishes guidance on the recognition, measurement, and presentation of government grants received by business entities, an area not previously addressed under US GAAP. This ASU will be effective for annual periods beginning after December 15, 2028, for interim reporting periods beginning within those annual periods, and early adoption is permitted. Management is currently evaluating this ASU as it relates to certain tax credits to determine its impact on the Company’s financial statements.

ASU No. 2026-02

On May 19, 2026, the FASB issued ASU No. 2026-02, “Environmental Credits and Environmental Credit Obligations (Topic 818).” This ASU establishes guidance on the recognition, measurement, presentation, and disclosure of environmental credits and compliance obligations that may be settled by using environmental credits. US GAAP did not previously address how to account for these items. The 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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