Item 8. Financial Statements and Supplementary Data.

KINDER MORGAN, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

									Page Number
Report of Independent Registered Public Accounting Firm						(PCAOB ID: 238)			67
Consolidated Statements of Income for the years ended December 31, 2025, 2024, and 2023									69
Consolidated Statements of Comprehensive Income for the years ended December 31, 2025, 2024, and 2023									70
Consolidated Balance Sheets as of December 31, 2025 and 2024									71
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023									72
Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2025, 2024, and 2023									74
Notes to Consolidated Financial Statements									75
Note 1.			General						75
Note 2.			Summary of Significant Accounting Policies						75
Note 3.			Acquisitions and Divestitures						84
Note 4.			Income Taxes						86
Note 5.			Property, Plant, and Equipment, net						89
Note 6.			Investments						90
Note 7.			Goodwill						91
Note 8.			Debt						91
Note 9.			Share-based Compensation and Employee Benefits						95
Note 10.			Stockholders’ Equity						101
Note 11.			Related Party Transactions						102
Note 12.			Commitments and Contingent Liabilities						103
Note 13.			Risk Management						104
Note 14.			Revenue Recognition						108
Note 15.			Reportable Segments						110
Note 16.			Leases						114
Note 17.			Litigation and Environmental						115
Note 18.			Recent Accounting Pronouncements						119

Report of Independent Registered Public Accounting Firm

To the Board of Directors and Stockholders of Kinder Morgan, Inc.

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024**,** and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management’s Report on Internal Control Over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill Impairment Assessment – Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals Reporting Units

As described in Notes 2 and 7 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, 2025, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion, and amortization expenses (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.

The principal considerations for our determination that performing procedures relating to the goodwill impairment assessment of the reporting units is a critical audit matter are (i) the significant judgment by management when developing the fair value estimate of the reporting units; (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units; and (iii) the audit effort involved the use of professionals with specialized skill and knowledge.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s goodwill impairment assessment, including controls over developing the fair value estimate of the reporting units. These procedures also included, among others (i) testing management’s process for developing the fair value estimate of the reporting units; (ii) evaluating the appropriateness of the market approach used by management; (iii) testing the completeness and accuracy of underlying data used in the market approach; and (iv) evaluating the reasonableness of the significant assumptions used by management related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units. Evaluating management’s assumptions related to forecasted EBITDA and the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units involved evaluating whether the assumptions used by management were reasonable considering (i) the current and past performance of the reporting units; (ii) the consistency with external market and industry data; and (iii) whether these assumptions were consistent with evidence obtained in other areas of the audit. Professionals with specialized skill and knowledge were used to assist in evaluating (i) the appropriateness of the market approach and (ii) the reasonableness of the assumption related to the enterprise value to estimated EBITDA multiples of comparable companies for each of the reporting units.

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 13, 2026

We have served as the Company’s auditor since 1997.

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

			Year Ended December 31,
			2025						2024						2023
Revenues
Services			$	9,490					$	8,916					$	8,371
Commodity sales			7,255						5,957						6,786
Other			192						227						177
Total Revenues			16,937						15,100						15,334
Operating Costs, Expenses, and Other
Costs of sales (exclusive of items shown separately below)			5,529						4,337						4,938
Operations and maintenance			3,057						2,972						2,807
Depreciation, depletion, and amortization			2,453						2,354						2,250
General and administrative			744						712						668
Taxes, other than income taxes			445						433						421
Other income, net			(15)						(92)						(13)
Total Operating Costs, Expenses, and Other			12,213						10,716						11,071
Operating Income			4,724						4,384						4,263
Other Income (Expense)
Earnings from equity investments			896						840						772
Interest, net			(1,801)						(1,844)						(1,797)
Other, net (Note 3)			173						27						(37)
Total Other Expense			(732)						(977)						(1,062)
Income Before Income Taxes			3,992						3,407						3,201
Income Tax Expense			(832)						(687)						(715)
Net Income			3,160						2,720						2,486
Net Income Attributable to Noncontrolling Interests			(104)						(107)						(95)
Net Income Attributable to Kinder Morgan, Inc.			$	3,056					$	2,613					$	2,391
Class P Common Stock
Basic and Diluted Earnings Per Share			$	1.37					$	1.17					$	1.06
Basic and Diluted Weighted Average Shares Outstanding			2,223						2,220						2,234

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

			Year Ended December 31,
			2025						2024						2023
Net income			$	3,160					$	2,720					$	2,486
Other comprehensive income, net of tax
Net unrealized gain (loss) from derivative instruments (net of taxes of $(54), $8, and $(47), respectively)			184						(29)						155
Reclassification into earnings of net derivative instruments (gain) loss to net income (net of taxes of $26, $(12), and $12, respectively)			(84)						40						(35)
Benefit plan adjustments (net of taxes of $(12), $(33), and $(20), respectively)			40						111						65
Total other comprehensive income			140						122						185
Comprehensive income			3,300						2,842						2,671
Comprehensive income attributable to noncontrolling interests			(104)						(107)						(95)
Comprehensive income attributable to KMI			$	3,196					$	2,735					$	2,576

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)

			December 31,
			2025						2024
ASSETS
Current assets
Cash and cash equivalents			$	63					$	88
Restricted deposits			46						126
Accounts receivable			1,714						1,506
Inventories			574						555
Other current assets			357						246
Total current assets			2,754						2,521
Property, plant, and equipment, net			39,331						38,013
Investments			7,532						7,845
Goodwill			20,084						20,084
Other intangibles, net			1,730						1,760
Deferred charges and other assets			1,317						1,184
Total Assets			$	72,748					$	71,407
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt			$	1,226					$	2,009
Accounts payable			1,408						1,395
Accrued interest			534						543
Accrued taxes			256						276
Other current liabilities			898						878
Total current liabilities			4,322						5,101
Long-term liabilities and deferred credits
Long-term debt
Outstanding			30,597						29,779
Debt fair value adjustments			180						102
Total long-term debt			30,777						29,881
Deferred income taxes			2,891						2,070
Other long-term liabilities and deferred credits			2,309						2,488
Total long-term liabilities and deferred credits			35,977						34,439
Total Liabilities			40,299						39,540
Commitments and contingencies (Notes 8, 12, 16 and 17)
Stockholders’ Equity
Class P Common Stock, $0.01 par value, 4,000,000,000 shares authorized, 2,224,777,750 and 2,221,647,775 shares, respectively, issued and outstanding			22						22
Additional paid-in capital			41,276						41,237
Accumulated deficit			(10,181)						(10,633)
Accumulated other comprehensive income (loss)			45						(95)
Total Kinder Morgan, Inc.’s stockholders’ equity			31,162						30,531
Noncontrolling interests			1,287						1,336
Total Stockholders’ Equity			32,449						31,867
Total Liabilities and Stockholders’ Equity			$	72,748					$	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)
			Year Ended December 31,
			2025						2024						2023
Cash Flows From Operating Activities
Net income			$	3,160					$	2,720					$	2,486
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion, and amortization			2,453						2,354						2,250
Deferred income taxes			780						647						710
Change in fair value of derivative contracts			(23)						72						(126)
Gain on divestitures, net			(6)						(74)						(15)
Gain on sale of interest in equity investment (Note 3)			(123)						—						—
Earnings from equity investments			(896)						(840)						(772)
Distributions of equity investment earnings			805						823						755
Pension contributions net of noncash pension benefit expenses			(10)						9						77
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable			(192)						52						301
Inventories			(21)						(12)						188
Other current assets			(9)						(46)						108
Accounts payable			96						(5)						(201)
Accrued interest, net of interest rate swaps			(13)						43						(13)
Accrued taxes			(15)						5						2
Other current liabilities			41						(48)						(79)
Change in deferred revenues			5						(58)						870
Other, net			(115)						(7)						(50)
Net Cash Provided by Operating Activities			5,917						5,635						6,491
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 3)			(648)						(62)						(1,842)
Capital expenditures			(3,026)						(2,629)						(2,317)
Proceeds from sale of investment (Note 3)			382						—						—
Contributions to investments			(178)						(121)						(212)
Distributions from equity investments in excess of cumulative earnings			330						177						228
Other, net			(39)						6						(32)
Net Cash Used in Investing Activities			(3,179)						(2,629)						(4,175)
Cash Flows From Financing Activities
Issuances of debt			10,017						10,441						7,590
Payments of debt			(10,054)						(10,557)						(7,356)
Debt issue costs			(20)						(33)						(20)
Dividends (Note 10)			(2,604)						(2,557)						(2,529)
Repurchases of shares (Note 10)			—						(7)						(522)
Contributions from noncontrolling interests			—						—						3
Distributions to noncontrolling interests			(153)						(154)						(151)
Other, net			(29)						(20)						(29)
Net Cash Used in Financing Activities			(2,843)						(2,887)						(3,014)
Effect of Exchange Rate Changes on Cash, Cash Equivalents, and Restricted Deposits			—						(1)						—
Net (Decrease) Increase in Cash, Cash Equivalents, and Restricted Deposits			(105)						118						(698)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period			214						96						794
Cash, Cash Equivalents, and Restricted Deposits, end of period			$	109					$	214					$	96

KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
			Year Ended December 31,
			2025						2024						2023
Noncash Investing and Financing Activities
Net increase in property, plant, and equipment from both accruals and contractor retainage									$	50					$	120
ROU assets and operating lease obligations recognized (Note 16)			$	25					36						56
Assets contributed to equity investment			—						—						16
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)			1,811						1,816						1,844

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

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions)

									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 January 1, 2023															2,248						$	22					$	41,673					$	(10,551)					$	(402)					$	30,742					$	1,372					$	32,114
Repurchases of shares															(32)												(522)																		(522)												(522)
Restricted shares															4												44																		44												44
Net income																																	2,391												2,391						95						2,486
Dividends																																	(2,529)												(2,529)												(2,529)
Distributions																																													—						(151)						(151)
Contributions																																													—						3						3
Acquisition (Note 3)																																													—						104						104
Other																											(5)																		(5)												(5)
Other comprehensive income																																							185						185												185
Balance at December 31, 2023															2,220						22						41,190						(10,689)						(217)						30,306						1,423						31,729
Repurchases of shares															(1)												(7)																		(7)												(7)
Restricted shares															3												54																		54												54
Net income																																	2,613												2,613						107						2,720
Dividends																																	(2,557)												(2,557)												(2,557)
Distributions																																													—						(154)						(154)
Acquisition adjustment (Note 3)																																													—						(38)						(38)
Other																																													—						(2)						(2)
Other comprehensive income																																							122						122												122
Balance at December 31, 2024															2,222						22						41,237						(10,633)						(95)						30,531						1,336						31,867
Restricted shares															3												39																		39												39
Net income																																	3,056												3,056						104						3,160
Dividends																																	(2,604)												(2,604)												(2,604)
Distributions																																													—						(153)						(153)
Other comprehensive income																																							140						140												140
Balance at December 31, 2025															2,225						$	22					$	41,276					$	(10,181)					$	45					$	31,162					$	1,287					$	32,449

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.			General

We are one of the largest energy infrastructure companies in North America. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. 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.

2.			Summary of Significant Accounting Policies

Basis of Presentation

Our reporting currency is U.S. dollars, and all references to dollars are U.S. dollars, unless stated otherwise. Our accompanying consolidated financial statements have been prepared under the rules and regulations of the SEC. These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. Under such rules and regulations, all significant intercompany items have been eliminated in consolidation. Additionally, certain amounts from prior years have been reclassified to conform to the current presentation.

Use of Estimates

Certain amounts included in or affecting our financial statements and related disclosures must be estimated, requiring us to make certain assumptions with respect to values or conditions which cannot be known with certainty at the time our financial statements are prepared. These estimates and assumptions affect the amounts we report for assets and liabilities, our revenues and expenses during the reporting period, and our disclosures, including those related to contingent assets and liabilities at the date of our financial statements. We evaluate these estimates on an ongoing basis, utilizing historical experience, consultation with experts, and other methods we consider reasonable in the particular circumstances. Nevertheless, actual results may differ significantly from our estimates. Any effects on our business, financial position, or results of operations resulting from revisions to these estimates are recorded in the period in which the facts that give rise to the revision become known.

Certain accounting policies are of more significance in our financial statement preparation process than others, and set out below are the principal accounting policies we apply in the preparation of our consolidated financial statements.

Cash Equivalents and Restricted Deposits

We define cash equivalents as all highly liquid short-term investments with original maturities of three months or less.

Amounts included in the restricted deposits in the accompanying consolidated financial statements represent a combination of restricted cash amounts required to be set aside by regulatory agencies to cover obligations for our captive insurance subsidiary and cash margin deposits posted by us with our counterparties associated with certain energy commodity contract positions.

Allowance for Credit Losses

We evaluate our financial assets measured at amortized cost and off-balance sheet credit exposures for expected credit losses over the contractual term of the asset or exposure. We consider available information relevant to assessing the collectability of cash flows including the expected risk of credit loss even if that risk is remote. We measure expected credit losses on a collective (pool) basis when similar risk characteristics exist, and we reflect the expected credit losses on the amortized cost basis of the financial asset as of the reporting date.

Our financial instruments primarily consist of our accounts receivable from customers, notes receivable from affiliates, and contingent liabilities such as proportional guarantees of debt obligations of an equity investee. We utilized historical analysis of credit losses experienced over the previous five years along with current conditions and reasonable and supportable forecasts of future conditions in our evaluation of collectability of our financial assets.

Inventories

Our inventories consist of materials and supplies and products such as natural gas, NGL, crude oil, condensate, refined petroleum products, and transmix. We report products inventory at the lower of weighted-average cost or net realizable value. We report materials and supplies inventories at cost, and periodically review for physical deterioration and obsolescence.

Property, Plant, and Equipment, net

Capitalization, Depreciation and Depletion and Disposals

We report property, plant, and equipment at its acquisition cost. We expense costs for routine maintenance and repairs in the period incurred. The following table summarizes our significant policies related to our property, plant, and equipment. The application of these policies can involve significant estimates.

Asset						Accounting Area						Policy
Straight-line assets						Depreciation rates						•Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property, and historical data concerning useful lives of similar assets.
						Gains and losses						•A gain or loss on the sale of property, plant, and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset. •A gain on an asset disposal is recognized in income in the period that the sale is closed. •A loss is recognized when the asset is sold or when classified as held for sale. •Gains and losses are recorded in operating costs, expenses, and other.
Composite assets						Depreciation rates						•A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value. •Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC. •A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property, and historical data concerning useful lives of similar assets.
						Gains and losses						•Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal. •Gains or losses on land sales and FERC-approved operating unit sales are recorded in operating costs, expenses, and other.
Oil and gas producing activities(a)						Successful efforts method of accounting						•Costs that are incurred to acquire leasehold and subsequent development costs are capitalized. •Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. •Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. •The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. •Other miscellaneous property, plant, and equipment are depreciated over the estimated useful lives of the asset.
						Enhanced recovery techniques						•In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. •The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. •When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. •Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.

(a)Gains and losses associated with assets in our oil and gas producing activities have a similar treatment as with that associated with our straight-line assets.

Circumstances may develop which cause us to change our estimates, thus impacting the future calculation of depreciation and amortization expense. Historically, adjustments to useful lives have not had a material impact on our aggregate depreciation levels from year to year.

Asset Retirement Obligations

We record liabilities for obligations related to the retirement and removal of long-lived assets used in our businesses. The majority of our asset retirement obligations are associated with our CO2 business where we are required to plug and abandon oil and gas wells that have been removed from service and to remove the surface wellhead equipment and compressors, but we also have obligations for certain gathering and long-haul pipelines and certain processing plants. We record, as liabilities, the fair value of asset retirement obligations on a discounted basis when they are incurred and can be reasonably estimated, which is typically at the time the assets are installed or acquired. The fair value estimates are primarily based on Level 3 inputs of the fair value hierarchy. The inputs include estimates and assumptions related to timing of settlement and retirement costs, which we base on historical retirement costs, future inflation rates, and credit-adjusted risk-free interest rates. Amounts recorded for the related assets are increased by the amount of these obligations. Over time, the liabilities are accreted to reflect the change in their present value, and the initial capitalized costs are depreciated over the useful lives of the related assets. The liabilities are eventually extinguished when the asset is taken out of service. Our estimates of retirement costs could change as a result of changes in cost estimates and/or timing of the obligation.

The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:

			December 31,
			2025						2024
			(In millions)
Balance at beginning of period			$	248					$	231
Accretion expense			14						13
Divestitures (Note 3)			—						(33)
Acquisitions (Note 3)			—						43
New obligations			23						10
Settlements			(30)						(16)
Balance at end of period(a)			$	255					$	248

(a)Balances at both December 31, 2025 and 2024 include $2 million within “Other current liabilities” on our accompanying consolidated balance sheets.

For certain assets, we currently cannot reasonably estimate the fair value of the asset retirement obligations because the associated assets have indeterminate lives. These assets include certain pipelines, processing plants and distribution facilities, and liquids and bulk terminal facilities. Based on the widespread use of hydrocarbons domestically and for international export, management expects demand for our services to exist for the foreseeable future. Therefore, the remaining useful lives of these assets are indeterminate due to prolonged expected demand. Additionally, these assets could also benefit from potential future conversion opportunities. For example, certain assets could be converted to transport, handle, or store products other than traditional hydrocarbons. Under our integrity program, individual asset parts are replaced regularly. Although some of the individual asset parts may be replaced, the assets themselves may remain intact indefinitely. For these assets, an asset retirement obligation, if any, will be recognized once sufficient information is available to reasonably estimate the fair value of the obligation.

Long-lived Asset Impairments

We evaluate long-lived assets including leases and investments for impairment whenever events or changes in circumstances indicate that our carrying amount of an asset or investment may not be recoverable. Individual assets are grouped at the lowest level for which the related identifiable cash flows are largely independent of the cash flows of other assets and liabilities.

In addition to our annual goodwill impairment test discussed further below, to the extent triggering events exist, we complete a review of the carrying value of our long-lived assets, including property, plant, and equipment as well as other intangibles, and record, as applicable, the appropriate impairments using a two-step approach. To determine if a long-lived asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value. If the carrying value of a long-

lived asset or asset group is in excess of estimated undiscounted cash flows, we typically use discounted cash flow analyses to calculate the fair value of the long-lived asset to determine if an impairment is required and the amount of the impairment losses to be recognized.

We evaluate our oil and gas producing properties for impairment of value on a field-by-field basis or, in certain instances, by logical grouping of assets if there is significant shared infrastructure, using undiscounted future cash flows based on estimated future oil and gas production volumes. Oil and gas producing properties deemed to be impaired are written down to their fair value, as determined by discounted future cash flows based on estimated future oil and gas production volumes.

Equity Method of Accounting and Basis Differences

We use the equity method of accounting for investments which we do not control, but for which we have the ability to exercise significant influence. The carrying values of these investments are impacted by our share of investee income or loss, distributions, amortization or accretion of basis differences, and other-than-temporary impairments. We evaluate our equity method investments for other-than-temporary impairment. When an other-than-temporary impairment is recognized, the loss is recorded as a reduction in equity earnings.

The difference between the carrying value of an investment and our share of the investment’s underlying equity in net assets is referred to as a basis difference. If the basis difference is assigned to depreciable or amortizable assets and liabilities, the basis difference is amortized or accreted as part of our share of investee earnings. To the extent that the basis difference relates to goodwill, referred to as equity method goodwill, the amount is not amortized.

Goodwill

Goodwill is the cost of an acquisition of a business in excess of the fair value of acquired assets and liabilities and is recorded as an asset on our balance sheet. Goodwill is not subject to amortization but must be tested for impairment at least annually and in interim periods if indicators of impairment exist. This test requires us to assign goodwill to an appropriate reporting unit and compare the fair value of a reporting unit to its carrying value. If the carrying value of a reporting unit, including allocated goodwill, exceeds its fair value an impairment is measured and recorded at the amount by which the reporting unit’s carrying value exceeds its fair value.

We evaluate goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. For purposes of 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. Generally, the evaluation of goodwill for impairment involves a quantitative test, although under certain circumstances an initial qualitative evaluation may be sufficient to conclude that goodwill is not impaired without conducting the quantitative test.

A large portion of our goodwill is non-deductible for tax purposes, and as such, to the extent there are impairments, all or a portion of the impairment may not result in a corresponding tax benefit.

Refer to Note 7 for further information.

Other Intangibles

Excluding goodwill, our other intangible assets include customer contracts and other relationships and agreements.

Our intangible assets primarily relate to customer contracts or other relationships for the gathering and transportation of petroleum, including oil, gasoline, and other refined petroleum products, the gathering and transportation of natural gas, and the production and supply of RNG and CO2. We determined the values of these intangible assets by first, estimating the revenues derived from a customer contract or relationship (offset by the cost and expenses of supporting assets to fulfill the contract), and second, discounting the revenues at a risk adjusted discount rate.

We amortize the costs of our intangible assets to expense in a systematic and rational manner over their estimated useful lives. The life of each intangible asset is based either on the life of the corresponding customer contract or agreement or, in the case of a customer relationship intangible (the life of which was determined by an analysis of all available data on that business relationship), the length of time used in the discounted cash flow analysis to determine the value of the customer relationship.

Among the factors we weigh, depending on the nature of the asset, are the effects of obsolescence, new technology, and competition.

The following tables summarize our other intangible assets as of December 31, 2025 and 2024 and our amortization expense for the years ended December 31, 2025, 2024, and 2023:

									December 31,
						2025						2024
									(In millions)
Gross									$	3,580					$	3,543
Accumulated amortization									(1,850)						(1,783)
Net carrying amount									$	1,730					$	1,760

						December 31,
						2025						2024						2023
						(In millions)
Amortization expense						$	190					$	197					$	202

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:

						2026						2027						2028						2029						2030
						(In millions)
Estimated amortization expenses						$	184					$	188					$	187					$	186					$	186

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers and are primarily derived from the following activities:

Business Segment						Nature of Revenue
Natural Gas Pipelines						•Natural gas transportation and storage services •Gathering and processing services •Natural gas and NGL sales
Products Pipelines						•Transmix, crude oil, and other commodity products sales •Crude oil and refined petroleum product transportation and storage services
Terminals						•Liquids and bulk storage and handling services
CO2						•Crude oil, NGL, natural gas, CO2, and RIN sales •CO2 enhanced oil recovery and CO2 and crude oil transportation services

We recognize revenue when control of the promised goods or services is transferred to our customers and in an amount that reflects the consideration we expect to receive for those goods or services. Revenues are generally invoiced on a monthly basis. The table below describes the general steps we follow for revenue recognition for the large majority of our contracts. Each of these steps may involve management judgment and an analysis of the contract’s material terms. Refer to Note 14 for further information.

						Commodity Sales						Firm Services						Fee-Based Services
Revenue Type						Customers specify quantities of commodity products to be delivered and sold at specified delivery points.						Customers are generally subject to a fixed take-or-pay reservation fee or are subject to a minimum volume commitment for services.						Customers receive non-firm or interruptible services, on an “as available” basis.
Performance Obligation						Each unit of commodity (Bcf, gallon, barrel, etc.) is a separate performance obligation (promise to sell multiple distinct units of commodity at a point in time).						Promise to stand-ready to provide continuous service availability, with limited exceptions, over the contractual service period (a single performance obligation).						Upon acceptance of a customer’s periodic service request, promise to provide a series of periodic services over the contractual service period (a single performance obligation).

						Commodity Sales						Firm Services						Fee-Based Services
Transaction Price						Variable consideration (typically market-indexed per unit rate), for the value of commodities sold.						Fixed consideration, including payment for a minimum fixed fee, even if service is not used or received.						Variable consideration (typically fee-based per unit rate), based on invoicing right for units of service transferred.
Allocation of Transaction Price						Allocated to each performance obligation, based on the commodity’s standalone selling price.						Allocated ratably over the contractual service period.						Allocated to a single performance obligation of providing services over the contractual service period.
Performance Obligation Satisfaction						Upon delivery of the commodity.						Based on the passage of time, as the service period expires.						As each unit of service is transferred to the customer in the specified service period.

Contract Balances

Our contract assets arise when we recognize revenue before billing and our right to payment is conditional on factors other than the passage of time and primarily relate to breakage revenue under firm service contracts and contracts with increasing fixed rates per volume, where we apply revenue levelization and recognize revenue evenly over the contract term. Contract liabilities represent payments received for performance obligations which have not been fulfilled and primarily relate to (i) advanced payments for capital improvements, which we recognize as revenue ratably over the contract term; (ii) payments for temporary minimum volume shortfalls, which we recognize when the volume shortfalls are made up or make-up becomes remote; and (iii) contracts with decreasing fixed rates per volume, where we apply revenue levelization for amounts received for future performance obligations.

Costs of Sales

Costs of sales primarily includes the cost to purchase energy commodities sold, including natural gas, crude oil, NGL, and other refined petroleum products, adjusted for the effects of our energy commodity hedging activities, as applicable. Costs of our crude oil, gas, and CO2 producing activities, such as those in our CO2 business segment, are not accounted for as costs of sales.

Operations and Maintenance

Operations and maintenance includes costs of services and is primarily comprised of (i) operational labor costs and (ii) operations, maintenance and asset integrity, regulatory and environmental costs. Costs associated with our crude oil, gas, and CO2 producing activities included within operations and maintenance totaled $382 million, $402 million, and $393 million for the years ended December 31, 2025, 2024, and 2023, respectively.

Environmental Matters

We capitalize certain environmental expenditures required to obtain rights-of-way, regulatory approvals, or permitting as part of the construction of facilities we use in our business operations. We accrue and expense environmental costs that relate to an existing condition caused by past operations, which do not contribute to current or future revenue generation. We generally do not discount environmental liabilities to a net present value, and we record environmental liabilities when environmental assessments and/or remedial efforts are probable and we can reasonably estimate the costs, such as after the completion of a feasibility study or commitment to a formal plan of action. We recognize receivables for anticipated associated insurance recoveries when such recoveries are deemed to be probable. We record at estimated fair value, where appropriate, environmental liabilities assumed in a business combination.

We routinely conduct reviews of potential environmental issues and claims that assist us in identifying environmental issues and estimating the costs and timing of remediation efforts. We also routinely adjust our environmental liabilities to reflect changes in previous estimates. In making environmental liability estimations, we consider the material effect of environmental compliance, pending legal actions against us, and potential third-party liability claims we may have against others. Often, as the remediation evaluation and effort progresses, additional information is obtained, requiring revisions to estimated costs.

Leases

We lease property including corporate and field offices and facilities, vehicles, heavy work equipment including rail cars and large trucks, tanks, office equipment, and land. Our leases have remaining lease terms of one to 45 years, some of which have options to extend or terminate the lease. We determine if an arrangement is a lease at inception or upon modification. For purposes of calculating operating lease liabilities, lease terms may be deemed to include options to extend or terminate the lease when it is reasonably certain that we will exercise that option.

Our operating ROU assets and operating lease liabilities are recognized based on the present value of lease payments over the lease term at commencement date. Leases with variable rate adjustments, such as Consumer Price Index (CPI) adjustments, are reflected based on contractual lease payments as outlined within the lease agreement and not adjusted for any CPI increases or decreases. Because most of our leases do not provide an explicit rate of return, we use our incremental secured borrowing rate based on lease term information available at the commencement date of the lease in determining the present value of lease payments. We have real estate lease agreements with lease and non-lease components, which are accounted for separately. For certain equipment leases, such as copiers and vehicles, we account for the leases under a portfolio method. Leases that were grandfathered under various portions of Topic 842*,* such as land easements, are reassessed when the agreements are modified.

Refer to Note 16 for further information.

Share-based Compensation

We recognize compensation expense ratably over the vesting period of the restricted stock award based on the grant-date fair value, which is determined based on the market price of our Class P common stock on the grant date, less estimated forfeitures. Forfeiture rates are estimated based on historical forfeitures under our equity award plans. Upon vesting, the restricted stock award will be settled in unrestricted shares of our Class P common stock.

Pensions and Other Postretirement Benefits

We recognize the differences between the fair value of each of our and our consolidated subsidiaries’ pension and other postretirement benefit plans’ assets and the benefit obligations as either assets or liabilities on our consolidated balance sheets. We record deferred plan costs and income—unrecognized losses and gains, unrecognized prior service costs and credits, and any remaining unamortized transition obligations—net of income taxes in “Accumulated other comprehensive loss,” with the proportionate share associated with less than wholly owned consolidated subsidiaries allocated and included within “Noncontrolling interests,” or as a regulatory asset or liability for certain of our regulated operations, until they are amortized as a component of benefit expense. Other than service cost, all other components of net benefit (cost) credit are included within “Other, net” in our accompanying consolidated statements of income.

Variable Interest Entities (VIEs)

We evaluate our financial interests in business entities to determine if they represent VIEs when we are the primary beneficiary. To make this determination, we evaluate whether we have the ability to direct the activities that most significantly affect the entity’s economic performance and have the right to receive benefits from and the obligation to absorb losses of the entity.

We hold a variable interest in and consolidate ELC. Southern Liquefaction Company, LLC (SLC), which we indirectly control, is the primary beneficiary. ELC’s liquefaction service agreement is designed for recovery of actual operating and maintenance costs, thereby limiting its equity owners’ exposure to cost variability. In addition, substantially all of ELC’s activities involve KMI subsidiaries under common control that benefit from ELC’s operations. We receive distributions from ELC indirectly through our interest in SLC; but otherwise, ELC’s assets cannot be used to settle our obligations. ELC’s creditors have no recourse against our general credit and ELC’s obligations may only be settled using its own assets. ELC does not guarantee our debt or other commitments. The balance of ELC’s “Property, plant, and equipment, net” as of December 31, 2025 and 2024 were $1,099 million and $1,129 million, respectively, and its other working capital and other long-term assets and liabilities at the end of each period were not material.

Noncontrolling Interests

Noncontrolling interests represents the interests in our consolidated subsidiaries that are not owned by us. In our accompanying consolidated statements of income, the noncontrolling interest in the net income of our less than wholly owned

consolidated subsidiaries is shown as an allocation of our consolidated net income and is presented separately as “Net Income Attributable to Noncontrolling Interests.” In our accompanying consolidated balance sheets, noncontrolling interests is presented separately as “Noncontrolling interests” within “Stockholders’ Equity.”

Income Taxes

Income tax expense is recorded based on an estimate of the effective tax rate in effect or to be in effect during the relevant periods. Changes in tax legislation are included in the relevant computations in the period in which such changes are enacted. We do business in a number of states with differing laws concerning how income subject to each state’s tax structure is measured and at what effective rate such income is taxed. Therefore, we must make estimates of how our income will be apportioned among the various states in order to arrive at an overall effective tax rate. Changes in our effective tax rate, including any effect on previously recorded deferred taxes, are recorded in the period in which the need for such change is identified.

Deferred income tax assets and liabilities are recognized for temporary differences between the basis of assets and liabilities for financial reporting and tax purposes. Deferred tax assets are reduced by a valuation allowance when it is more-likely-than-not that all, or a portion, of a deferred tax asset will not be realized. While we have considered estimated future taxable income and prudent and feasible tax planning strategies in determining the amount of our valuation allowance, any change in the amount that we expect to ultimately realize will be included in income in the period in which such a determination is reached. Income tax effects are released from accumulated other comprehensive loss to retained earnings, when applicable, on an individual item basis as those items are reclassified into income.

In determining the deferred income tax asset and liability balances attributable to our investments, we apply an accounting policy that looks through our investments. The application of this policy resulted in no deferred income taxes being provided on the difference between the book and tax basis on the non-tax-deductible goodwill portion of our investments, including KMI’s investment in its wholly-owned subsidiary, KMP.

Risk Management Activities

We utilize energy commodity derivative contracts for the purpose of mitigating our risk resulting from fluctuations in the market price of commodities including crude oil, natural gas, and NGL. In addition, we enter into interest rate swap agreements for the purpose of managing our interest rate exposure associated with our debt obligations. We also enter into cross-currency swap agreements to manage our foreign currency risk associated with certain debt obligations. We measure our derivative contracts at fair value and we report them on our balance sheet as either an asset or liability. For certain physical forward commodity derivatives contracts, we apply the normal purchase/normal sale exception, whereby the revenues and expenses associated with such transactions are recognized during the period when the commodities are physically delivered or received.

For qualifying accounting hedges, we formally document the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. When we designate a derivative contract as a cash flow accounting hedge, the entire change in fair value of the derivative that is included in the assessment of hedge effectiveness is deferred in “Accumulated other comprehensive loss” and reclassified into earnings in the period in which the hedged item affects earnings. When we designate a derivative contract as a fair value accounting hedge, the change in fair value of the hedged item is recorded as an adjustment to the carrying value of the hedged item and recognized currently in earnings in the same line item that the change in fair value of the derivative is recognized currently in earnings. Therefore, any difference between the changes in fair values of the item being hedged and the derivative contract results in a gain or loss from the hedging relationship recognized currently in earnings.

For derivative instruments that are not designated as accounting hedges, or for which we have not elected the normal purchase/normal sales exception, changes in fair value are recognized currently in earnings.

Unrealized gains and losses associated with our derivative activities that affect income are reflected as “Change in fair market value of derivative contracts” within our accompanying consolidated statement of cash flows as a noncash add back to net income to arrive at cash flows from our derivative activities for the period. Net changes in our interest receivable and payable balances that represent accruals and periodic settlements of interest on our interest rate swaps are included within “Accrued interest, net of interest rate swaps” on our accompanying consolidated statement of cash flows.

Fair Value

The fair values of our financial instruments are separated into three broad levels (Levels 1, 2, and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. We assign each fair value measurement to a level corresponding to the lowest level input that is significant to the fair value measurement in its entirety. Recognized valuation techniques utilize inputs such as contractual prices, quoted market prices or rates, and discount factors. These inputs may be either readily observable or corroborated by market data.

Regulatory Assets and Liabilities

Regulatory assets and liabilities represent probable future revenues or expenses associated with certain charges and credits that will be recovered from or returned to customers through the ratemaking process. In instances where we receive recovery in tariff rates related to losses on dispositions of operating units, we record a regulatory asset for the estimated recoverable amount. We include the amounts of our regulatory assets and liabilities within “Other current assets,” “Deferred charges and other assets,” “Other current liabilities” and “Other long-term liabilities and deferred credits,” respectively, in our accompanying consolidated balance sheets.

The following table summarizes our regulatory asset and liability balances as of December 31, 2025 and 2024:

			December 31,
			2025						2024
			(In millions)
Current regulatory assets			$	40					$	25
Non-current regulatory assets			216						231
Total regulatory assets(a)			$	256					$	256
Current regulatory liabilities			$	18					$	35
Non-current regulatory liabilities			199						197
Total regulatory liabilities(b)			$	217					$	232

(a)Regulatory assets as of December 31, 2025 include (i) $80 million of unamortized losses on disposal of assets; (ii) $39 million income tax gross up on equity AFUDC; and (iii) $137 million of other assets, including amounts related to fuel tracker arrangements. Approximately $171 million of the regulatory assets, with a weighted average remaining recovery period of 7 years, are recoverable without earning a return, including the income tax gross up on equity AFUDC for which there is an offsetting deferred income tax balance for FERC rate base purposes; therefore, it does not earn a return.

(b)Regulatory liabilities as of December 31, 2025 are comprised of customer prepayments to be credited to shippers or other over-collections that are expected to be returned to shippers or netted against under-collections over time. Approximately $109 million of the $199 million classified as non-current is expected to be credited to shippers over a remaining weighted average period of 10 years, while the remaining $90 million is not subject to a defined period.

Earnings per Share (EPS)

We calculate EPS using the two-class method, which allocates earnings to common stock and participating securities based on dividends paid in the current period plus an allocation of the undistributed earnings.

The following table sets forth net income allocated to common shareholders:

			Year Ended December 31,
			2025						2024						2023
			(In millions, except per share amounts)
Net Income Available to Stockholders			$	3,056					$	2,613					$	2,391
Less: Net Income Allocated to Participating Securities(a)			(16)						(15)						(14)
Net Income Allocated to Common Stockholders			$	3,040					$	2,598					$	2,377
Basic and Diluted Weighted Average Shares Outstanding(b)			2,223						2,220						2,234
Basic and Diluted EPS(b)			$	1.37					$	1.17					$	1.06

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

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

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

			Year Ended December 31,
			2025						2024						2023
			(In millions on a weighted average basis)
Unvested stock awards			13						13						13
Convertible trust preferred securities			3						3						3

3.			Acquisitions and Divestitures

Acquisitions

For acquired businesses, we recognize the identifiable assets acquired, the liabilities assumed, and any noncontrolling interest in the acquiree at their estimated fair values on the date of acquisition with any excess purchase price over the fair value of net assets acquired recorded to goodwill. Determining the fair value of these items requires management’s judgment and the utilization of an independent valuation specialist, if applicable, and involves the use of significant estimates and assumptions.

Our allocation of the purchase price for acquisitions completed during the years ended December 31, 2025, 2024, and 2023 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
(4)						Diamond M			13						—						25						—						—						(12)						—						—

(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 consist of a 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) STX 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. Other long-term assets includes $357 million related to customer relationships intangibles with a weighted average amortization period of 15 years and $192 million related to a 50% equity investment interest in Dos Caminos, LLC. The acquisition included a 90% interest in NET Mexico Pipeline LLC. During the year ended December 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 goodwill consists primarily of synergies expected from the business combination and $124 million of the goodwill recorded is expected to be tax deductible. The acquired assets are included in our Natural Gas business segment.

The determination of fair value utilized valuation methodologies including discounted cash flows for the customer relationships intangible assets and the equity method investment and the replacement cost approach for the property, plant, and equipment. The significant assumptions made in performing these valuations include the discount rate utilized to value the customer relationships intangible assets and equity method investment and replacement costs used to value property, plant, and equipment.

(4) Diamond M Acquisition

On June 1, 2023, we completed the acquisition of the Diamond M Field from Parallel Petroleum LLC for a purchase price of $13 million, including purchase price adjustments for working capital. During the year ended December 31, 2024, we acquired an additional working interest from Collins Permian LP for a purchase price of $3 million, net of an immaterial asset retirement obligation assumed. These acquired assets, which are adjacent to our SACROC field, are included in our CO2 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.

Divestitures

Sale of EagleHawk

On December 31, 2025, we completed a sale of our 25% non-operated interest in EagleHawk, and received $382 million of cash proceeds from the sale, including preliminary purchase price adjustments, which is reported as an investing activity within “Proceeds from sale of investment” on our accompanying consolidated statement of cash flows, and recorded a gain of $123 million, which is reported within “Other, net” on our accompanying consolidated statement of income.

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 from this divestiture, net of working capital adjustments, which is reported as an investing activity within “Other, net” on our accompanying consolidated statement of cash flows, and recorded a gain of $40 million, which is reported within “Other income, net” on our accompanying consolidated statement of income and includes the effect of a $33 million reduction in our asset retirement obligations that were transferred to the buyer. The assets were included in our CO2 business segment.

4.			Income Taxes

The components of “Income Before Income Taxes” are as follows:

			Year Ended December 31,
			2025						2024						2023
			(In millions)
U.S.			$	3,990					$	3,402					$	3,192
Foreign			2						5						9
Total Income Before Income Taxes			$	3,992					$	3,407					$	3,201

Components of the income tax provision applicable for federal, foreign and state taxes are as follows:

			Year Ended December 31,
			2025						2024						2023
			(In millions)
Current tax expense
Federal			$	23					$	11					$	—
State			25						26						5
Foreign			4						3						—
Total			52						40						5
Deferred tax expense
Federal			729						602						619
State			51						45						91
Total			780						647						710
Total tax provision			$	832					$	687					$	715

The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:

			Year Ended December 31,
			2025												2024												2023
			(In millions, except percentages)
Federal income tax			$	838					21.0		%				$	716					21.0		%				$	672					21.0		%
Increase (decrease) as a result of:
State income tax, net of federal benefit(a)			69						1.7		%				64						1.9		%				97						3.0		%
Foreign tax effects			3						0.1		%				2						0.1		%				—						—		%
Tax Credits
Investment tax credit(b)			(21)						(0.5)		%				(42)						(1.2)		%				(1)						—		%
Other credit			—						—		%				(1)						—		%				(5)						(0.1)		%
Changes in Valuation Allowances			—						—		%				—						—		%				4						0.1		%
Nontaxable or Nondeductible Items
Dividend received deduction			(36)						(0.9)		%				(34)						(1.0)		%				(34)						(1.1)		%
Other			(23)						(0.7)		%				(19)						(0.6)		%				(16)						(0.5)		%
Changes in unrecognized tax benefits			2						0.1		%				1						—		%				(2)						(0.1)		%
Total			$	832					20.8		%				$	687					20.2		%				$	715					22.3		%

(a)State taxes in Texas, California, Arizona, North Dakota, and New Jersey made up the majority (greater than 50%) of the tax effect in this category for 2025. Pennsylvania, Texas, New Jersey, and Mississippi made up the majority of state tax expense in 2024. Louisiana, Pennsylvania, Georgia, Utah, Colorado, and California made up the majority of state tax expense in 2023.

(b)Recognition of investment tax credits generated by biogas projects.

Deferred tax assets and liabilities result from the following:

			December 31,
			2025						2024
			(In millions)
Deferred tax assets
Employee benefits			$	67					$	81
Net operating loss carryforwards			1,017						1,416
Tax credit carryforwards			265						312
Interest expense limitation			346						372
Other			183						179
Valuation allowances			(72)						(64)
Total deferred tax assets			1,806						2,296
Deferred tax liabilities
Property, plant, and equipment			231						217
Investments(a)			4,436						4,124
Other			30						25
Total deferred tax liabilities			4,697						4,366
Net deferred tax liability			$	(2,891)					$	(2,070)

(a)Amounts as of December 31, 2025 and 2024 are primarily associated with KMI’s investment in KMP.

Deferred Tax Assets and Valuation Allowances

A reconciliation of our valuation allowances for the year ended December 31, 2025 is as follows:

						Year Ended December 31, 2025
						(In millions)
Balance at beginning of period						$	64
Addition for state NOL						6
State rate changes						(1)
Currency fluctuation						3
Balance at end of period						$	72

The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2025:

						Unused Amount						Deferred Tax Asset						Valuation Allowance						Expiration Period
						(In millions)
Net Operating Loss
U.S. federal net operating loss						$	3,899					$	819					$	—					Indefinite
State losses						4,137						171						(45)						2025 - 2045
Foreign losses						79						27						(27)						Indefinite
Tax Credits
General business credits						265						265						—						2037 - 2045

Use of a portion of our U.S. federal carryforwards is subject to the limitations provided under Sections 382 and 383 of the Internal Revenue Code as well as the separate return limitation rules of Internal Revenue Service regulations. If certain substantial changes in our ownership occur, there would be an annual limitation on the amount of carryforwards that could be utilized.

Unrecognized Tax Benefits: We recognize the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities, based not only on the technical merits of the tax position based on tax law, but also the past administrative practices and precedents of the taxing authority. The tax benefits

recognized in the financial statements from such a position are measured based on the largest benefit that has a greater than 50% likelihood of being realized upon ultimate resolution.

A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows:

						Year Ended December 31,
						2025						2024						2023
						(In millions)
Balance at beginning of period						$	19					$	18					$	23
Reductions based on statute expirations						(2)						(3)						(5)
Audit settlement						(1)						—						(1)
Additions to state reserves for prior years						5						4						1
Balance at end of period						$	21					$	19					$	18
Amounts which, if recognized, would affect the effective tax rate						$	21

In addition, we believe it is reasonably possible that our liability for unrecognized tax benefits will remain the same during the next year, primarily due to additions for state filing positions taken in prior years, offset by releases from statute expirations.

The following table summarizes information of our open tax years:

Jurisdiction						Open Tax Year
U.S.						2021 - 2025
Various states						2012 - 2025
Foreign						2021 - 2025

Income Taxes Paid

The components of total income taxes paid net of refunds by jurisdiction are as follows:

						Year Ended December 31,
						2025						2024						2023
						(In millions)
Federal						$	20					$	10					$	—
States(a)
Texas						12						9						6
Pennsylvania						3						4						2
Louisiana						3						2						—
California						3						2						—
New Hampshire						—						—						1
Utah						—						1						1
New Mexico						—						—						(2)
Other States						3						4						—
Foreign
Mexico						3						1						3
Total Income Taxes Paid						$	47					$	33					$	11

(a)2025 tax payments include $4 million of transferrable state tax credits purchased.

On July 4, 2025, President Trump signed into law the One Big Beautiful Bill Act (OBBBA) that includes tax reform provisions that amend, eliminate, and extend tax rules under the Inflation Reduction Act and Tax Cuts and Jobs Act. The most significant impact to the Company of the OBBBA at this time is the permanent reinstatement of bonus depreciation on qualified property and modifications to the calculation for excess business interest expense limitation under §163(j) to the current tax estimate. Based on our current projections, we anticipate the impact will defer the payment of a significant portion of our

current federal tax for multiple years. The impact to current and deferred tax has been recorded with no overall impact to our income statement.

5. Property, Plant, and Equipment, net

As of December 31, 2025 and 2024, our property, plant, and equipment, net consisted of the following:

			Straight-Line Estimated Useful Life						Composite Depreciation Rates						December 31,
									2025						2024
			(Years)						(%)						(In millions)
Interstate Natural Gas FERC-Regulated
Pipelines (Natural gas)									1.09-6.67						$	12,583					$	12,376
Equipment (Natural gas)									1.09-6.67						10,118						9,488
Other(a)									0.00-33						1,124						1,143
Accumulated depreciation, depletion, and amortization															(11,092)						(10,712)
Depreciable assets															12,733						12,295
Land															54						51
Construction work in process															454						568
Total interstate natural gas FERC-regulated															13,241						12,914
Other
Pipelines (Natural gas, liquids, refined products, crude oil and CO2)			5-40						0.09-33.33						9,697						8,933
Equipment (Natural gas, liquids, refined products, crude oil, CO2 and terminals)			5-40						0.09-33.33						21,425						20,243
Other(a)			3-10						0.00-33.33						5,790						5,587
Accumulated depreciation, depletion, and amortization															(12,970)						(11,470)
Depreciable assets															23,942						23,293
Land															785						786
Construction work in process															1,363						1,020
Total other															26,090						25,099
Property, plant, and equipment, net															$	39,331					$	38,013

(a)Includes general plant, general structures and buildings, land rights-of-way, computer and communication equipment, intangibles, vessels, transmix products, linefill, and miscellaneous property, plant, and equipment.

Depreciation, depletion and amortization expense for property, plant, and equipment, net was $2,233 million, $2,127 million, and $2,020 million for the years ended December 31, 2025, 2024, and 2023, respectively.

6. Investments

Our investments primarily consist of equity investments where we hold significant influence over investee actions and for which we apply the equity method of accounting. The following table provides details on our investments as of December 31, 2025 and 2024 and our earnings (loss) from these respective investments for the years ended December 31, 2025, 2024, and 2023:

			Ownership Interest						Equity Investments												Earnings from Equity Investments
			December 31,						December 31,												Year Ended December 31,
			2025						2025						2024						2025						2024						2023
									(In millions)
Citrus Corporation			50%						$	1,819					$	1,794					$	153					$	134					$	143
SNG			50%						1,660						1,734						127						145						140
PHP			27.74%						736						736						92						91						70
NGPL Holdings(a)			37.5%						645						618						130						117						121
GCX			34%						630						566						90						91						93
Products (SE) Pipe Line Corporation			51.17%						371						371						73						72						65
Utopia Holding LLC			50%						314						318						39						24						22
MEP			50%						299						320						74						63						87
Gulf LNG Holdings Group, LLC			50%						206						240						27						26						25
Dos Caminos, LLC			50%						181						188						22						16						—
Red Cedar Gathering Company			49%						168						168						3						7						15
EagleHawk(b)									—						266						34						26						18
All others(c)									503						526						78						78						39
Total investments									$	7,532					$	7,845					$	942					$	890					$	838
Amortization of excess cost																					$	(46)					$	(50)					$	(66)

(a)Our investment in NPGL Holdings includes a related party promissory note receivable from NGPL Holdings with quarterly interest payments at 6.75%. The outstanding principal amount of our related party promissory note receivable at both December 31, 2025 and 2024 was $375 million. For the each of the years ended December 31, 2025, 2024, and 2023, we recognized $25 million of interest within “Earnings from equity investments” on our accompanying consolidated statements of income.

(b)On December 31, 2025, we completed a sale of our 25% interest in EagleHawk. See Note 3 “Acquisitions and Divestitures” for further information regarding this divestiture.

(c)Includes a loss of $67 million on our share of a pre-tax non-cash impairment charge related to our investment in Double Eagle Pipeline for the year ended December 31, 2023. The impairment was driven by lower expected renewal rates on contracts that expired in the second half of 2023.

Summarized combined financial information for our equity investments is reported below (amounts represent 100% of investee financial information):

						Year Ended December 31,
Income Statement						2025						2024						2023
						(In millions)
Revenues						$	6,854					$	6,607					$	6,249
Costs and expenses						4,798						4,541						4,262
Net income						$	2,056					$	2,066					$	1,987

						December 31,
Balance Sheet						2025						2024
						(In millions)
Current assets						$	1,451					$	1,355
Non-current assets						24,490						24,465
Current liabilities						1,420						2,223
Non-current liabilities						10,469						9,181
Partners’/owners’ equity						14,052						14,416

7. Goodwill

Changes in the amounts of our goodwill for each of the years ended December 31, 2025 and 2024 are summarized by segment as follows:

			Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Total
			(In millions)
January 1, 2024			$	16,748					$	1,529					$	802					$	1,042					$	20,121
Acquisition(a)			(28)						—						—						—						(28)
Divestiture(b)			—						—						—						(9)						(9)
December 31, 2024 and 2025			$	16,720					$	1,529					$	802					$	1,033					$	20,084
Accumulated impairment losses as of December 31, 2025(c)			$	(4,240)					$	(1,267)					$	(679)					$	(600)					$	(6,786)

(a)Reflects adjustment to purchase price allocation related to the December 2023 STX Midstream acquisition.

(b)Associated with our CO2 business segment assets that were divested in June 2024.

(c)Also reflects balances as of January 1, 2024. Impairment losses all occurred prior to 2024.

Results of our May 31, 2025 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded carrying value (by at least 10%). We did not identify any triggers requiring further impairment analysis during the remainder of the year.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates, which include assumptions primarily involving management’s judgments and estimates. For all reporting units other than the Energy Transition Ventures reporting unit within our CO2 business segment, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses, including amortization of basis differences, which was previously presented separately as amortization of excess cost of equity investments (EBITDA) and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For the Energy Transition Ventures reporting unit, which had a goodwill balance of $114 million as of December 31, 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.

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.

8. Debt

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

			December 31,
			2025						2024
			(In millions)
Credit facility and commercial paper borrowings(a)			$	13					$	331
Corporate senior notes(b)
4.30%, due June 2025			—						1,500
1.75%, due November 2026			500						500
6.70%, due February 2027			7						7
2.25%, due March 2027(c)			587						518
6.67%, due November 2027			7						7
4.30%, due March 2028			1,250						1,250
7.25%, due March 2028			32						32
6.95%, due June 2028			31						31
5.00%, due February 2029			1,250						1,250
5.10% due August 2029			500						500
5.15% due June 2030			1,100						—
8.05%, due October 2030			234						234

			December 31,
			2025						2024
2.00%, due February 2031			750						750
7.40%, due March 2031			300						300
7.80%, due August 2031			537						537
7.75%, due January 2032			1,005						1,005
7.75%, due March 2032			300						300
4.80%, due February 2033			750						750
5.20%, due June 2033			1,500						1,500
7.30%, due August 2033			500						500
5.40%, due February 2034			1,000						1,000
5.30%, due December 2034			750						750
5.80%, due March 2035			500						500
5.85% due June 2035			750						—
7.75%, due October 2035			1						1
6.40%, due January 2036			36						36
6.50%, due February 2037			400						400
7.42%, due February 2037			47						47
6.95%, due January 2038			1,175						1,175
6.50%, due September 2039			600						600
6.55%, due September 2040			400						400
7.50%, due November 2040			375						375
6.375%, due March 2041			600						600
5.625%, due September 2041			375						375
5.00%, due August 2042			625						625
4.70%, due November 2042			475						475
5.00%, due March 2043			700						700
5.50%, due March 2044			750						750
5.40%, due September 2044			550						550
5.55%, due June 2045			1,750						1,750
5.05%, due February 2046			800						800
5.20%, due March 2048			750						750
3.25%, due August 2050			500						500
3.60%, due February 2051			1,050						1,050
5.45%, due August 2052			750						750
5.95% due August 2054			750						750
7.45%, due March 2098			26						26
TGP senior notes(b)
7.00%, due March 2027			300						300
7.00%, due October 2028			400						400
2.90%, due March 2030			1,000						1,000
8.375%, due June 2032			240						240
7.625%, due April 2037			300						300
EPNG senior notes(b)
7.50%, due November 2026			200						200
3.50%, due February 2032			300						300
8.375%, due June 2032			300						300
CIG senior notes(b)
4.15%, due August 2026			375						375
6.85%, due June 2037			100						100
EPC Building, LLC, promissory note, 3.967%, due January 2024 through December 2035			290						310
Trust I Preferred Securities, 4.75%, due March 2028(d)			221						221
Other miscellaneous debt(e)			159						205
Total debt – KMI and Subsidiaries			31,823						31,788
Less: Current portion of debt			1,226						2,009
Total long-term debt – KMI and Subsidiaries(f)			$	30,597					$	29,779

(a)Weighted average interest rates on borrowings at December 31, 2025 and 2024 were 3.85% and 4.60%, respectively.

(b)Notes provide for the redemption at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date plus a make whole premium and are subject to a number of restrictions and covenants. The most restrictive of these include limitations on the incurrence of liens and limitations on sale-leaseback transactions.

(c)Consists of senior notes denominated in Euros that have been converted to U.S. dollars and are respectively reported above at the December 31, 2025 exchange rate of 1.1746 U.S. dollars per Euro and at the December 31, 2024 exchange rate of 1.0354 U.S. dollars

per Euro. As of December 31, 2025 and 2024, the cumulative changes in the exchange rate of U.S. dollars per Euro since issuance had resulted in an increase of $44 million and a decrease of $25 million, respectively. As of December 31, 2025, we had outstanding associated cross-currency swap agreements which are designated as cash flow hedges.

(d)Capital Trust I (Trust I), is a 100%-owned business trust that as of December 31, 2025, had 4.4 million of 4.75% trust convertible preferred securities outstanding (referred to as the Trust I Preferred Securities). Trust I exists for the sole purpose of issuing preferred securities and investing the proceeds in 4.75% convertible subordinated debentures, which are due 2028. Trust I’s sole source of income is interest earned on these debentures. This interest income is used to pay distributions on the preferred securities. We provide a full and unconditional guarantee of the Trust I Preferred Securities. There are no significant restrictions from these securities on our ability to obtain funds from our subsidiaries by distribution, dividend, or loan. The Trust I Preferred Securities are non-voting (except in limited circumstances), pay quarterly distributions at an annual rate of 4.75%, and carry a liquidation value of $50 per security plus accrued and unpaid distributions. The Trust I Preferred Securities outstanding as of December 31, 2025 are convertible at any time prior to the close of business on March 31, 2028, at the option of the holder, into the following mixed consideration: (i) 0.7197 of a share of our Class P common stock; and (ii) $25.18 in cash without interest. We have the right to redeem these Trust I Preferred Securities at any time.

(e)Includes finance lease obligations with monthly installments. The lease terms expire between 2026 and 2070.

(f)Excludes our “Debt fair value adjustments” which, as of December 31, 2025 and 2024, increased our combined debt balances by $180 million and $102 million, respectively. In addition to all unamortized debt discount/premium amounts, debt issuance costs, and purchase accounting on our debt balances, our debt fair value adjustments also include amounts associated with the offsetting entry for hedged debt and any unamortized portion of proceeds received from the early termination of interest rate swap agreements. For further information about our debt fair value adjustments, see “—Debt Fair Value Adjustments” below.

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.

We and substantially all of our wholly owned domestic subsidiaries are party 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.

Current Portion of Debt

The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets:

						December 31,
						2025						2024
						(In millions)
$3.5 billion credit facility due August 20, 2027						$	—					$	—
Commercial paper notes						13						331
Current portion of senior notes
4.30%, due June 2025						—						1,500
4.15%, due August 2026						375						—
1.75%, due November 2026						500						—
7.50%, due November 2026						200						—
Trust I Preferred Securities, 4.75% due March 2028(a)						111						111
Current portion of other debt						27						67
Total current portion of debt						$	1,226					$	2,009

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

Credit Facility and Restrictive Covenants

We have a $3.5 billion revolving credit facility due August 2027 with a syndicate of lenders, which can be increased by up to $1.0 billion if certain conditions, including the receipt of additional lender commitments, are met. Borrowings under our credit facility can be used for working capital and other general corporate purposes and as backup to our commercial paper program.

We maintain a $3.5 billion commercial paper program through the private placement of short-term notes which matures in August 2027. The notes mature up to 270 days from the date of issue and are not redeemable or subject to voluntary prepayment by us prior to maturity. The notes are sold at par value less a discount representing an interest factor or if interest bearing, at par. Borrowings under our commercial paper program reduce the borrowings allowed under our credit facility.

Depending on the type of loan request, our borrowings under our credit facility bears interest at either (i) SOFR, plus (x) a credit spread adjustment and (y) an applicable margin ranging from 1.000% to 1.750% per annum based on our credit ratings or (ii) the greatest of (1) the Federal Funds Rate plus 0.5%; (2) the Prime Rate; or (3) SOFR for a one-month eurodollar loan, plus (x) a credit spread adjustment, (y) 1%, and (z) in each case, an applicable margin ranging from 0.100% to 0.750% 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 0.100% to 0.250%.

Our 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 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. Our credit facility also restricts our ability to make certain restricted payments if an event of default (as defined in the credit facility) has occurred and is continuing or would occur and be continuing.

As of December 31, 2025, we had no borrowings outstanding under our credit facility, $13 million borrowings outstanding under our commercial paper program, and $10 million in letters of credit. Our availability under our credit facility as of December 31, 2025 was approximately $3,477 million. For the years ended December 31, 2025, 2024, and 2023, we were in compliance with all required covenants.

Maturities of Debt

The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2025, are summarized as follows:

Year						Total
						(In millions)
2026						$	1,226
2027						942
2028						1,867
2029						1,781
2030						2,367
Thereafter						23,640
Total						$	31,823

Debt Fair Value Adjustments

The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:

						December 31,
						2025						2024
						(In millions)
Purchase accounting debt fair value adjustments						$	337					$	385
Carrying value adjustment to hedged debt						(101)						(241)
Unamortized portion of proceeds received from the early termination of interest rate swap agreements						149						167
Unamortized debt discounts, net						(67)						(70)
Unamortized debt issuance costs						(138)						(139)
Total debt fair value adjustments						$	180					$	102

Fair Value of Financial Instruments

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

			December 31, 2025												December 31, 2024
			Carrying value						Estimated fair value(a)						Carrying value						Estimated fair value(a)
			(In millions)
Total debt			$	32,003					$	31,966					$	31,890					$	30,794

(a)Included in the estimated fair value are amounts for our Trust I Preferred Securities of $217 million and $201 million as of December 31, 2025 and 2024, respectively.

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

Interest Rates, Interest Rate Swaps and Contingent Debt

The weighted average interest rate on all of our borrowings was 5.59% during 2025 and 5.83% during 2024. Information on our interest rate swaps is contained in Note 13. For information about our contingent debt agreements, see Note 12 “Commitments and Contingent Liabilities*—Contingent Debt.*”

9. Share-based Compensation and Employee Benefits

Share-based Compensation

Class P Common Stock

Following is a summary of our stock compensation plans:

						Directors’ Plan						Long Term Incentive Plan
Participating individuals						Eligible non-employee directors						Eligible employees
Total number of shares of Class P common stock authorized						1,190,000						63,000,000
Vesting period						6 months						1 year to 10 years

Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors

We have a Kinder Morgan, Inc. Second Amended and Restated Stock Compensation Plan for Non-Employee Directors (Directors’ Plan). The plan recognizes that the compensation paid to each eligible non-employee director is fixed by our board of directors (Board), generally annually, and that the compensation is payable in cash. Pursuant to the plan, in lieu of receiving some or all of the cash compensation, each eligible non-employee director may elect annually to receive shares of Class P common stock. During the year ended December 31, 2025, we made restricted Class P common stock grants to our non-employee directors of 9,620.

Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan

We also have a Kinder Morgan, Inc. 2021 Amended and Restated Stock Incentive Plan (Long Term Incentive Plan). The following table sets forth a summary of activity and related balances under our Long Term Incentive Plan:

			Shares						Weighted Average Grant Date Fair Value per Share
			(In thousands, except per share amounts)
Outstanding at December 31, 2024			13,405						$	18.30
Granted			3,420						27.97
Vested			(4,573)						17.50
Forfeited			(409)						19.00
Outstanding at December 31, 2025			11,843						$	21.38

The following tables set forth additional information related to our Long Term Incentive Plan:

			Year Ended December 31,
			2025						2024						2023
			(In millions, except per share amounts)
Weighted average grant date fair value per share			$	27.97					$	20.27					$	17.41
Intrinsic value of awards vested during the year			128						70						93
Restricted stock awards expense(a)			68						64						60
Restricted stock awards capitalized(a)			11						10						9
(a)The above amounts represents total compensation costs and we allocate labor and benefit costs to joint ventures that we operate in accordance with our partnership agreements.
									December 31, 2025
Unrecognized restricted stock awards compensation costs, less estimated forfeitures (in millions)															$	132
Weighted average remaining amortization period															2.04 years

Pension and Other Postretirement Benefit (OPEB) Plans

Savings Plan

We maintain a defined contribution plan covering eligible U.S. employees. We contribute 5% of eligible compensation for most of the plan participants. Certain collectively bargained participants receive Company contributions in accordance with collective bargaining agreements. A participant becomes fully vested in Company contributions after two years and may take a distribution upon termination of employment or retirement. The total cost for our savings plan was approximately $58 million, $56 million, and $53 million for the years ended December 31, 2025, 2024, and 2023, respectively.

Pension Plans

Our pension plans are defined benefit plans that cover substantially all of our U.S. employees and provide benefits under a cash balance formula. A participant in the cash balance formula accrues benefits through contribution credits based on a combination of age and years of service, multiplied by eligible compensation. Interest is also credited to the participant’s plan account. A participant becomes fully vested in the plan after three years and may take a lump sum or annuity distribution upon termination of employment or retirement. Certain collectively bargained and grandfathered employees accrue benefits through career pay or final pay formulas.

OPEB Plans

We and certain of our subsidiaries provide OPEB benefits, including medical benefits for closed groups of retired employees and certain grandfathered employees and their dependents, and limited postretirement life insurance benefits for retired employees. These plans provide a fixed subsidy to post-age 65 Medicare eligible participants to purchase coverage through a retiree Medicare exchange. Medical benefits under these OPEB plans may be subject to deductibles, co-payment provisions, dollar caps and other limitations on the amount of employer costs, and we reserve the right to change these benefits.

Benefit Obligation, Plan Assets and Funded Status. The following table provides information about our pension and OPEB plans as of and for each of the years ended December 31, 2025 and 2024:

			Pension Benefits												OPEB
			2025						2024						2025						2024
			(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period			$	1,809					$	1,902					$	169					$	177
Service cost			50						52						1						1
Interest cost			91						91						8						8
Actuarial loss (gain)			27						(82)						7						8
Benefits paid			(163)						(154)						(24)						(26)
Participant contributions			—						—						1						1
Benefit obligation at end of period			1,814						1,809						162						169
Change in plan assets:
Fair value of plan assets at beginning of period			1,614						1,562						331						323
Actual return on plan assets			183						156						44						33
Employer contributions			50						50						—						—
Participant contributions			—						—						1						1
Benefits paid			(163)						(154)						(24)						(26)
Fair value of plan assets at end of period			1,684						1,614						352						331
Funded status - net (liability) asset at December 31,			$	(130)					$	(195)					$	190					$	162
Amounts recognized in the consolidated balance sheets:
Non-current benefit asset(a)			$	—					$	—					$	303					$	278
Current benefit liability			—						—						(15)						(14)
Non-current benefit liability			(130)						(195)						(98)						(102)
Funded status - net (liability) asset at December 31,			$	(130)					$	(195)					$	190					$	162
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:
Unrecognized net actuarial (loss) gain			$	(176)					$	(230)					$	139					$	139
Unrecognized prior service credit			—						—						1						2
Accumulated other comprehensive (loss) income			$	(176)					$	(230)					$	140					$	141
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:
Accumulated benefit obligation			$	1,268					$	1,782					$	113					$	117
Fair value of plan assets			1,165						1,614						—						2

(a)2025 and 2024 OPEB amounts include $68 million and $59 million, respectively, of non-current benefit assets related to a plan we sponsor which is associated with employee services provided to an unconsolidated joint venture, and for which we have recorded an offsetting related party deferred credit.

The 2025 net actuarial loss for the pension plans was primarily due to a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2025. The 2025 net actuarial loss for the OPEB plans was primarily due to changes in the claims cost assumption and a decrease in the weighted average discount rate used to determine the benefit obligation as of December 31, 2025. The 2024 net actuarial gain for the pension plans was primarily due to an increase in the weighted average discount rate used to determine the benefit obligation as of December 31, 2024. The 2024 net actuarial loss for the OPEB plans was primarily due to changes in the claims cost and trend assumptions.

Plan Assets. The investment policies and strategies are established by our plan’s fiduciary committee for the assets of each of the pension and OPEB plans, which are responsible for investment decisions and management oversight of the plans. The stated philosophy of the fiduciary committee is to manage these assets in a manner consistent with the purpose for which the plans were established and the time frame over which the plans’ obligations need to be met. The objectives of the investment management program are to (i) meet or exceed plan actuarial earnings assumptions over the long term and (ii) provide a reasonable return on assets within established risk tolerance guidelines and to maintain the liquidity needs of the plans with the goal of paying benefit and expense obligations when due. In seeking to meet these objectives, the fiduciary committee recognizes that prudent investing requires taking reasonable risks in order to raise the likelihood of achieving the targeted investment returns. In order to reduce portfolio risk and volatility, the fiduciary committee has adopted a strategy of using multiple asset classes.

The allowable range for asset allocations in effect for our plans as of December 31, 2025, by asset category, are as follows:

						Pension Benefits						OPEB
Cash												0% to 23%
Equities						42% to 52%						43% to 71%
Fixed income securities						37% to 47%						26% to 50%
Real estate						2% to 12%
Company securities (KMI Class P common stock and/or debt securities)						0% to 10%

Below are the details of our pension and OPEB plan assets by class and a description of the valuation methodologies used for assets measured at fair value.

• Level 1 assets’ fair values are based on quoted market prices for the instruments in actively traded markets. Included in this level are equities. These investments are valued at the closing price reported on the active market on which the individual securities are traded.

• Level 2 assets’ fair values are primarily based on pricing data representative of quoted prices for similar assets in active markets (or identical assets in less active markets). Included in this level are short-term investment funds, fixed income securities and derivatives. Short-term investment funds are valued at amortized cost, which approximates fair value. The fixed income securities’ fair values are primarily based on an evaluated price which is based on a compilation of primarily observable market information or a broker quote in a non-active market. Derivatives are exchange-traded through clearinghouses and are valued based on these prices.

• Plan assets with fair values that are based on the net asset value per share, or its equivalent (NAV), as a practical expedient to measure fair value, as reported by the issuers are determined based on the fair value of the underlying securities as of the valuation date and include common/collective trust funds, real estate, and short-term investment funds. The plan assets measured at NAV are not categorized within the fair value hierarchy described above but are separately identified in the following tables.

Listed below are the fair values of our pension and OPEB plans’ assets that are recorded at fair value by class and categorized by fair value measurement used at December 31, 2025 and 2024:

			Pension Assets
			2025																		2024
			Level 1						Level 2						Total						Level 1						Level 2						Total
			(In millions)
Measured within fair value hierarchy
Equities(a)			$	147					$	—					$	147					$	203					$	—					$	203
Fixed income securities			—						426						426						—						380						380
Subtotal			$	147					$	426					573						$	203					$	380					583
Measured at NAV
Common/collective trusts(b)															1,084																		1,002
Short-term investment funds															27																		29
Subtotal															1,111																		1,031
Total plan assets fair value															$	1,684																	$	1,614

(a)Plan assets include $118 and $167 of KMI Class P common stock for 2025 and 2024, respectively.

(b)Common/collective trust funds were invested in approximately 65% equities, 23% fixed income securities, and 12% real estate in 2025 and 66% equities, 22% fixed income securities, and 12% real estate in 2024.

			OPEB Assets
			2025																		2024
			Level 1						Level 2												Total						Level 1						Level 2												Total
			(In millions)
Measured within fair value hierarchy
Short-term investment funds			$	—					$	4											$	4					$	—					$	3											$	3
Measured at NAV
Common/collective trusts(a)																					348																								328
Total plan assets fair value																					$	352																							$	331

(a)Common/collective trust funds were invested in approximately 63% equities and 37% fixed income securities for 2025, and 62% equities and 38% fixed income securities for 2024.

Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2025, we expect the following cash flows under our plans:

						Pension Benefits						OPEB
						(In millions)
Contributions expected in 2026						$	60					$	—
Benefit payments expected in:
2026						$	191					$	22
2027						186						21
2028						181						19
2029						177						18
2030						170						16
2031 - 2035						755						62

Actuarial Assumptions. Benefit obligations and net benefit cost are based on actuarial estimates and assumptions. The following table details the weighted-average actuarial assumptions used in determining our benefit obligation as of December 31, 2025 and 2024 and net benefit costs of our pension and OPEB plans for 2025, 2024, and 2023:

																		Pension Benefits												OPEB
																		2025						2024						2025						2024
Assumptions related to benefit obligations:
Discount rate																		5.32		%				5.58		%				5.02		%				5.44		%
Rate of compensation increase																		3.50		%				3.50		%				n/a						n/a
Interest crediting rate																		3.85		%				3.78		%				n/a						n/a
						Pension Benefits																		OPEB
						2025						2024						2023						2025						2024						2023
Assumptions related to benefit costs:
Discount rate						5.58		%				5.13		%				5.41		%				5.44		%				5.08		%				5.38		%
Expected return on plan assets						7.00		%				7.00		%				7.00		%				6.00		%				6.00		%				6.00		%
Rate of compensation increase						3.50		%				3.50		%				3.50		%				n/a						n/a						n/a
Interest crediting rate						3.78		%				3.85		%				3.50		%				n/a						n/a						n/a

We utilize a full yield curve approach in estimating the service and interest cost components of net periodic benefit cost (credit) for our retirement benefit plans by applying the specific spot rates along the yield curve used in the determination of the benefit obligation to their underlying projected cash flows. The expected long-term rates of return on plan assets were determined by combining a review of the historical returns realized within the portfolio, the investment strategy included in the plans’ investment policy, and capital market projections for the asset classes in which the portfolio is invested and the target weightings of each asset class. The expected return on plan assets listed in the table above is a pre-tax rate of return based on our targeted portfolio of investments. For the OPEB assets subject to unrelated business income taxes, we utilize an after-tax expected return on plan assets to determine our benefit costs.

Actuarial estimates for our OPEB plans assume an annual increase in the per capita cost of covered health care benefits. The initial annual rate of increase is 7.60% which gradually decreases to 4.00% by the year 2050.

Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income. For each of the years ended December 31, the components of net benefit cost and other amounts recognized in pre-tax other comprehensive income related to our pension and OPEB plans are as follows:

						Pension Benefits																		OPEB
						2025						2024						2023						2025						2024						2023
						(In millions)
Components of net benefit cost (credit):
Service cost						$	50					$	52					$	55					$	1					$	1					$	1
Interest cost						91						91						107						8						8						10
Expected return on assets						(109)						(106)						(117)						(15)						(14)						(13)
Amortization of prior service cost (credit)						—						—						1						(1)						(3)						(3)
Amortization of net actuarial loss (gain)						8						22						35						(16)						(17)						(16)
Settlement loss						—						—						46						—						—						—
Net benefit cost (credit)						40						59						127						(23)						(25)						(21)
Other changes in plan assets and benefit obligations recognized in OCI:
Net (gain) loss arising during period						(46)						(132)						10						(15)						(6)						(30)
Amortization or settlement recognition of net actuarial (loss) gain						(8)						(22)						(81)						15						16						16
Amortization of prior service (cost) credit						—						—						(1)						1						1						1
Total recognized in OCI(a)						(54)						(154)						(72)						1						11						(13)
Total recognized in net benefit cost (credit) and OCI						$	(14)					$	(95)					$	55					$	(22)					$	(14)					$	(34)

(a)Excludes $(1) million and $1 million for the years ended December 31, 2025 and 2024, respectively, associated with other plans.

10.			Stockholders’ Equity

Class P Common Stock

We have a board-approved share buy-back program that authorizes share repurchases of up to $3 billion that began in December 2017. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows:

						Year Ended December 31,
						2025						2024						2023
			(In millions, except per share amounts)
Total value of shares repurchased						$	—					$	7					$	522
Total number of shares repurchased(a)						—						1						32
Average repurchase price per share						$	—					$	16.50					$	16.56

(a)For the year ended December 31, 2024, we repurchased less than 1 million of our shares.

Since December 2017, in total, we have repurchased 86 million of our shares under the program at an average price of $17.09 per share for $1,472 million, leaving capacity under the program of $1.5 billion.

On December 19, 2014, we entered into an equity distribution agreement authorizing us to issue and sell through or to the managers party thereto, as sales agents and/or principals, shares having an aggregate offering price of up to $5 billion from time to time during the term of this agreement. During the years ended December 31, 2025, 2024, and 2023 we did not issue any shares under this agreement.

Dividends

The following table provides information about our per share dividends:

			Year Ended December 31,
			2025						2024						2023
Per share cash dividend declared for the period			$	1.17					$	1.15					$	1.13
Per share cash dividend paid in the period			1.1650						1.1450						1.1250

On January 21, 2026, our Board declared a cash dividend of $0.2925 per share for the quarterly period ended December 31, 2025, which is payable on February 17, 2026 to shareholders of record as of the close of business on February 2, 2026.

Accumulated Other Comprehensive (Loss) Income

Changes in the components of our “Accumulated other comprehensive (loss) income” 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)income
			(In millions)
Balance at December 31, 2022			$	(164)											$	(238)					$	(402)
Other comprehensive gain before reclassifications			155												65						220
Gains reclassified from accumulated other comprehensive loss			(35)												—						(35)
Net current-period change in accumulated other comprehensive loss			120												65						185
Balance at December 31, 2023			(44)												(173)						(217)
Other comprehensive (loss) gain before reclassifications			(29)												111						82
Losses reclassified from accumulated other comprehensive loss			40												—						40
Net current-period change in accumulated other comprehensive loss			11												111						122
Balance at December 31, 2024			(33)												(62)						(95)
Other comprehensive gain before reclassifications			184												40						224
Gains reclassified from accumulated other comprehensive loss			(84)												—						(84)
Net current-period change in accumulated other comprehensive income			100												40						140
Balance at December 31, 2025			$	67											$	(22)					$	45

11. Related Party Transactions

Affiliate Balances and Activities

In the course of our normal operations, we provide services to and obtain services from affiliates which consist of (i) unconsolidated affiliates in which we hold an investment accounted for under the equity method of accounting (see Note 6 for additional information related to these investments); and (ii) external partners of our joint ventures we consolidate.

The following tables summarize our affiliate balance sheet balances and income statement activity, other than amounts reported within our “Investments” balances and “Earnings from equity investments” activity:

			December 31,
			2025						2024
			(In millions)
Balance sheet location
Accounts receivable			$	54					$	48
Other current assets			4						1
			$	58					$	49
Current portion of debt			$	5					$	5
Accounts payable			20						21
Other current liabilities			7						8
Long-term debt			127						132
Other long-term liabilities and deferred credits			69						60
			$	228					$	226

			Year Ended December 31,
			2025						2024						2023
			(In millions)
Income statement location
Revenues			$	349					$	346					$	172
Operating Costs, Expenses, and Other
Costs of sales			$	177					$	145					$	132
Other operating expenses			101						69						57

12. Commitments and Contingent Liabilities

Capital Commitments

As of December 31, 2025, we had capital commitments of approximately $2,020 million. We have other planned capital and investment projects that are discretionary in nature, with no substantial contractual capital commitments made in advance of the actual expenditures.

Rights-Of-Way

Our rights-of-way obligations primarily consist of non-lease agreements that existed at the time of Topic 842*, Leases,* adoption, at which time we elected a practical expedient which allowed us to continue our historical treatment. Our future minimum rental commitments related to our rights-of-way obligations were $96 million as of December 31, 2025.

Contingent Debt

Our contingent debt disclosures pertain to certain types of guarantees or indemnifications we have made and cover certain types of guarantees included within debt agreements, even if the likelihood of requiring our performance under such guarantee is remote.

As of December 31, 2025 and 2024, our contingent debt obligations totaled $127 million and $149 million, respectively. These amounts include our proportional share of the debt obligations of one equity investee, Cortez Pipeline Company (Cortez). Under such guarantees we are severally liable for our percentage ownership share of Cortez’s debt in the event of its non-performance. The contingent debt obligations balances as of December 31, 2025 and 2024 also include $91 million and $120 million, respectively, of debt issued by a subsidiary of Cortez that is 100% guaranteed by us.

Guarantees and Indemnifications

We are involved in joint ventures and other ownership arrangements that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. These arrangements include, but are not limited to, indemnifications for income taxes, the resolution of existing disputes, and environmental matters.

While many of these agreements may specify a maximum potential exposure, or a specified duration to the indemnification obligation, there are also circumstances where the amount and duration are unlimited. Other than with our rights-of-way obligations and contingent debt described above, we are currently not subject to any material requirements to perform under quantifiable arrangements. We are unable to estimate a maximum exposure for our other guarantee and indemnification agreements that do not provide for limits on the amount of future payments due to the uncertainty of these exposures.

See Note 17 for a description of matters that we have identified as contingencies requiring accrual of liabilities and/or disclosure, including any such matters arising under guarantee or indemnification agreements.

13. 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 December 31, 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			(13.8)			MMBbl
Derivatives not designated as hedging contracts
Crude oil fixed price			(0.8)			MMBbl
Crude oil basis			(0.9)			MMBbl
Natural gas fixed price			(63.0)			Bcf
Natural gas basis			(77.3)			Bcf
NGL fixed price			(1.2)			MMBbl

As of December 31, 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 December 31, 2025:

						Notional amount									Accounting treatment						Maximum term
						(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)						$	3,500								Fair value hedge						August 2035

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

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 December 31, 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 in our accompanying consolidated balance sheets:

Fair Value of Derivative Contracts
			Location						Derivatives Asset												Derivatives Liability
									December 31,												December 31,
									2025						2024						2025						2024
									(In millions)
Derivatives designated as hedging instruments
Energy commodity derivative contracts
			Other current assets/(Other current liabilities)						$	56					$	10					$	—					$	(46)
			Deferred charges and other assets/(Other long-term liabilities and deferred credits)						36						9						—						(8)
			Subtotal						92						19						—						(54)
Interest rate contracts
			Other current assets/(Other current liabilities)						4						1						(25)						(51)
			Deferred charges and other assets/(Other long-term liabilities and deferred credits)						32						19						(111)						(203)
			Subtotal						36						20						(136)						(254)
Foreign currency contracts
			Other current assets/(Other current liabilities)						—						—						(2)						(3)
			Deferred charges and other assets/(Other long-term liabilities and deferred credits)						41						—						—						(26)
			Subtotal						41						—						(2)						(29)
			Total						169						39						(138)						(337)
Derivatives not designated as hedging instruments
Energy commodity derivative contracts
			Other current assets/(Other current liabilities)						75						14						(74)						(35)
			Deferred charges and other assets/(Other long-term liabilities and deferred credits)						4						1						(1)						(15)
			Subtotal						79						15						(75)						(50)
Interest rate contracts
			Other current assets/(Other current liabilities)						—						4						—						—
			Deferred charges and other assets/(Other long-term liabilities and deferred credits)						—						4						—						(2)
			Subtotal						—						8						—						(2)
			Total						79						23						(75)						(52)
Total derivatives									$	248					$	62					$	(213)					$	(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
			Level 1						Level 2						Level 3						Gross amount						Contracts available for netting						Cash collateral held(a)						Net amount
			(In millions)
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
As of December 31, 2024
Energy commodity derivative contracts(b)			$	6					$	29					$	—					$	35					$	(19)					$	—					$	16
Interest rate contracts			—						27						—						27						—						—						27
Foreign currency contracts			—						—						—						—						—						—						—

			Balance sheet liability fair value measurements by level
			Level 1						Level 2						Level 3						Gross amount						Contracts available for netting						Cash collateral posted(a)						Net amount
			(In millions)
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)
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 in 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
												Year Ended December 31,
												2025						2024						2023
												(In millions)
Interest rate contracts						Interest, net						$	132					$	(3)					$	138
Hedged fixed rate debt(a)						Interest, net						$	(140)					$	5					$	(132)

(a)As of December 31, 2025, the cumulative amount of fair value hedging adjustments resulted in a decrease of $101 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(b)
						Year Ended																								Year Ended
						December 31,																								December 31,
						2025						2024						2023												2025						2024						2023
						(In millions)																								(In millions)
Energy commodity derivative contracts						$	171					$	(26)					$	182					Revenues—Commodity sales						$	47					$	7					$	103
																								Costs of sales						(6)						(29)						(73)
Interest rate contracts						—						13						(10)						Interest, net						—						4						—
Foreign currency contracts						67						(24)						30						Other, net						69						(34)						17
Total						$	238					$	(37)					$	202					Total						$	110					$	(52)					$	47

(a)We expect to reclassify an approximately $63 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive income balance as of December 31, 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
												Year Ended December 31,
												2025						2024						2023
												(In millions)
Energy commodity derivative contracts						Revenues—Commodity sales						$	79					$	20					$	75
						Costs of sales						(61)						(89)						100
						Earnings from equity investments						1						—						2
Interest rate contracts						Interest, net						(5)						3						1
Total(a)												$	14					$	(66)					$	178

(a)The years ended December 31, 2025, 2024, and 2023 include approximate (losses) gains of $(3) million, $8 million, and $58 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 December 31, 2025 and 2024, we had no outstanding letters of credit supporting our commodity price risk management program. As of December 31, 2025 and 2024 we had cash margins of $24 million and $104 million, respectively, posted with our counterparties by us and reported within “Restricted deposits” on our accompanying consolidated balance sheet. The cash margin balance at December 31, 2025 represents the initial margin requirements of $26 million, offset by variation margin requirements of $2 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 December 31, 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.

14. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by segment, revenue source, and type of revenue for each revenue source. Refer to Note 2 for further information.

						Year Ended December 31, 2025
						Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
						(In millions)
Revenues from contracts with customers(a)
Services
Firm services						$	4,254					$	221					$	870					$	1					$	(4)					$	5,342
Fee-based services						1,161						1,090						431						45						(8)						2,719
Total services						5,415						1,311						1,301						46						(12)						8,061
Commodity sales
Natural gas sales						3,909						—						—						49						(9)						3,949
Product sales						1,001						1,157						56						857						(8)						3,063
Other sales						29						—						—						103						(3)						129
Total commodity sales						4,939						1,157						56						1,009						(20)						7,141
Total revenues from contracts with customers						10,354						2,468						1,357						1,055						(32)						15,202
Other revenues
Leasing services(b)						455						192						747						70						—						1,464
Derivatives adjustments on commodity sales						96						—						—						30						—						126
Other						104						26						—						15						—						145
Total other revenues						655						218						747						115						—						1,735
Total revenues						$	11,009					$	2,686					$	2,104					$	1,170					$	(32)					$	16,937

						Year Ended December 31, 2024
						Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
						(In millions)
Revenues from contracts with customers(a)
Services
Firm services						$	3,893					$	220					$	846					$	2					$	(4)					$	4,957
Fee-based services						1,044						1,059						460						41						(7)						2,597
Total services						4,937						1,279						1,306						43						(11)						7,554
Commodity sales
Natural gas sales						2,303						—						—						43						(6)						2,340
Product sales						965						1,444						50						1,031						(4)						3,486
Other sales						20						—						—						85						(2)						103
Total commodity sales						3,288						1,444						50						1,159						(12)						5,929
Total revenues from contracts with customers						8,225						2,723						1,356						1,202						(23)						13,483
Other revenues
Leasing services(b)						459						209						666						66						—						1,400
Derivatives adjustments on commodity sales						113						(1)						—						(85)						—						27
Other						145						24						—						21						—						190
Total other revenues						717						232						666						2						—						1,617
Total revenues						$	8,942					$	2,955					$	2,022					$	1,204					$	(23)					$	15,100

						Year Ended December 31, 2023
						Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
						(In millions)
Revenues from contracts with customers(a)
Services
Firm services						$	3,543					$	171					$	819					$	1					$	3					$	4,537
Fee-based services						1,008						1,036						427						40						(9)						2,502
Total services						4,551						1,207						1,246						41						(6)						7,039
Commodity sales
Natural gas sales						2,631						—						—						43						(8)						2,666
Product sales						1,110						1,635						33						1,114						(8)						3,884
Other sales						20						—						—						42						(4)						58
Total commodity sales						3,761						1,635						33						1,199						(20)						6,608
Total revenues from contracts with customers						8,312						2,842						1,279						1,240						(26)						13,647
Other revenues
Leasing services(b)						475						200						638						55						—						1,368
Derivatives adjustments on commodity sales						285						—						—						(107)						—						178
Other						96						24						—						21						—						141
Total other revenues						856						224						638						(31)						—						1,687
Total revenues						$	9,168					$	3,066					$	1,917					$	1,209					$	(26)					$	15,334

(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 December 31, 2025 and 2024, our contract asset balances were $30 million and $15 million, respectively, and our contract liability balances were $459 million and $377 million, respectively. Of the December 31, 2024 contract asset and liability balances, $8 million was transferred to accounts receivable and $78 million was recognized as revenue during the year 2025, 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 $531 million and $587 million as of December 31, 2025 and 2024, 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:

						2026						2027						2028 and thereafter
						(In billions)
Estimated revenue as of December 31, 2025						$	5					$	5					$	26

Based on the practical expedients 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.

15. Reportable Segments

Our reportable business segments are:

• Natural Gas Pipelines—the ownership and operation of (i) major interstate and intrastate natural gas pipeline and storage systems; (ii) natural gas gathering systems and natural gas processing and treating facilities; (iii) NGL fractionation facilities and transportation systems; and (iv) LNG regasification, liquefaction, and storage facilities;

• Products Pipelines—the ownership and operation of refined petroleum products, crude oil, and condensate pipelines that primarily deliver, among other products, gasoline, diesel and jet fuel, crude oil, renewable fuels, and condensate to various markets, plus the ownership and/or operation of associated product terminals and petroleum pipeline transmix facilities;

• Terminals—the ownership and/or operation of (i) liquids and bulk terminal facilities located throughout the U.S. that store and handle various commodities including gasoline, diesel fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks; and (ii) Jones Act-qualified tankers;

• CO2—(i) the production, transportation, and marketing of CO2 to oil fields that use CO2 as a flooding medium to increase recovery and production of crude oil from mature oil fields; (ii) ownership interests in and/or operation of oil fields and gasoline processing plants in West Texas; (iii) the ownership and operation of a crude oil pipeline system in West Texas; and (iv) the ownership and operation of RNG and LNG facilities.

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 including amortization of excess cost of equity investments (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.

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 years ended December 31, 2025, 2024, and 2023, and therefore is included within Segment EBDA. As a result, Segment EBDA for the years ended December 31, 2024 and 2023 have been adjusted to conform to the current presentation in the tables below.

During 2025, 2024, and 2023, we did not have revenues from any single external customer that exceeded 10% of our consolidated revenues.

Financial information by segment follows:

			Year Ended December 31, 2025
			Reportable Segments
			Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
			(In millions)
Revenues
Revenues from external customers			$	10,990					$	2,686					$	2,094					$	1,167					$	—					$	16,937
Intersegment revenues			19						—						10						3						(32)						—
Total revenues			11,009						2,686						2,104						1,170						(32)						16,937
Costs of sales			(4,299)						(1,112)						(50)						(94)
Labor			(331)						(132)						(282)						(53)
Fuel and power			(87)						(90)						(20)						(141)
Field - non-labor(a)			(901)						(209)						(558)						(242)
Taxes, other than income taxes			(287)						(45)						(55)						(51)
Earnings (loss) from equity investments			817						58						(2)						23
Other segment items(b)			159						1						6						—
Total Segment EBDA(c)			$	6,080					$	1,157					$	1,143					$	612											8,992
DD&A																																	(2,453)
General and administrative and corporate charges																																	(746)
Interest, net(d)																																	(1,801)
Income tax expense																																	(832)
Net income																																	$	3,160
Other segment activity information:
DD&A			$	1,173					$	358					$	518					$	378					$	26					$	2,453
Capital expenditures			2,092						242						326						328						38						3,026
Segment balance sheet information:
Investments			6,962						381						122						67						—						7,532
Other intangibles, net			900						403						13						414						—						1,730
Total assets(e)			52,546						8,044						7,917						3,608						633						72,748

			Year Ended December 31, 2024
			Reportable Segments
			Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
			(In millions)
Revenues
Revenues from external customers			$	8,930					$	2,955					$	2,013					$	1,202					$	—					$	15,100
Intersegment revenues			12						—						9						2						(23)						—
Total revenues			8,942						2,955						2,022						1,204						(23)						15,100
Costs of sales			(2,837)						(1,394)						(42)						(82)
Labor			(322)						(128)						(273)						(50)
Fuel and power			(74)						(92)						(20)						(153)
Field - non-labor(a)			(854)						(193)						(558)						(241)
Taxes, other than income taxes			(269)						(43)						(53)						(60)
Earnings from equity investments			748						57						8						27
Other segment items(b)			59						2						15						40
Total Segment EBDA(f)(g)			$	5,393					$	1,164					$	1,099					$	685											8,341
DD&A																																	(2,354)
General and administrative and corporate charges																																	(736)
Interest, net(d)																																	(1,844)
Income tax expense																																	(687)
Net income																																	$	2,720
Other segment activity information:
DD&A			$	1,105					$	365					$	508					$	354					$	22					$	2,354
Capital expenditures			1,654						210						385						346						34						2,629
Segment balance sheet information:
Investments			7,252						387						132						74						—						7,845
Other intangibles, net			687						597						18						458						—						1,760
Total assets(e)			50,402						8,639						8,086						3,583						697						71,407

			Year Ended December 31, 2023
			Reportable Segments
			Natural Gas Pipelines						Products Pipelines						Terminals						CO****2						Corporate and Eliminations						Total
			(In millions)
Revenues
Revenues from external customers			$	9,152					$	3,066					$	1,911					$	1,205					$	—					$	15,334
Intersegment revenues			16						—						6						4						(26)						—
Total revenues			9,168						3,066						1,917						1,209						(26)						15,334
Costs of sales			(3,258)						(1,588)						(33)						(77)
Labor			(300)						(121)						(254)						(49)
Fuel and power			(79)						(88)						(19)						(137)
Field - non-labor(a)			(801)						(185)						(535)						(232)
Taxes, other than income taxes			(262)						(42)						(55)						(55)
Earnings (loss) from equity investments			746						(6)						9						23
Other segment items(b)			38						(3)						10						—
Total Segment EBDA(g)(h)			$	5,252					$	1,033					$	1,040					$	682											8,007
DD&A																																	(2,250)
General and administrative and corporate charges																																	(759)
Interest, net(d)																																	(1,797)
Income tax expense																																	(715)
Net income																																	$	2,486
Other segment activity information:
DD&A			$	1,041					$	367					$	493					$	325					$	24					$	2,250
Capital expenditures			1,299						221						406						355						36						2,317

(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 of $37 million, $(1) million, and $4 million for our Natural Gas Pipelines, Products Pipelines, and CO2 business segments, respectively.

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

(e)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.

(f)Includes non-cash mark-to-market derivative hedge contract gain (loss) amounts of $(75) million and $(2) million for our Natural Gas Pipelines and CO2 business segments, respectively.

(g)Segment EBDA previously reported (before reclassifications) for the years ended December 31, 2024 and 2023 were $5,427 million and $5,282 million, $1,173 million and $1,062 million, $1,099 million and $1,040 million, and $692 million and $689 million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, and CO2 business segments, respectively.

(h)Includes non-cash mark-to-market derivative hedge contract gain (loss) amounts of $122 million, $1 million and $(4) million for our Natural Gas Pipelines, Products Pipelines and CO2 business segments, respectively.

Following is geographic information regarding the revenues and long-lived assets of our business:

			Year Ended December 31,
			2025						2024						2023
			(In millions)
Revenues from external customers
U.S.			$	16,926					$	15,057					$	15,255
Mexico			11						43						79
Total consolidated revenues from external customers			$	16,937					$	15,100					$	15,334

			December 31,
			2025						2024						2023
			(In millions)
Long-term assets, excluding goodwill and other intangibles
U.S.			$	48,115					$	46,972					$	46,328
Mexico			65						70						72
Total consolidated long-lived assets			$	48,180					$	47,042					$	46,400

16. Leases

Following are components of our lease cost:

			Year Ended December 31,
			2025						2024						2023
			(In millions)
Operating leases			$	74					$	80					$	71
Short-term and variable leases			152						131						127
Total lease cost			$	226					$	211					$	198

Other information related to our operating leases are as follows:

			Year Ended December 31,
			2025						2024						2023
			(In millions, except lease term and discount rate)
Operating cash flows from operating leases			$	(158)					$	(170)					$	(157)
Investing cash flows from operating leases			(68)						(41)						(41)
ROU assets obtained in exchange for operating lease obligations, net of retirements			25						36						56
Amortization of ROU assets			62						68						58
Weighted average remaining lease term			8.06 years						8.15 years						8.72 years
Weighted average discount rate			4.85		%				4.84		%				4.59		%

Amounts recognized in the accompanying consolidated balance sheets are as follows:

						December 31,
Lease Activity(a)			Balance sheet location			2025						2024
						(In millions)
ROU assets			Deferred charges and other assets			$	216					$	253
Short-term lease liability			Other current liabilities			49						60
Long-term lease liability			Other long-term liabilities and deferred credits			167						193

(a)We have immaterial financing leases recorded as of December 31, 2025 and 2024.

Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2025 are as follows:

Year			Commitment
			(In millions)
2026			$	59
2027			41
2028			27
2029			25
2030			21
Thereafter			105
Total lease payments			278
Less: Interest			(62)
Present value of lease liabilities			$	216

Short-term lease costs are not material to us and are anticipated to be similar to the current year short-term lease expense outlined in this disclosure.

17. 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 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 consisting of 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 on appeal, 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 on September 15, 2023. The Appellate Division affirmed the entry of summary judgment in GLNG’s favor. On September 16, 2025, the Court of Appeals denied Eni S.p.A.’s motion for leave to appeal, thereby terminating Eni S.p.A.’s recourse in state court against GLNG. On December 15, 2025, Eni S.p.A. filed a petition for writ of certiorari to the United States Supreme Court, which 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 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 Claims III, IV, and V. Plaintiffs seek equitable and other relief including early retirement benefits, monetary damages, or other equitable relief estimated to be in excess of $100 million. We vigorously oppose the form and scope of relief sought by the plaintiffs and believe we have numerous and substantial defenses to support our vigorous defense at the trial or appellate levels if necessary. 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. Plaintiffs may object to the Recommendation within 14 days, and 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 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 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 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 SLCRMA and Louisiana law, and caused substantial damage to the coastal waters and nearby lands. Orleans sought unspecified money damages, attorney fees, interest, and restoration costs. On February 28, 2024, after the case was removed to federal court, the U.S. District Court for the Eastern District of Louisiana entered partial final judgment dismissing a co-defendant and stayed the case pending an appeal by Orleans to the U.S. Court of Appeals for the Fifth Circuit. On January 23, 2025, the U.S. Court of Appeals for the Fifth Circuit affirmed the U.S. District Court’s judgment, thereby retaining jurisdiction and dismissing a co-defendant on the basis that SLCRMA does not apply to a co-defendant’s pipeline constructed prior to the regulation’s effective date. Considering this ruling and that SNG’s pipelines were constructed prior to the regulation’s effective date, SNG filed a motion for summary judgment seeking to be dismissed on the same basis. Shortly after SNG’s motion for summary judgment was filed and before Orleans filed any opposition thereto, Orleans agreed to a settlement pursuant to which all claims against SNG were dismissed with prejudice.

General

As of December 31, 2025 and 2024, we had liabilities of $176 million and $188 million, respectively, recorded for environmental matters. In addition, as of both December 31, 2025 and 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. 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. We expect compliance with these state plans would be less burdensome for us.

18.			Recent Accounting Pronouncements

Accounting Standards Updates

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.