KINDER MORGAN, INC., 10-K filed on 2/13/2026
Annual Report
v3.25.4
Document and Entity Information - USD ($)
 12 Months Ended
Dec. 31, 2025
Feb. 12, 2026
Jun. 30, 2025
Entity Information [Line Items]      
Document Type 10-K    
Document Annual Report true    
Current Fiscal Year End Date --12-31    
Document Fiscal Year Focus 2025    
Document Period End Date Dec. 31, 2025    
Document Transition Report false    
Entity File Number 001-35081    
Entity Registrant Name Kinder Morgan, Inc.    
Entity Incorporation, State or Country Code DE    
Entity Tax Identification Number 80-0682103    
Entity Address, Address Line One 1001 Louisiana Street    
Entity Address, Address Line Two Suite 1000    
Entity Address, City or Town Houston    
Entity Address, State or Province TX    
Entity Address, Postal Zip Code 77002    
City Area Code 713    
Local Phone Number 369-9000    
Entity Well-known Seasoned Issuer Yes    
Entity Voluntary Filers No    
Entity Current Reporting Status Yes    
Entity Interactive Data Current Yes    
Entity Filer Category Large Accelerated Filer    
Entity Small Business false    
Entity Emerging Growth Company false    
ICFR Auditor Attestation Flag true    
Document Financial Statement Error Correction [Flag] false    
Entity Shell Company false    
Entity Public Float     $ 57,054,291,328
Entity Common Stock, Shares Outstanding   2,224,806,397  
Entity Central Index Key 0001506307    
Document Fiscal Period Focus FY    
Amendment Flag false    
Class P      
Entity Information [Line Items]      
Title of 12(b) Security Class P Common Stock    
Trading Symbol KMI    
Security Exchange Name NYSE    
2.250% Senior Notes due March 2027      
Entity Information [Line Items]      
Title of 12(b) Security 2.250% Senior Notes due 2027    
Trading Symbol KMI 27 A    
Security Exchange Name NYSE    
v3.25.4
Audit Information
 12 Months Ended
Dec. 31, 2025
Auditor [Line Items]  
Auditor Name PricewaterhouseCoopers LLP
Auditor Location Houston, Texas
Auditor Firm ID 238
v3.25.4
CONSOLIDATED STATEMENTS OF INCOME - USD ($)
shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Revenues      
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 Earnings Per Share $ 1.37 $ 1.17 $ 1.06
Diluted Earnings Per Share $ 1.37 $ 1.17 $ 1.06
Basic Weighted Average Shares Outstanding 2,223 2,220 2,234
Diluted Weighted Average Shares Outstanding 2,223 2,220 2,234
Services      
Revenues      
Revenues $ 9,490 $ 8,916 $ 8,371
Commodity sales      
Revenues      
Revenues 7,255 5,957 6,786
Other      
Revenues      
Revenues $ 192 $ 227 $ 177
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
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
v3.25.4
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (Parenthetical) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Statement of Comprehensive Income [Abstract]      
Change in fair value of derivative instruments, tax $ (54) $ 8 $ (47)
Reclassification of change in fair value of derivative instruments to net income, tax 26 (12) 12
Benefit plan adjustments, tax (12) (33) (20)
Net income $ 3,160 $ 2,720 $ 2,486
v3.25.4
CONSOLIDATED BALANCE SHEETS - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
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
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 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
v3.25.4
CONSOLIDATED BALANCE SHEETS (Parenthetical) - $ / shares
Dec. 31, 2025
Dec. 31, 2024
Stockholders’ Equity    
Common stock, par value (in dollars per share) $ 0.01 $ 0.01
Common stock, shares authorized (in shares) 4,000,000,000 4,000,000,000
Common stock, shares issued (in shares) 2,224,777,750 2,221,647,775
Common stock, shares outstanding (in shares) 2,224,777,750 2,221,647,775
v3.25.4
CONSOLIDATED STATEMENTS OF CASH FLOWS - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 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) 0 0
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 0 0
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) 0 (7) (522)
Contributions from noncontrolling interests 0 0 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 0 (1) 0
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
Cash and Cash Equivalents, beginning of period 88    
Cash and Cash Equivalents, end of period 63 88  
Restricted Deposits, beginning of period 126    
Restricted Deposits, end of period 46 126  
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 0 0 16
Supplemental Disclosures of Cash Flow Information      
Cash paid during the period for interest (net of capitalized interest) 1,811 1,816 1,844
Cash paid during the period for income taxes, net $ 47 $ 33 $ 11
v3.25.4
CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY - USD ($)
shares in Millions, $ in Millions
Total
Common stock
Additional paid-in capital
Accumulated deficit
Accumulated other comprehensive loss
Stockholders’ equity attributable to KMI
Non-controlling interests
Balance at Dec. 31, 2022 $ 32,114 $ 22 $ 41,673 $ (10,551) $ (402) $ 30,742 $ 1,372
Balance (shares) at Dec. 31, 2022   2,248          
Repurchases of shares (522)   (522)     (522)  
Repurchases of shares (shares)   (32)          
Restricted shares 44   44     44  
Restricted shares (shares)   4          
Net income 2,486     2,391   2,391 95
Dividends (2,529)     (2,529)   (2,529)  
Distributions (151)         0 (151)
Contributions 3         0 3
Acquisition (Note 3) 104         0 104
Other (5)   (5)     (5)  
Other comprehensive income 185       185 185  
Balance (shares) at Dec. 31, 2023   2,220          
Balance at Dec. 31, 2023 31,729 $ 22 41,190 (10,689) (217) 30,306 1,423
Repurchases of shares (7)   (7)     (7)  
Repurchases of shares (shares)   (1)          
Restricted shares 54   54     54  
Restricted shares (shares)   3          
Net income 2,720     2,613   2,613 107
Dividends (2,557)     (2,557)   (2,557)  
Distributions (154)         0 (154)
Acquisition adjustment (Note3) (38)         0 (38)
Other (2)         0 (2)
Other comprehensive income 122       122 122  
Balance (shares) at Dec. 31, 2024   2,222          
Balance at Dec. 31, 2024 31,867 $ 22 41,237 (10,633) (95) 30,531 1,336
Repurchases of shares 0            
Repurchases of shares (shares)   0          
Restricted shares 39   39     39  
Restricted shares (shares)   3          
Net income 3,160     3,056   3,056 104
Dividends (2,604)     (2,604)   (2,604)  
Distributions (153)         0 (153)
Other comprehensive income 140       140 140  
Balance (shares) at Dec. 31, 2025   2,225          
Balance at Dec. 31, 2025 $ 32,449 $ 22 $ 41,276 $ (10,181) $ 45 $ 31,162 $ 1,287
v3.25.4
General (Notes)
 12 Months Ended
Dec. 31, 2025
Organization, Consolidation and Presentation of Financial Statements [Abstract]  
General
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.
v3.25.4
Summary of Significant Accounting Policies (Notes)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Summary of Significant Accounting Policies
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.
AssetAccounting AreaPolicy
Straight-line assetsDepreciation 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 assetsDepreciation 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,
20252024
(In millions)
Balance at beginning of period$248 $231 
Accretion expense14 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,
20252024
(In millions)
Gross$3,580 $3,543 
Accumulated amortization(1,850)(1,783)
Net carrying amount$1,730 $1,760 
December 31,
202520242023
(In millions)
Amortization expense$190 $197 $202 

Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
20262027202820292030
(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 SalesFirm ServicesFee-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 ObligationEach 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 SalesFirm ServicesFee-Based Services
Transaction PriceVariable 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 PriceAllocated 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 SatisfactionUpon 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,
20252024
(In millions)
Current regulatory assets$40 $25 
Non-current regulatory assets216 231 
Total regulatory assets(a)$256 $256 
Current regulatory liabilities$18 $35 
Non-current regulatory liabilities199 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,
202520242023
(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,
202520242023
(In millions on a weighted average basis)
Unvested stock awards
13 13 13 
Convertible trust preferred securities3 3 3 
v3.25.4
Acquisitions and Divestitures (Notes)
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Acquisitions and Divestitures
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
RefAcquisitionPurchase priceCurrent assets
Property, plant, & equipment
Other long-term assetsCurrent liabilitiesLong-term liabilitiesNon-controlling interestResulting goodwill
(In millions)
(1)Outrigger Energy$648 $16 $497 $160 $(5)$(20)$— $— 
(2)North McElroy Unit61 1 102 — — (42)— — 
(3)STX Midstream1,829 25 1,199 549 (6)— (66)128 
(4)Diamond M13 — 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.

CO2 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.
v3.25.4
Income Taxes (Notes)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Income Taxes
4. Income Taxes

The components of “Income Before Income Taxes” are as follows:
 Year Ended December 31,
 202520242023
(In millions)
U.S.$3,990 $3,402 $3,192 
Foreign2 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,
 202520242023
(In millions)
Current tax expense   
Federal$23 $11 $— 
State25 26 5 
Foreign4 3 — 
Total52 40 5 
Deferred tax expense    
Federal729 602 619 
State51 45 91 
Total780 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,
 202520242023
(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,
 20252024
(In millions)
Deferred tax assets  
Employee benefits$67 $81 
Net operating loss carryforwards1,017 1,416 
Tax credit carryforwards265 312 
Interest expense limitation346 372 
Other183 179 
Valuation allowances(72)(64)
Total deferred tax assets1,806 2,296 
Deferred tax liabilities
Property, plant, and equipment231 217 
Investments(a)
4,436 4,124 
Other30 25 
Total deferred tax liabilities4,697 4,366 
Net deferred tax liability$(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 NOL6 
State rate changes(1)
Currency fluctuation3 
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 AmountDeferred Tax AssetValuation AllowanceExpiration Period
(In millions)
Net Operating Loss
U.S. federal net operating loss$3,899 $819 $— Indefinite
State losses4,137 171 (45)2025 - 2045
Foreign losses79 27 (27)Indefinite
Tax Credits
General business credits265 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,
202520242023
(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 years5 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:
JurisdictionOpen Tax Year
U.S.2021 - 2025
Various states2012 - 2025
Foreign2021 - 2025

Income Taxes Paid

The components of total income taxes paid net of refunds by jurisdiction are as follows:
Year Ended December 31,
202520242023
(In millions)
Federal
$20 $10 $— 
States(a)
Texas12 9 6 
Pennsylvania3 4 2 
Louisiana3 2 — 
California3 2 — 
New Hampshire— — 1 
Utah— 1 1 
New Mexico— — (2)
Other States3 4 — 
Foreign
Mexico3 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.
v3.25.4
Property, Plant and Equipment, net (Notes)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Property, Plant and Equipment, net
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,
 20252024
(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 assets12,733 12,295 
Land54 51 
Construction work in process454 568 
Total interstate natural gas FERC-regulated13,241 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 assets23,942 23,293 
Land785 786 
Construction work in process1,363 1,020 
Total other26,090 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.
v3.25.4
Investments (Notes)
 12 Months Ended
Dec. 31, 2025
Equity Method Investments and Joint Ventures [Abstract]  
Investments .  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 InvestmentsEarnings from
Equity Investments
 December 31,December 31,Year Ended December 31,
 202520252024202520242023
(In millions)
Citrus Corporation50%$1,819 $1,794 $153 $134 $143 
SNG50%1,660 1,734 127 145 140 
PHP27.74%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 Corporation51.17%371 371 73 72 65 
Utopia Holding LLC50%314 318 39 24 22 
MEP50%299 320 74 63 87 
Gulf LNG Holdings Group, LLC50%206 240 27 26 25 
Dos Caminos, LLC
50%181 188 22 16 — 
Red Cedar Gathering Company49%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 Statement202520242023
(In millions)
Revenues$6,854 $6,607 $6,249 
Costs and expenses4,798 4,541 4,262 
Net income$2,056 $2,066 $1,987 
December 31,
Balance Sheet20252024
(In millions)
Current assets$1,451 $1,355 
Non-current assets24,490 24,465 
Current liabilities1,420 2,223 
Non-current liabilities10,469 9,181 
Partners’/owners’ equity14,052 14,416 
v3.25.4
Goodwill (Notes)
 12 Months Ended
Dec. 31, 2025
Goodwill and Intangible Assets Disclosure [Abstract]  
Goodwill
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 PipelinesProducts PipelinesTerminals
CO2
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.
v3.25.4
Debt (Notes)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Debt
8.  Debt

The following table provides detail on the principal amount of our outstanding debt balances:
December 31,
 20252024
(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,
 20252024
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 Subsidiaries31,823 31,788 
Less: Current portion of debt1,226 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,
20252024
(In millions)
$3.5 billion credit facility due August 20, 2027
$— $— 
Commercial paper notes13 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 debt27 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:
YearTotal
(In millions)
2026$1,226 
2027942 
20281,867 
20291,781 
20302,367 
Thereafter23,640 
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,
20252024
(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, 2025December 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.”
v3.25.4
Share-based Compensation and Employee Benefits (Notes)
 12 Months Ended
Dec. 31, 2025
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]  
Share-based Compensation and Employee Benefits
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 individualsEligible non-employee directors
Eligible employees
Total number of shares of Class P common stock authorized1,190,000 63,000,000 
Vesting period6 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:
SharesWeighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 2024
13,405 $18.30 
Granted3,420 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,
202520242023
(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 year128 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 BenefitsOPEB
2025202420252024
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period$1,809 $1,902 $169 $177 
Service cost50 52 1 1 
Interest cost91 91 8 8 
Actuarial loss (gain)27 (82)7 8 
Benefits paid(163)(154)(24)(26)
Participant contributions— — 1 1 
Benefit obligation at end of period1,814 1,809 162 169 
Change in plan assets:   
Fair value of plan assets at beginning of period1,614 1,562 331 323 
Actual return on plan assets183 156 44 33 
Employer contributions50 50 — — 
Participant contributions— — 1 1 
Benefits paid(163)(154)(24)(26)
Fair value of plan assets at end of period1,684 1,614 352 331 
Funded status - net (liability) asset at December 31,$(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 assets1,165 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 BenefitsOPEB
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
20252024
Level 1Level 2TotalLevel 1Level 2Total
(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 
Subtotal1,111 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
20252024
Level 1Level 2TotalLevel 1Level 2Total
(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 BenefitsOPEB
(In millions)
Contributions expected in 2026
$60 $— 
Benefit payments expected in:
2026$191 $22 
2027186 21 
2028181 19 
2029177 18 
2030170 16 
2031 - 2035755 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 BenefitsOPEB
2025202420252024
Assumptions related to benefit obligations:
Discount rate5.32 %5.58 %5.02 %5.44 %
Rate of compensation increase3.50 %3.50 %n/an/a
Interest crediting rate3.85 %3.78 %n/an/a
Pension BenefitsOPEB
202520242023202520242023
Assumptions related to benefit costs:
Discount rate5.58 %5.13 %5.41 %5.44 %5.08 %5.38 %
Expected return on plan assets7.00 %7.00 %7.00 %6.00 %6.00 %6.00 %
Rate of compensation increase3.50 %3.50 %3.50 %n/an/an/a
Interest crediting rate3.78 %3.85 %3.50 %n/an/an/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 BenefitsOPEB
202520242023202520242023
(In millions)
Components of net benefit cost (credit):
Service cost$50 $52 $55 $1 $1 $1 
Interest cost91 91 107 8 8 10 
Expected return on assets(109)(106)(117)(15)(14)(13)
Amortization of prior service cost (credit)— — 1 (1)(3)(3)
Amortization of net actuarial loss (gain)8 22 35 (16)(17)(16)
Settlement loss
— — 46 — — — 
Net benefit cost (credit)40 59 127 (23)(25)(21)
Other changes in plan assets and benefit obligations recognized in OCI:
Net (gain) loss arising during period(46)(132)10 (15)(6)(30)
Amortization or settlement recognition of net actuarial (loss) gain(8)(22)(81)15 16 16 
Amortization of prior service (cost) credit— — (1)1 1 1 
Total recognized in OCI(a)(54)(154)(72)1 11 (13)
Total recognized in net benefit cost (credit) and OCI$(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.
v3.25.4
Stockholders' Equity (Notes)
 12 Months Ended
Dec. 31, 2025
Stockholders' Equity Note [Abstract]  
Stockholders’ Equity
10. Stockholders’ Equity

Class P Common Stock

We have a board-approved share buy-back program that authorizes share repurchases of up to $3 billion that began in December 2017. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows:
Year Ended December 31,
202520242023
(In millions, except per share amounts)
Total value of shares repurchased$— $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,
202520242023
Per share cash dividend declared for the period$1.17 $1.15 $1.13 
Per share cash dividend paid in the period1.1650 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 loss120 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 loss11 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 income100 40 140 
Balance at December 31, 2025$67 $(22)$45 
v3.25.4
Related Party Transactions (Notes)
 12 Months Ended
Dec. 31, 2025
Related Party Transactions [Abstract]  
Related Party Transactions
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,
20252024
(In millions)
Balance sheet location
Accounts receivable$54 $48 
Other current assets4 1 
$58 $49 
Current portion of debt$5 $5 
Accounts payable20 21 
Other current liabilities7 8 
Long-term debt127 132 
Other long-term liabilities and deferred credits69 60 
$228 $226 
Year Ended December 31,
202520242023
(In millions)
Income statement location
Revenues$349 $346 $172 
Operating Costs, Expenses, and Other
Costs of sales$177 $145 $132 
Other operating expenses101 69 57 
v3.25.4
Commitments and Contingent Liabilities (Notes)
 12 Months Ended
Dec. 31, 2025
Commitments and Contingencies Disclosure [Abstract]  
Commitments and Contingencies Disclosure [Text Block]
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.
v3.25.4
Risk Management (Notes)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Risk Management
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 amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)
$3,500 Fair value hedgeAugust 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 amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$543 Cash flow hedgeMarch 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
LocationDerivatives AssetDerivatives Liability
December 31,December 31,
2025202420252024
(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)
Subtotal92 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)
Subtotal36 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)
Subtotal41 — (2)(29)
Total169 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)
Subtotal79 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)
Total79 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 amountContracts available for nettingCash 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 1Level 2Level 3Gross amountContracts available for nettingCash 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 relationshipsLocationGain/(loss) recognized in income on derivatives and related hedged item
  Year Ended December 31,
  202520242023
(In millions)
Interest rate contractsInterest, 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 EndedYear Ended
 December 31, December 31,
 202520242023 202520242023
(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 contracts67 (24)30 Other, net69 (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 hedgesLocationGain/(loss) recognized in income on derivatives
 Year Ended December 31,
 202520242023
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$79 $20 $75 
Costs of sales
(61)(89)100 
 
Earnings from equity investments1 — 2 
Interest rate contractsInterest, 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.
v3.25.4
Revenue Recognition (Notes)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Revenue Recognition
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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$4,254 $221 $870 $1 $(4)$5,342 
Fee-based services1,161 1,090 431 45 (8)2,719 
Total services5,415 1,311 1,301 46 (12)8,061 
Commodity sales
Natural gas sales3,909 — — 49 (9)3,949 
Product sales1,001 1,157 56 857 (8)3,063 
Other sales29 — — 103 (3)129 
Total commodity sales4,939 1,157 56 1,009 (20)7,141 
Total revenues from contracts with customers10,354 2,468 1,357 1,055 (32)15,202 
Other revenues
Leasing services(b)
455 192 747 70 — 1,464 
Derivatives adjustments on commodity sales96 — — 30 — 126 
Other104 26 — 15 — 145 
Total other revenues655 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$3,893 $220 $846 $2 $(4)$4,957 
Fee-based services1,044 1,059 460 41 (7)2,597 
Total services4,937 1,279 1,306 43 (11)7,554 
Commodity sales
Natural gas sales2,303 — — 43 (6)2,340 
Product sales965 1,444 50 1,031 (4)3,486 
Other sales20 — — 85 (2)103 
Total commodity sales3,288 1,444 50 1,159 (12)5,929 
Total revenues from contracts with customers8,225 2,723 1,356 1,202 (23)13,483 
Other revenues
Leasing services(b)
459 209 666 66 — 1,400 
Derivatives adjustments on commodity sales113 (1)— (85)— 27 
Other145 24 — 21 — 190 
Total other revenues717 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$3,543 $171 $819 $1 $3 $4,537 
Fee-based services1,008 1,036 427 40 (9)2,502 
Total services4,551 1,207 1,246 41 (6)7,039 
Commodity sales
Natural gas sales2,631 — — 43 (8)2,666 
Product sales1,110 1,635 33 1,114 (8)3,884 
Other sales20 — — 42 (4)58 
Total commodity sales3,761 1,635 33 1,199 (20)6,608 
Total revenues from contracts with customers8,312 2,842 1,279 1,240 (26)13,647 
Other revenues
Leasing services(b)
475 200 638 55 — 1,368 
Derivatives adjustments on commodity sales285 — — (107)— 178 
Other96 24 — 21 — 141 
Total other revenues856 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:
202620272028 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.
v3.25.4
Reportable Segments (Notes)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Reportable Segments
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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$10,990 $2,686 $2,094 $1,167 $— $16,937 
Intersegment revenues19 — 10 3 (32)— 
Total revenues11,009 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 expenditures2,092 242 326 328 38 3,026 
Segment balance sheet information:
Investments6,962 381 122 67 — 7,532 
Other intangibles, net900 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$8,930 $2,955 $2,013 $1,202 $— $15,100 
Intersegment revenues12 — 9 2 (23)— 
Total revenues8,942 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 investments748 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 expenditures1,654 210 385 346 34 2,629 
Segment balance sheet information:
Investments7,252 387 132 74 — 7,845 
Other intangibles, net687 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$9,152 $3,066 $1,911 $1,205 $— $15,334 
Intersegment revenues16 — 6 4 (26)— 
Total revenues9,168 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 expenditures1,299 221 406 355 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,
 202520242023
(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,
 202520242023
(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 
v3.25.4
Leases (Notes)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Leases: Lessee
16.  Leases

Following are components of our lease cost:
Year Ended December 31,
202520242023
(In millions)
Operating leases$74 $80 $71 
Short-term and variable leases152 131 127 
Total lease cost$226 $211 $198 

Other information related to our operating leases are as follows:
Year Ended December 31,
202520242023
(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 retirements25 36 56 
Amortization of ROU assets62 68 58 
Weighted average remaining lease term
8.06 years
8.15 years
8.72 years
Weighted average discount rate4.85 %4.84 %4.59 %

Amounts recognized in the accompanying consolidated balance sheets are as follows:
December 31,
Lease Activity(a)Balance sheet location20252024
(In millions)
ROU assetsDeferred charges and other assets$216 $253 
Short-term lease liabilityOther current liabilities49 60 
Long-term lease liabilityOther long-term liabilities and deferred credits167 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:
YearCommitment
 (In millions)
2026$59 
202741 
202827 
202925 
203021 
Thereafter105 
Total lease payments278 
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.
v3.25.4
Litigation and Environmental (Notes)
 12 Months Ended
Dec. 31, 2025
Loss Contingency, Information about Litigation Matters [Abstract]  
Litigation and Environmental
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.
v3.25.4
Recent Accounting Pronoucements (Notes)
 12 Months Ended
Dec. 31, 2025
Accounting Standards Update and Change in Accounting Principle [Abstract]  
Recent Accounting Pronouncements
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.
v3.25.4
Insider Trading Arrangements
 3 Months Ended
Dec. 31, 2025
shares
Trading Arrangements, by Individual  
Material Terms of Trading Arrangement
On December 9, 2025, Michael Garthwaite, Vice President (President, Products Pipelines) of KMI, adopted a trading plan that is intended to satisfy the affirmative defense of Rule 10b5-1(c) providing for the sale of up to 18,600 shares of KMI common stock. The expiration date for Mr. Garthwaite’s plan is February 16, 2027.
Non-Rule 10b5-1 Arrangement Adopted false
Rule 10b5-1 Arrangement Terminated false
Non-Rule 10b5-1 Arrangement Terminated false
Michael Garthwaite [Member]  
Trading Arrangements, by Individual  
Name Michael Garthwaite
Title Vice President (President, Products Pipelines)
Rule 10b5-1 Arrangement Adopted true
Adoption Date December 9, 2025
Expiration Date February 16, 2027
Aggregate Available 18,600
v3.25.4
Insider Trading Policies and Procedures
 12 Months Ended
Dec. 31, 2025
Insider Trading Policies and Procedures [Line Items]  
Insider Trading Policies and Procedures Adopted true
v3.25.4
Cybersecurity Risk Management and Strategy Disclosure
 12 Months Ended
Dec. 31, 2025
Cybersecurity Risk Management, Strategy, and Governance [Line Items]  
Cybersecurity Risk Management Processes for Assessing, Identifying, and Managing Threats [Text Block]
Cybersecurity Risk Management and Strategy

We employ a comprehensive strategy for identifying and addressing cybersecurity risks that is consistent with the security directives issued by TSA where required and aligned with the U.S. Department of Commerce’s National Institute of Standards and Technology Framework for Improving Critical Infrastructure Cybersecurity. This framework outlines standards and practices to promote the protection of critical infrastructure. We utilize a risk-based approach that focuses on critical systems where failure or exploitation could potentially impact the safety or reliability of our key assets or operations. Cybersecurity risks are integrated into our overall risk management processes, including, for example, quarterly security briefings with senior management, tabletop exercises with operations, finance and other company personnel, and by employing a continuous improvement model for our cyber protection strategy that is aligned with the DHS’s National Infrastructure Protection Plan risk management framework.

Our management team has engaged third-party experts to provide guidance related to management of supply chain cybersecurity risks. Our strategy includes both short- and long-term initiatives to increase the security surrounding our assets and is supplemented using third-party threat monitoring, rigorous security protocols, and government partnerships. We perform cybersecurity assessments with respect to third parties who provide critical services or who have access to or store critical confidential data.

We have not identified any cybersecurity threats that have materially impaired or are reasonably likely to materially impair our operations or financial standing. Please read Item 1A. “Risk Factors—Risks Related to Our Business—A breach of information security or the failure of one or more key IT or operational (OT) systems, or those of third parties, may adversely affect our business, results of operations, or business reputation.” and “ Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.” for discussions of risks from cybersecurity threats we face.

Measures We Take to Monitor and our Procedures for Responding to Data Breaches or Cyberattacks

We have made investments to address data and cybersecurity risks. These investments include our use of continuous third-party security monitoring of our network perimeters, advanced persistent threat group monitoring to keep us informed of emerging serious threats, standardization of our network security architecture which separates business and supervisory control and data acquisition (SCADA) networks, and security information and event management software systems.

Our critical business systems are fully redundant and backed up at separate locations. Separate business and SCADA networks allow for isolation of potential threats and enhances the security of these systems. Our security systems correlate security events and aggregate security-related incident data, such as malware activity and other possible malicious activities. This system sends alerts if the data analysis shows that an activity could be a potential security issue. Security functionality is continuously monitored by our network operations center, and our network traffic is analyzed for signs of malicious activity through the CyberSentry program, which is managed by DHS’s Cybersecurity and Infrastructure Security Agency and a third-party security operations center, which operates continuously. We maintain a dedicated SCADA group within our IT department to evaluate and respond to significant events and incidents that may impact our operations. Anti-virus solutions are deployed on the SCADA systems and workstations in our data centers and control centers.

Our processes and cybersecurity plans are part of our overall emergency response plans, and we conduct simulated exercise drills, including with multiple U.S. government agencies and peer companies, to enhance our preparedness and provide for continual process improvement.
If data and network defenses are bypassed, processes detailed in our Cyber Incident Response Plan would help identify, contain and eradicate threats and bring our systems back online if needed. Additionally, the plan requires that the appropriate level of our management be made aware of incidents and be updated as the situation warrants.

Vulnerability Assessments and Penetration Testing

We hire an independent third-party cybersecurity firm to perform penetration testing annually. The third-party checks for vulnerabilities on our external and internal network perimeters. If vulnerabilities are found, corrective actions are implemented to remediate any issues.

Government and Industry Group Engagement

We engage with a wide variety of government agencies and industry groups to enable cross-sharing of information and to identify opportunities to improve our security, including active participation in IT Sector Coordinating Councils and attendance at classified briefings and security architecture reviews hosted by the U.S. Department of Energy, the U.S. Federal Bureau of Investigation and DHS. Partnership with these agencies provides us with intelligence on a wide range of critical infrastructure protection and cybersecurity issues as well as an opportunity to exchange best practices.

Employee Training

Our employees are required to take annual cyber and physical security training designed to help employees guard our cyber and physical data. Employees are tested regularly on cybersecurity, and cybersecurity performance is considered in annual employee performance reviews.

Cybersecurity Governance Structures

Management’s Role in Managing Cybersecurity Risk

We are committed to protecting sensitive information and have a dedicated cybersecurity group within our IT department that is overseen by our Chief Information Officer. This group provides a quarterly cybersecurity report to our senior management, including the Chief Executive Officer, President, Chief Financial Officer, Chief Operating Officer, Chief Administrative Officer, Chief Information Officer, General Counsel, business segment Presidents, and the Vice President—Corporate Security. This senior management team is involved in all significant cybersecurity decisions, including efforts undertaken to comply with the security directives issued by the TSA. Our Chief Information Officer and, occasionally, our Chief Executive Officer and our General Counsel have attended classified briefings on cybersecurity in Washington, D.C. In addition to the quarterly reports to senior management, the cybersecurity team prepares broader management briefings that include updates regarding company-wide cybersecurity matters and initiatives and provide a forum for discussing data security risk solutions and formulating action plans.

Management of our cybersecurity team has extensive experience and training related to cybersecurity matters. These leaders hold top-secret clearance from the U.S. federal government and have attended classified briefings from relevant federal agencies. Our cybersecurity team has in excess of 100 years of combined cybersecurity experience as of year-end 2025, and members of the team hold various specialized certifications related to cybersecurity, including training related to penetration testing and information system auditing.

The Board’s Role in Cybersecurity Risk Oversight

The Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events. In the event of a significant cybersecurity incident, our Chief Executive Officer will notify the Chairman of the Board or, in that person’s absence, the lead independent director of the Board.
Cybersecurity Risk Management Processes Integrated [Flag] true
Cybersecurity Risk Management Processes Integrated [Text Block] Cybersecurity risks are integrated into our overall risk management processes, including, for example, quarterly security briefings with senior management, tabletop exercises with operations, finance and other company personnel, and by employing a continuous improvement model for our cyber protection strategy that is aligned with the DHS’s National Infrastructure Protection Plan risk management framework.
Cybersecurity Risk Management Third Party Engaged [Flag] true
Cybersecurity Risk Third Party Oversight and Identification Processes [Flag] true
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Flag] false
Cybersecurity Risk Materially Affected or Reasonably Likely to Materially Affect Registrant [Text Block]
We have not identified any cybersecurity threats that have materially impaired or are reasonably likely to materially impair our operations or financial standing. Please read Item 1A. “Risk Factors—Risks Related to Our Business—A breach of information security or the failure of one or more key IT or operational (OT) systems, or those of third parties, may adversely affect our business, results of operations, or business reputation.” and “ Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.” for discussions of risks from cybersecurity threats we face.
Cybersecurity Risk Board of Directors Oversight [Text Block]
The Board’s Role in Cybersecurity Risk Oversight

The Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events. In the event of a significant cybersecurity incident, our Chief Executive Officer will notify the Chairman of the Board or, in that person’s absence, the lead independent director of the Board.
Cybersecurity Risk Board Committee or Subcommittee Responsible for Oversight [Text Block] The Audit Committee of our Board has oversight responsibility related to cybersecurity risk
Cybersecurity Risk Process for Informing Board Committee or Subcommittee Responsible for Oversight [Text Block]
The Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events. In the event of a significant cybersecurity incident, our Chief Executive Officer will notify the Chairman of the Board or, in that person’s absence, the lead independent director of the Board.
Cybersecurity Risk Role of Management [Text Block]
Management’s Role in Managing Cybersecurity Risk

We are committed to protecting sensitive information and have a dedicated cybersecurity group within our IT department that is overseen by our Chief Information Officer. This group provides a quarterly cybersecurity report to our senior management, including the Chief Executive Officer, President, Chief Financial Officer, Chief Operating Officer, Chief Administrative Officer, Chief Information Officer, General Counsel, business segment Presidents, and the Vice President—Corporate Security. This senior management team is involved in all significant cybersecurity decisions, including efforts undertaken to comply with the security directives issued by the TSA. Our Chief Information Officer and, occasionally, our Chief Executive Officer and our General Counsel have attended classified briefings on cybersecurity in Washington, D.C. In addition to the quarterly reports to senior management, the cybersecurity team prepares broader management briefings that include updates regarding company-wide cybersecurity matters and initiatives and provide a forum for discussing data security risk solutions and formulating action plans.

Management of our cybersecurity team has extensive experience and training related to cybersecurity matters. These leaders hold top-secret clearance from the U.S. federal government and have attended classified briefings from relevant federal agencies. Our cybersecurity team has in excess of 100 years of combined cybersecurity experience as of year-end 2025, and members of the team hold various specialized certifications related to cybersecurity, including training related to penetration testing and information system auditing.
Cybersecurity Risk Management Positions or Committees Responsible [Flag] true
Cybersecurity Risk Management Positions or Committees Responsible [Text Block] We are committed to protecting sensitive information and have a dedicated cybersecurity group within our IT department that is overseen by our Chief Information Officer. This group provides a quarterly cybersecurity report to our senior management, including the Chief Executive Officer, President, Chief Financial Officer, Chief Operating Officer, Chief Administrative Officer, Chief Information Officer, General Counsel, business segment Presidents, and the Vice President—Corporate SecurityThe Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events.
Cybersecurity Risk Management Expertise of Management Responsible [Text Block]
We are committed to protecting sensitive information and have a dedicated cybersecurity group within our IT department that is overseen by our Chief Information Officer. This group provides a quarterly cybersecurity report to our senior management, including the Chief Executive Officer, President, Chief Financial Officer, Chief Operating Officer, Chief Administrative Officer, Chief Information Officer, General Counsel, business segment Presidents, and the Vice President—Corporate Security. This senior management team is involved in all significant cybersecurity decisions, including efforts undertaken to comply with the security directives issued by the TSA. Our Chief Information Officer and, occasionally, our Chief Executive Officer and our General Counsel have attended classified briefings on cybersecurity in Washington, D.C. In addition to the quarterly reports to senior management, the cybersecurity team prepares broader management briefings that include updates regarding company-wide cybersecurity matters and initiatives and provide a forum for discussing data security risk solutions and formulating action plans.

Management of our cybersecurity team has extensive experience and training related to cybersecurity matters. These leaders hold top-secret clearance from the U.S. federal government and have attended classified briefings from relevant federal agencies. Our cybersecurity team has in excess of 100 years of combined cybersecurity experience as of year-end 2025, and members of the team hold various specialized certifications related to cybersecurity, including training related to penetration testing and information system auditing.
Cybersecurity Risk Process for Informing Management or Committees Responsible [Text Block]
The Audit Committee of our Board has oversight responsibility related to cybersecurity risk and is briefed quarterly by our Chief Information Officer on cybersecurity risk, our cybersecurity management program and initiatives, and, if applicable, notable cybersecurity events. In the event of a significant cybersecurity incident, our Chief Executive Officer will notify the Chairman of the Board or, in that person’s absence, the lead independent director of the Board.
Cybersecurity Risk Management Positions or Committees Responsible Report to Board [Flag] true
v3.25.4
Summary of Significant Accounting Policies (Policies)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Basis of Presentation
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
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
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
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
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
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.
AssetAccounting AreaPolicy
Straight-line assetsDepreciation 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 assetsDepreciation 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
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,
20252024
(In millions)
Balance at beginning of period$248 $231 
Accretion expense14 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
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 Difference
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

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
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.
Revenue Recognition
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 SalesFirm ServicesFee-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 ObligationEach 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 SalesFirm ServicesFee-Based Services
Transaction PriceVariable 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 PriceAllocated 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 SatisfactionUpon 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

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

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
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: Lessee
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
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
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
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.
Noncontrolling Interests
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 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
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
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

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.
Earnings per Share
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.
v3.25.4
Acquisitions and Divestitures (Policies)
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Business Combinations
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.
v3.25.4
Income Taxes (Policies)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Unrecognized Tax Benefits
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.
v3.25.4
Summary of Significant Accounting Policies (Tables)
 12 Months Ended
Dec. 31, 2025
Accounting Policies [Abstract]  
Schedule of Change in Asset Retirement Obligation
The following table summarizes changes in the asset retirement obligations included in our accompanying consolidated balance sheets:
December 31,
20252024
(In millions)
Balance at beginning of period$248 $231 
Accretion expense14 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.
Schedule of Other Intangibles
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,
20252024
(In millions)
Gross$3,580 $3,543 
Accumulated amortization(1,850)(1,783)
Net carrying amount$1,730 $1,760 
December 31,
202520242023
(In millions)
Amortization expense$190 $197 $202 
Schedule of Estimated Amortization Expense for Other Intangibles
Our estimated amortization expense for our intangible assets for each of the next five fiscal years is:
20262027202820292030
(In millions)
Estimated amortization expenses$184 $188 $187 $186 $186 
Schedule of Regulatory Assets
The following table summarizes our regulatory asset and liability balances as of December 31, 2025 and 2024:
December 31,
20252024
(In millions)
Current regulatory assets$40 $25 
Non-current regulatory assets216 231 
Total regulatory assets(a)$256 $256 
Current regulatory liabilities$18 $35 
Non-current regulatory liabilities199 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.
Schedule of Regulatory Liabilities
The following table summarizes our regulatory asset and liability balances as of December 31, 2025 and 2024:
December 31,
20252024
(In millions)
Current regulatory assets$40 $25 
Non-current regulatory assets216 231 
Total regulatory assets(a)$256 $256 
Current regulatory liabilities$18 $35 
Non-current regulatory liabilities199 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.
Schedule of Earnings Per Share, Basic and Diluted
The following table sets forth net income allocated to common shareholders:
Year Ended December 31,
202520242023
(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.
Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share
The following potential common stock equivalents are excluded from the determination of diluted EPS.
Year Ended December 31,
202520242023
(In millions on a weighted average basis)
Unvested stock awards
13 13 13 
Convertible trust preferred securities3 3 3 
v3.25.4
Acquisitions and Divestitures (Tables)
 12 Months Ended
Dec. 31, 2025
Business Combination, Asset Acquisition, Transaction between Entities under Common Control, and Joint Venture Formation [Abstract]  
Business Combination, Recognized Asset Acquired and Liability Assumed
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
RefAcquisitionPurchase priceCurrent assets
Property, plant, & equipment
Other long-term assetsCurrent liabilitiesLong-term liabilitiesNon-controlling interestResulting goodwill
(In millions)
(1)Outrigger Energy$648 $16 $497 $160 $(5)$(20)$— $— 
(2)North McElroy Unit61 1 102 — — (42)— — 
(3)STX Midstream1,829 25 1,199 549 (6)— (66)128 
(4)Diamond M13 — 25 — — (12)— — 
v3.25.4
Income Taxes (Tables)
 12 Months Ended
Dec. 31, 2025
Income Tax Disclosure [Abstract]  
Schedule of Income Before Income Taxes
The components of “Income Before Income Taxes” are as follows:
 Year Ended December 31,
 202520242023
(In millions)
U.S.$3,990 $3,402 $3,192 
Foreign2 5 9 
Total Income Before Income Taxes$3,992 $3,407 $3,201 
Schedule of Components of Income Tax Provision
Components of the income tax provision applicable for federal, foreign and state taxes are as follows:
 Year Ended December 31,
 202520242023
(In millions)
Current tax expense   
Federal$23 $11 $— 
State25 26 5 
Foreign4 3 — 
Total52 40 5 
Deferred tax expense    
Federal729 602 619 
State51 45 91 
Total780 647 710 
Total tax provision$832 $687 $715 
Schedule of Effective Income Tax Rate Reconciliation
The difference between the statutory federal income tax rate and our effective income tax rate is summarized as follows:
 Year Ended December 31,
 202520242023
(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.
Schedule of Deferred Tax Assets and Liabilities
Deferred tax assets and liabilities result from the following:
 December 31,
 20252024
(In millions)
Deferred tax assets  
Employee benefits$67 $81 
Net operating loss carryforwards1,017 1,416 
Tax credit carryforwards265 312 
Interest expense limitation346 372 
Other183 179 
Valuation allowances(72)(64)
Total deferred tax assets1,806 2,296 
Deferred tax liabilities
Property, plant, and equipment231 217 
Investments(a)
4,436 4,124 
Other30 25 
Total deferred tax liabilities4,697 4,366 
Net deferred tax liability$(2,891)$(2,070)
(a)Amounts as of December 31, 2025 and 2024 are primarily associated with KMI’s investment in KMP.
Summary of Valuation Allowance
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 NOL6 
State rate changes(1)
Currency fluctuation3 
Balance at end of period$72 
Summary of Operating Loss Carryforwards
The following table provides details related to our deferred tax assets and valuation allowances as of December 31, 2025:
Unused AmountDeferred Tax AssetValuation AllowanceExpiration Period
(In millions)
Net Operating Loss
U.S. federal net operating loss$3,899 $819 $— Indefinite
State losses4,137 171 (45)2025 - 2045
Foreign losses79 27 (27)Indefinite
Tax Credits
General business credits265 265 — 2037 - 2045
Schedule of Unrecognized Tax Benefits Roll Forward
A reconciliation of our gross unrecognized tax benefit excluding interest and penalties is as follows:
Year Ended December 31,
202520242023
(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 years5 4 1 
Balance at end of period$21 $19 $18 
Amounts which, if recognized, would affect the effective tax rate$21 
Summary of Income Tax Examinations
The following table summarizes information of our open tax years:
JurisdictionOpen Tax Year
U.S.2021 - 2025
Various states2012 - 2025
Foreign2021 - 2025
Schedule of Cash Flow, Supplemental Disclosures
The components of total income taxes paid net of refunds by jurisdiction are as follows:
Year Ended December 31,
202520242023
(In millions)
Federal
$20 $10 $— 
States(a)
Texas12 9 6 
Pennsylvania3 4 2 
Louisiana3 2 — 
California3 2 — 
New Hampshire— — 1 
Utah— 1 1 
New Mexico— — (2)
Other States3 4 — 
Foreign
Mexico3 1 3 
Total Income Taxes Paid
$47 $33 $11 
(a)2025 tax payments include $4 million of transferrable state tax credits purchased.
v3.25.4
Property, Plant and Equipment, net (Tables)
 12 Months Ended
Dec. 31, 2025
Property, Plant and Equipment [Abstract]  
Schedule of Property, Plant and Equipment
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,
 20252024
(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 assets12,733 12,295 
Land54 51 
Construction work in process454 568 
Total interstate natural gas FERC-regulated13,241 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 assets23,942 23,293 
Land785 786 
Construction work in process1,363 1,020 
Total other26,090 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.
v3.25.4
Investments (Tables)
 12 Months Ended
Dec. 31, 2025
Equity Method Investments and Joint Ventures [Abstract]  
Schedule of Equity Method 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 InvestmentsEarnings from
Equity Investments
 December 31,December 31,Year Ended December 31,
 202520252024202520242023
(In millions)
Citrus Corporation50%$1,819 $1,794 $153 $134 $143 
SNG50%1,660 1,734 127 145 140 
PHP27.74%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 Corporation51.17%371 371 73 72 65 
Utopia Holding LLC50%314 318 39 24 22 
MEP50%299 320 74 63 87 
Gulf LNG Holdings Group, LLC50%206 240 27 26 25 
Dos Caminos, LLC
50%181 188 22 16 — 
Red Cedar Gathering Company49%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 Statement202520242023
(In millions)
Revenues$6,854 $6,607 $6,249 
Costs and expenses4,798 4,541 4,262 
Net income$2,056 $2,066 $1,987 
December 31,
Balance Sheet20252024
(In millions)
Current assets$1,451 $1,355 
Non-current assets24,490 24,465 
Current liabilities1,420 2,223 
Non-current liabilities10,469 9,181 
Partners’/owners’ equity14,052 14,416 
v3.25.4
Goodwill (Tables)
 12 Months Ended
Dec. 31, 2025
Goodwill and Intangible Assets Disclosure [Abstract]  
Schedule of 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 PipelinesProducts PipelinesTerminals
CO2
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.
v3.25.4
Debt (Tables)
 12 Months Ended
Dec. 31, 2025
Debt Disclosure [Abstract]  
Schedule of Debt
The following table provides detail on the principal amount of our outstanding debt balances:
December 31,
 20252024
(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,
 20252024
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 Subsidiaries31,823 31,788 
Less: Current portion of debt1,226 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.
Schedule of Short-term Debt
The following table details the components of our “Current portion of debt” reported on our consolidated balance sheets:
December 31,
20252024
(In millions)
$3.5 billion credit facility due August 20, 2027
$— $— 
Commercial paper notes13 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 debt27 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.
Schedule of Maturities of Long-term Debt
The scheduled maturities of the outstanding debt balances, excluding debt fair value adjustments as of December 31, 2025, are summarized as follows:
YearTotal
(In millions)
2026$1,226 
2027942 
20281,867 
20291,781 
20302,367 
Thereafter23,640 
Total$31,823 
Schedule of Debt Fair Value Adjustments
The following table summarizes the “Debt fair value adjustments” included on our accompanying consolidated balance sheets:
December 31,
20252024
(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 
Schedule of Carrying Values and Estimated Fair Values of Debt Instruments
The carrying value and estimated fair value of our outstanding debt balances is disclosed below:
 December 31, 2025December 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.
v3.25.4
Share-based Compensation and Employee Benefits (Tables)
 12 Months Ended
Dec. 31, 2025
Employee Benefit and Share-Based Payment Arrangement, Noncash Expense [Abstract]  
Summary of Stock Compensation Plans
Following is a summary of our stock compensation plans:
Directors’ Plan
Long Term Incentive Plan
Participating individualsEligible non-employee directors
Eligible employees
Total number of shares of Class P common stock authorized1,190,000 63,000,000 
Vesting period6 months
1 year to 10 years
Summary of Activity and Related Balances of Restricted Stock Awards
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:
SharesWeighted Average Grant Date Fair Value per Share
(In thousands, except per share amounts)
Outstanding at December 31, 2024
13,405 $18.30 
Granted3,420 27.97 
Vested(4,573)17.50 
Forfeited(409)19.00 
Outstanding at December 31, 2025
11,843 $21.38 
Schedule of Grant Date Fair Value, Awards Vested and Compensation Costs
The following tables set forth additional information related to our Long Term Incentive Plan:
Year Ended December 31,
202520242023
(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 year128 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
Schedule of Defined Benefit Plans Disclosures
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 BenefitsOPEB
2025202420252024
(In millions)
Change in benefit obligation:
Benefit obligation at beginning of period$1,809 $1,902 $169 $177 
Service cost50 52 1 1 
Interest cost91 91 8 8 
Actuarial loss (gain)27 (82)7 8 
Benefits paid(163)(154)(24)(26)
Participant contributions— — 1 1 
Benefit obligation at end of period1,814 1,809 162 169 
Change in plan assets:   
Fair value of plan assets at beginning of period1,614 1,562 331 323 
Actual return on plan assets183 156 44 33 
Employer contributions50 50 — — 
Participant contributions— — 1 1 
Benefits paid(163)(154)(24)(26)
Fair value of plan assets at end of period1,684 1,614 352 331 
Funded status - net (liability) asset at December 31,$(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 assets1,165 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.
Fair Value of Pension and OPEB Assets by Level of Assets
The allowable range for asset allocations in effect for our plans as of December 31, 2025, by asset category, are as follows:
Pension BenefitsOPEB
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%
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
20252024
Level 1Level 2TotalLevel 1Level 2Total
(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 
Subtotal1,111 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
20252024
Level 1Level 2TotalLevel 1Level 2Total
(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.
Schedule of Expected Payment of Future Benefits and Employer Contributions
Employer Contributions and Expected Payment of Future Benefits. As of December 31, 2025, we expect the following cash flows under our plans:
Pension BenefitsOPEB
(In millions)
Contributions expected in 2026
$60 $— 
Benefit payments expected in:
2026$191 $22 
2027186 21 
2028181 19 
2029177 18 
2030170 16 
2031 - 2035755 62 
Schedule of Weighted-Average Actuarial Assumptions
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 BenefitsOPEB
2025202420252024
Assumptions related to benefit obligations:
Discount rate5.32 %5.58 %5.02 %5.44 %
Rate of compensation increase3.50 %3.50 %n/an/a
Interest crediting rate3.85 %3.78 %n/an/a
Pension BenefitsOPEB
202520242023202520242023
Assumptions related to benefit costs:
Discount rate5.58 %5.13 %5.41 %5.44 %5.08 %5.38 %
Expected return on plan assets7.00 %7.00 %7.00 %6.00 %6.00 %6.00 %
Rate of compensation increase3.50 %3.50 %3.50 %n/an/an/a
Interest crediting rate3.78 %3.85 %3.50 %n/an/an/a
Schedule of Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income
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 BenefitsOPEB
202520242023202520242023
(In millions)
Components of net benefit cost (credit):
Service cost$50 $52 $55 $1 $1 $1 
Interest cost91 91 107 8 8 10 
Expected return on assets(109)(106)(117)(15)(14)(13)
Amortization of prior service cost (credit)— — 1 (1)(3)(3)
Amortization of net actuarial loss (gain)8 22 35 (16)(17)(16)
Settlement loss
— — 46 — — — 
Net benefit cost (credit)40 59 127 (23)(25)(21)
Other changes in plan assets and benefit obligations recognized in OCI:
Net (gain) loss arising during period(46)(132)10 (15)(6)(30)
Amortization or settlement recognition of net actuarial (loss) gain(8)(22)(81)15 16 16 
Amortization of prior service (cost) credit— — (1)1 1 1 
Total recognized in OCI(a)(54)(154)(72)1 11 (13)
Total recognized in net benefit cost (credit) and OCI$(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.
v3.25.4
Stockholders' Equity (Tables)
 12 Months Ended
Dec. 31, 2025
Stockholders' Equity Note [Abstract]  
Schedule of Share Repurchases
We have a board-approved share buy-back program that authorizes share repurchases of up to $3 billion that began in December 2017. All shares we have repurchased are canceled and are no longer outstanding. Activity under the buy-back program is as follows:
Year Ended December 31,
202520242023
(In millions, except per share amounts)
Total value of shares repurchased$— $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.
Schedule of Dividends Paid and Payable
The following table provides information about our per share dividends:
Year Ended December 31,
202520242023
Per share cash dividend declared for the period$1.17 $1.15 $1.13 
Per share cash dividend paid in the period1.1650 1.1450 1.1250 
Schedule of Changes in Accumulated Other Comprehensive Income (Loss)
Changes in the components of our “Accumulated other comprehensive (loss) income” not including noncontrolling interests are summarized as follows:
 Net unrealized
gains/(losses)
on cash flow
hedge derivatives		Pension and
other
postretirement
liability adjustments
Total
Accumulated other
comprehensive
(loss)income
(In millions)
Balance at December 31, 2022$(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 loss120 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 loss11 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 income100 40 140 
Balance at December 31, 2025$67 $(22)$45 
v3.25.4
Related Party Transactions (Tables)
 12 Months Ended
Dec. 31, 2025
Related Party Transactions [Abstract]  
Schedule of Related Party Transactions [Table Text Block]
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,
20252024
(In millions)
Balance sheet location
Accounts receivable$54 $48 
Other current assets4 1 
$58 $49 
Current portion of debt$5 $5 
Accounts payable20 21 
Other current liabilities7 8 
Long-term debt127 132 
Other long-term liabilities and deferred credits69 60 
$228 $226 
Year Ended December 31,
202520242023
(In millions)
Income statement location
Revenues$349 $346 $172 
Operating Costs, Expenses, and Other
Costs of sales$177 $145 $132 
Other operating expenses101 69 57 
v3.25.4
Risk Management (Tables)
 12 Months Ended
Dec. 31, 2025
Derivative Instruments and Hedging Activities Disclosure [Abstract]  
Schedule of 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
Schedule of Interest Rate Risk Management The following table summarizes our outstanding interest rate contracts as of December 31, 2025:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
Fixed-to-variable interest rate contracts(a)
$3,500 Fair value hedgeAugust 2035
(a)Included in “Long-term debt” on our accompanying consolidated balance sheet.
Schedule of Foreign Currency Risk Management The following table summarizes our outstanding foreign currency contracts as of December 31, 2025:
Notional amountAccounting treatmentMaximum term
(In millions)
Derivatives designated as hedging instruments
EUR-to-USD cross currency swap contracts(a)$543 Cash flow hedgeMarch 2027
(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt.
Schedule of Derivative Instruments in Statement of Financial Position, Fair Value
The following table summarizes the fair values of our derivative contracts included in our accompanying consolidated balance sheets:
Fair Value of Derivative Contracts
LocationDerivatives AssetDerivatives Liability
December 31,December 31,
2025202420252024
(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)
Subtotal92 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)
Subtotal36 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)
Subtotal41 — (2)(29)
Total169 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)
Subtotal79 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)
Total79 23 (75)(52)
Total derivatives$248 $62 $(213)$(389)
Schedule of Derivative Assets and Liabilities at Fair Value
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 amountContracts available for nettingCash 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 1Level 2Level 3Gross amountContracts available for nettingCash 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.
Schedule of Derivative Instruments, Gain (Loss) in Statements of Income
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 relationshipsLocationGain/(loss) recognized in income on derivatives and related hedged item
  Year Ended December 31,
  202520242023
(In millions)
Interest rate contractsInterest, 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 EndedYear Ended
 December 31, December 31,
 202520242023 202520242023
(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 contracts67 (24)30 Other, net69 (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 hedgesLocationGain/(loss) recognized in income on derivatives
 Year Ended December 31,
 202520242023
(In millions)
Energy commodity derivative contracts
Revenues—Commodity sales
$79 $20 $75 
Costs of sales
(61)(89)100 
 
Earnings from equity investments1 — 2 
Interest rate contractsInterest, 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.
v3.25.4
Revenue Recognition (Tables)
 12 Months Ended
Dec. 31, 2025
Revenue from Contract with Customer [Abstract]  
Schedule of Disaggregation of Revenue
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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$4,254 $221 $870 $1 $(4)$5,342 
Fee-based services1,161 1,090 431 45 (8)2,719 
Total services5,415 1,311 1,301 46 (12)8,061 
Commodity sales
Natural gas sales3,909 — — 49 (9)3,949 
Product sales1,001 1,157 56 857 (8)3,063 
Other sales29 — — 103 (3)129 
Total commodity sales4,939 1,157 56 1,009 (20)7,141 
Total revenues from contracts with customers10,354 2,468 1,357 1,055 (32)15,202 
Other revenues
Leasing services(b)
455 192 747 70 — 1,464 
Derivatives adjustments on commodity sales96 — — 30 — 126 
Other104 26 — 15 — 145 
Total other revenues655 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$3,893 $220 $846 $2 $(4)$4,957 
Fee-based services1,044 1,059 460 41 (7)2,597 
Total services4,937 1,279 1,306 43 (11)7,554 
Commodity sales
Natural gas sales2,303 — — 43 (6)2,340 
Product sales965 1,444 50 1,031 (4)3,486 
Other sales20 — — 85 (2)103 
Total commodity sales3,288 1,444 50 1,159 (12)5,929 
Total revenues from contracts with customers8,225 2,723 1,356 1,202 (23)13,483 
Other revenues
Leasing services(b)
459 209 666 66 — 1,400 
Derivatives adjustments on commodity sales113 (1)— (85)— 27 
Other145 24 — 21 — 190 
Total other revenues717 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues from contracts with customers(a)
Services
Firm services$3,543 $171 $819 $1 $3 $4,537 
Fee-based services1,008 1,036 427 40 (9)2,502 
Total services4,551 1,207 1,246 41 (6)7,039 
Commodity sales
Natural gas sales2,631 — — 43 (8)2,666 
Product sales1,110 1,635 33 1,114 (8)3,884 
Other sales20 — — 42 (4)58 
Total commodity sales3,761 1,635 33 1,199 (20)6,608 
Total revenues from contracts with customers8,312 2,842 1,279 1,240 (26)13,647 
Other revenues
Leasing services(b)
475 200 638 55 — 1,368 
Derivatives adjustments on commodity sales285 — — (107)— 178 
Other96 24 — 21 — 141 
Total other revenues856 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.
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:
202620272028 and thereafter
(In billions)
Estimated revenue as of December 31, 2025
$5 $5 $26 
v3.25.4
Reportable Segments (Tables)
 12 Months Ended
Dec. 31, 2025
Segment Reporting [Abstract]  
Schedule of Segment Reporting Information, by Segment
Financial information by segment follows: 

 Year Ended December 31, 2025
Reportable Segments
 Natural Gas PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$10,990 $2,686 $2,094 $1,167 $— $16,937 
Intersegment revenues19 — 10 3 (32)— 
Total revenues11,009 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 expenditures2,092 242 326 328 38 3,026 
Segment balance sheet information:
Investments6,962 381 122 67 — 7,532 
Other intangibles, net900 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$8,930 $2,955 $2,013 $1,202 $— $15,100 
Intersegment revenues12 — 9 2 (23)— 
Total revenues8,942 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 investments748 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 expenditures1,654 210 385 346 34 2,629 
Segment balance sheet information:
Investments7,252 387 132 74 — 7,845 
Other intangibles, net687 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 PipelinesProducts PipelinesTerminals
CO2
Corporate and EliminationsTotal
(In millions)
Revenues
Revenues from external customers$9,152 $3,066 $1,911 $1,205 $— $15,334 
Intersegment revenues16 — 6 4 (26)— 
Total revenues9,168 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 expenditures1,299 221 406 355 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.
Schedule of Revenue and Long-lived Assets from External Customers Attributed to Foreign Countries by Geographic Area [Table Text Block]
Following is geographic information regarding the revenues and long-lived assets of our business:
 Year Ended December 31,
 202520242023
(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,
 202520242023
(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 
v3.25.4
Leases (Tables)
 12 Months Ended
Dec. 31, 2025
Leases [Abstract]  
Lease, Cost [Table Text Block]
Following are components of our lease cost:
Year Ended December 31,
202520242023
(In millions)
Operating leases$74 $80 $71 
Short-term and variable leases152 131 127 
Total lease cost$226 $211 $198 

Other information related to our operating leases are as follows:
Year Ended December 31,
202520242023
(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 retirements25 36 56 
Amortization of ROU assets62 68 58 
Weighted average remaining lease term
8.06 years
8.15 years
8.72 years
Weighted average discount rate4.85 %4.84 %4.59 %

Amounts recognized in the accompanying consolidated balance sheets are as follows:
December 31,
Lease Activity(a)Balance sheet location20252024
(In millions)
ROU assetsDeferred charges and other assets$216 $253 
Short-term lease liabilityOther current liabilities49 60 
Long-term lease liabilityOther long-term liabilities and deferred credits167 193 
(a)We have immaterial financing leases recorded as of December 31, 2025 and 2024.
Lessee, Operating Lease, Liability, Maturity [Table Text Block]
Operating lease liabilities under non-cancellable leases (excluding short-term leases) as of December 31, 2025 are as follows:
YearCommitment
 (In millions)
2026$59 
202741 
202827 
202925 
203021 
Thereafter105 
Total lease payments278 
Less: Interest(62)
Present value of lease liabilities$216 
v3.25.4
Summary of Significant Accounting Policies - Property, Plant and Equipment (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Accounting Policies [Abstract]    
Balance at beginning of period $ 248 $ 231
Accretion expense 14 13
Divestitures 0 (33)
Acquisitions 0 43
New obligations 23 10
Settlements (30) (16)
Balance at end of period 255 248
Asset Retirement Obligation, Current $ 2 $ 2
v3.25.4
Summary of Significant Accounting Policies - Goodwill (Details)
May 31, 2025
segment
Accounting Policies [Abstract]  
Number of Reporting Units 7
v3.25.4
Summary of Significant Accounting Policies - Other Intangibles (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Other Intangibles      
Gross $ 3,580 $ 3,543  
Accumulated amortization (1,850) (1,783)  
Net carrying amount 1,730 1,760  
Amortization expense 190 $ 197 $ 202
Estimated amortization expense:      
2026 184    
2027 188    
2028 187    
2029 186    
2030 $ 186    
v3.25.4
Summary of Significant Accounting Policies - Operations and Maintenance (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Operating Expense      
Results of Operations for Oil and Gas Producing Activities, by Geographic Area [Line Items]      
Results of Operations, Expense from Oil and Gas Producing Activities $ 382 $ 402 $ 393
v3.25.4
Summary of Significant Accounting Policies - Leases (Details)
Dec. 31, 2025
Minimum  
Lessee, Operating Lease, Remaining Lease Term 1 year
Maximum  
Lessee, Operating Lease, Remaining Lease Term 45 years
v3.25.4
Summary of Significant Accounting Policies - Variable Interest Entities (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Variable Interest Entity [Line Items]    
Property, plant, and equipment, net $ 39,331 $ 38,013
Elba Liquefaction Company L.L.C.    
Variable Interest Entity [Line Items]    
Property, plant, and equipment, net $ 1,099 $ 1,129
v3.25.4
Summary of Significant Accounting Policies - Regulatory Assets and Liabilities (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Regulatory Assets    
Current regulatory assets $ 40 $ 25
Non-current regulatory assets 216 231
Total regulatory assets(a) 256 256
Amount recoverable without earning a return $ 171  
Weighted average remaining recovery period 7 years  
Regulatory Liabilities    
Current regulatory liabilities $ 18 35
Non-current regulatory liabilities 199 197
Total regulatory liabilities(b) 217 $ 232
Amount expected to be credited to shippers over remaining weighted average period $ 109  
Remaining weighted average period 10 years  
Amount not subject to defined crediting period $ 90  
Loss on Disposal of Assets    
Regulatory Assets    
Total regulatory assets(a) 80  
Income Tax Gross Up on AFUDC Equity    
Regulatory Assets    
Total regulatory assets(a) 39  
Other Regulatory Assets (Liabilities)    
Regulatory Assets    
Total regulatory assets(a) $ 137  
v3.25.4
Summary of Significant Accounting Policies - Earnings per share (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Net Income Available to Stockholders $ 3,056 $ 2,613 $ 2,391
Less: Net Income Allocated to Participating Securities $ (16) $ (15) $ (14)
Basic Weighted Average Shares Outstanding 2,223 2,220 2,234
Diluted Weighted Average Shares Outstanding 2,223 2,220 2,234
Basic EPS $ 1.37 $ 1.17 $ 1.06
Diluted EPS $ 1.37 $ 1.17 $ 1.06
Unvested stock awards      
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Antidilutive securities 13 13 13
Convertible trust preferred securities      
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Antidilutive securities 3 3 3
Class P      
Earnings Per Share, Diluted, by Common Class, Including Two Class Method [Line Items]      
Net Income Available to Stockholders $ 3,040 $ 2,598 $ 2,377
v3.25.4
Acquisitions and Divestitures - Schedule of Recognized Identified Assets and Liabilities Assumed (Details)
$ in Millions
 12 Months Ended
Feb. 18, 2025
USD ($)
mi
Bcf
Dec. 28, 2023
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2025
USD ($)
Jun. 10, 2024
USD ($)
Dec. 31, 2023
USD ($)
Jun. 01, 2023
USD ($)
Business Combination [Line Items]              
Resulting goodwill     $ 20,084 $ 20,084   $ 20,121  
Equity Investments     7,845 7,532      
Adjustment to noncontrolling interest     38        
Goodwill adjustment     (28)        
Dos Caminos, LLC              
Business Combination [Line Items]              
Equity Investments     188 $ 181      
Ownership Interest       50.00%      
North McElroy              
Business Combination [Line Items]              
Purchase price         $ 61    
Current assets         1    
Property, plant, & equipment         102    
Other long-term assets         0    
Current liabilities         0    
Long-term liabilities         (42)    
Non-controlling interest         0    
Resulting goodwill         $ 0    
STX Midstream              
Business Combination [Line Items]              
Purchase price   $ 1,829          
Current assets   25          
Property, plant, & equipment   1,199          
Other long-term assets   549          
Current liabilities   (6)          
Long-term liabilities   0          
Non-controlling interest   (66)          
Resulting goodwill   128          
Business combination, customer contracts   $ 357          
Weighted average amortization period, customer relationship   15 years          
Adjustment to noncontrolling interest     38        
Measurement period adjustments     10        
Goodwill adjustment     (28)        
Goodwill expected to be tax deductible   $ 124          
STX Midstream | NET Mexico              
Business Combination [Line Items]              
Ownership percentage   90.00%          
STX Midstream | Dos Caminos, LLC              
Business Combination [Line Items]              
Equity Investments   $ 192          
Ownership Interest   50.00%          
Diamond M              
Business Combination [Line Items]              
Purchase price             $ 13
Current assets             0
Property, plant, & equipment             25
Other long-term assets             0
Current liabilities             0
Long-term liabilities             (12)
Non-controlling interest             0
Resulting goodwill             $ 0
Diamond M, Additional Interest              
Business Combination [Line Items]              
Purchase price     $ 3        
North Dakota Gas Gathering and Processing System              
Business Combination [Line Items]              
Purchase price $ 648            
Current assets 16            
Property, plant, & equipment 497            
Other long-term assets 160            
Current liabilities (5)            
Long-term liabilities (20)            
Non-controlling interest 0            
Resulting goodwill $ 0            
Weighted average amortization period, customer relationship 15 years            
North Dakota Gas Gathering and Processing System | Processing Facility              
Business Combination [Line Items]              
Asset capacity | Bcf 0.27            
North Dakota Gas Gathering and Processing System | Gas Gathering Pipeline              
Business Combination [Line Items]              
Asset capacity | Bcf 0.35            
Length of pipeline | mi 104            
v3.25.4
Acquisitions and Divestitures - Sale of Eaglehawk (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Business Combination [Line Items]      
Proceeds from Sale of Investment $ 382 $ 0 $ 0
Gain on sale of interest in equity investment $ 123 $ 0 $ 0
v3.25.4
Acquisitions and Divestitures - CO2 Divestiture (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Gain on divestiture $ 6 $ 74 $ 15
Asset retirement obligation, liabilities divested $ 0 33  
CO2      
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]      
Proceeds from divestiture   18  
Gain on divestiture   40  
Asset retirement obligation, liabilities divested   $ 33  
v3.25.4
Income Taxes - Income Tax Provision (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Components of Income Before Income Taxes      
U.S. $ 3,990 $ 3,402 $ 3,192
Foreign 2 5 9
Income Before Income Taxes 3,992 3,407 3,201
Current tax expense      
Federal 23 11 0
State 25 26 5
Foreign 4 3 0
Total 52 40 5
Deferred tax expense      
Federal 729 602 619
State 51 45 91
Total 780 647 710
Total $ 832 $ 687 $ 715
v3.25.4
Income Taxes - Schedule of Effective Income Tax Rate Reconciliation (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Amount:      
Federal income tax $ 838 $ 716 $ 672
State income tax, net of federal benefit 69 64 97
Foreign tax effects 3 2 0
Investment tax credit (21) (42) (1)
Other credit 0 (1) (5)
Changes in Valuation Allowances 0 0 4
Dividend received deduction (36) (34) (34)
Other (23) (19) (16)
Changes in unrecognized tax benefits 2 1 (2)
Total $ 832 $ 687 $ 715
Percent:      
Federal income tax, percent 21.00% 21.00% 21.00%
State income tax, net of federal benefit, percent 1.70% 1.90% 3.00%
Foreign tax effects, percent 0.10% 0.10% 0.00%
Investment tax credit, percent (0.50%) (1.20%) 0.00%
Other credit, percent 0.00% 0.00% (0.10%)
Changes in Valuation Allowances, percent 0.00% 0.00% 0.10%
Dividend received deduction, percent (0.90%) (1.00%) (1.10%)
Other, percent (0.70%) (0.60%) (0.50%)
Changes in unrecognized tax benefits, percent 0.10% 0.00% (0.10%)
Total, percent 20.80% 20.20% 22.30%
v3.25.4
Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
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)
v3.25.4
Income Taxes - Valuation Allowance (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Valuation Allowance [Line Items]  
Balance at beginning of period $ 64
Balance at end of period 72
Addition for state NOL | States  
Valuation Allowance [Line Items]  
Change in valuation allowances 6
State rate changes | States  
Valuation Allowance [Line Items]  
Change in valuation allowances (1)
Currency Fluctuation  
Valuation Allowance [Line Items]  
Change in valuation allowances $ 3
v3.25.4
Income Taxes - Deferred Tax Assets and Valuation Allowances (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Deferred tax assets and valuation allowances:    
Net operating loss, deferred tax assets $ 1,017 $ 1,416
Tax credits, deferred tax assets 265 $ 312
General Business Credits | Expires from 2037 - 2045    
Deferred tax assets and valuation allowances:    
Tax credits, unused amount 265  
Tax credits, deferred tax assets 265  
Tax credits, valuation allowance 0  
Domestic Tax Jurisdiction | Indefinite Tax Period    
Deferred tax assets and valuation allowances:    
Net operating loss, unused amount 3,899  
Net operating loss, deferred tax assets 819  
Net operating loss, valuation allowance 0  
States | Expires from 2025 - 2045    
Deferred tax assets and valuation allowances:    
Net operating loss, unused amount 4,137  
Net operating loss, deferred tax assets 171  
Net operating loss, valuation allowance (45)  
Foreign | Indefinite Tax Period    
Deferred tax assets and valuation allowances:    
Net operating loss, unused amount 79  
Net operating loss, deferred tax assets 27  
Net operating loss, valuation allowance $ (27)  
v3.25.4
Income Taxes - Unrecognized Tax Benefits (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Unrecognized Tax Benefits      
Balance at beginning of period $ 19 $ 18 $ 23
Reductions based on statute expirations (2) (3) (5)
Audit settlement (1) 0 (1)
Additions to state reserves for prior years 5 4 1
Balance at end of period 21 $ 19 $ 18
Other Disclosures      
Amounts which, if recognized, would affect the effective tax rate $ 21    
v3.25.4
Income Taxes - Income taxes paid (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Total Income Taxes Paid $ 47 $ 33 $ 11
Transferrable State Tax Credits, Purchase Amount 4    
U.S.      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Federal 20 10 0
TEXAS      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 12 9 6
PENNSYLVANIA      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 3 4 2
LOUISIANA      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 3 2 0
CALIFORNIA      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 3 2 0
NEW HAMPSHIRE      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 0 0 1
UTAH      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 0 1 1
NEW MEXICO      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 0 0 (2)
Other States      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
States 3 4 0
Mexico      
Income Tax Paid, by Individual Jurisdiction [Line Items]      
Foreign $ 3 $ 1 $ 3
v3.25.4
Property, Plant and Equipment, net (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Property, Plant and Equipment [Line Items]      
Property, plant, and equipment, net $ 39,331 $ 38,013  
Depreciation Depletion and Amortization Expense for Property, Plant and Equipment 2,233 2,127 $ 2,020
Interstate Natural Gas FERC-Regulated      
Property, Plant and Equipment [Line Items]      
Accumulated depreciation, depletion and amortization (11,092) (10,712)  
Depreciable assets 12,733 12,295  
Property, plant, and equipment, net 13,241 12,914  
Interstate Natural Gas FERC-Regulated | Pipelines      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 12,583 12,376  
Interstate Natural Gas FERC-Regulated | Pipelines | Minimum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 1.09%    
Interstate Natural Gas FERC-Regulated | Pipelines | Maximum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 6.67%    
Interstate Natural Gas FERC-Regulated | Equipment      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 10,118 9,488  
Interstate Natural Gas FERC-Regulated | Equipment | Minimum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 1.09%    
Interstate Natural Gas FERC-Regulated | Equipment | Maximum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 6.67%    
Interstate Natural Gas FERC-Regulated | Other      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 1,124 1,143  
Interstate Natural Gas FERC-Regulated | Other | Minimum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 0.00%    
Interstate Natural Gas FERC-Regulated | Other | Maximum      
Property, Plant and Equipment [Line Items]      
Composite Depreciation Rates 33.00%    
Interstate Natural Gas FERC-Regulated | Land and land rights-of-way      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 54 51  
Interstate Natural Gas FERC-Regulated | Construction work in process      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross 454 568  
Other      
Property, Plant and Equipment [Line Items]      
Accumulated depreciation, depletion and amortization (12,970) (11,470)  
Depreciable assets 23,942 23,293  
Property, plant, and equipment, net 26,090 25,099  
Other | Pipelines      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 9,697 8,933  
Other | Pipelines | Minimum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 5 years    
Composite Depreciation Rates 0.09%    
Other | Pipelines | Maximum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 40 years    
Composite Depreciation Rates 33.33%    
Other | Equipment      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 21,425 20,243  
Other | Equipment | Minimum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 5 years    
Composite Depreciation Rates 0.09%    
Other | Equipment | Maximum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 40 years    
Composite Depreciation Rates 33.33%    
Other | Other      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 5,790 5,587  
Other | Other | Minimum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 3 years    
Composite Depreciation Rates 0.00%    
Other | Other | Maximum      
Property, Plant and Equipment [Line Items]      
Straight-Line Estimated Useful Life 10 years    
Composite Depreciation Rates 33.33%    
Other | Land and land rights-of-way      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 785 786  
Other | Construction work in process      
Property, Plant and Equipment [Line Items]      
Property, Plant and Equipment, Gross $ 1,363 $ 1,020  
v3.25.4
Investments - Equity investments (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]      
Equity Investments $ 7,532 $ 7,845  
Earnings from equity invesments, excluding amortization of excess cost 942 890 $ 838
Amortization of excess cost $ (46) (50) (66)
Related Party | NGPL Holdings, LLC      
Schedule of Equity Method Investments [Line Items]      
Interest rate, stated percentage 6.75%    
Note receivable $ 375 375  
Earnings from equity investments | Related Party | NGPL Holdings, LLC      
Schedule of Equity Method Investments [Line Items]      
Interest income $ 25 25 25
Citrus Corporation      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 1,819 1,794  
Earnings from equity invesments, excluding amortization of excess cost $ 153 134 143
SNG      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 1,660 1,734  
Earnings from equity invesments, excluding amortization of excess cost $ 127 145 140
PHP      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 27.74%    
Equity Investments $ 736 736  
Earnings from equity invesments, excluding amortization of excess cost $ 92 91 70
NGPL Holdings, LLC      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 37.50%    
Equity Investments $ 645 618  
Earnings from equity invesments, excluding amortization of excess cost $ 130 117 121
GCX      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 34.00%    
Equity Investments $ 630 566  
Earnings from equity invesments, excluding amortization of excess cost $ 90 91 93
Products (SE) Pipe Line Corporation      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 51.17%    
Equity Investments $ 371 371  
Earnings from equity invesments, excluding amortization of excess cost $ 73 72 65
Utopia Holding LLC      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 314 318  
Earnings from equity invesments, excluding amortization of excess cost $ 39 24 22
MEP      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 299 320  
Earnings from equity invesments, excluding amortization of excess cost $ 74 63 87
Gulf LNG      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 206 240  
Earnings from equity invesments, excluding amortization of excess cost $ 27 26 25
Dos Caminos, LLC      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 50.00%    
Equity Investments $ 181 188  
Earnings from equity invesments, excluding amortization of excess cost $ 22 16 0
Red Cedar Gathering Company      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest 49.00%    
Equity Investments $ 168 168  
Earnings from equity invesments, excluding amortization of excess cost 3 $ 7 15
EagleHawk      
Schedule of Equity Method Investments [Line Items]      
Ownership Interest   25.00%  
Equity Investments 0 $ 266  
Earnings from equity invesments, excluding amortization of excess cost 34 26 18
All others      
Schedule of Equity Method Investments [Line Items]      
Equity Investments 503 526  
Earnings from equity invesments, excluding amortization of excess cost $ 78 $ 78 39
Double Eagle Pipeline LLC      
Schedule of Equity Method Investments [Line Items]      
Impairments of equity investments     $ 67
v3.25.4
Investments - Summary of Investments (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Schedule of Equity Method Investments [Line Items]      
Revenues $ 16,937 $ 15,100 $ 15,334
Costs and expenses 12,213 10,716 11,071
Net income 3,160 2,720 2,486
Current assets 2,754 2,521  
Current liabilities 4,322 5,101  
Non-current liabilities 35,977 34,439  
Partners’/owners’ equity 31,162 30,531  
Equity Method Investment, Nonconsolidated Investee or Group of Investees      
Schedule of Equity Method Investments [Line Items]      
Revenues 6,854 6,607 6,249
Costs and expenses 4,798 4,541 4,262
Net income 2,056 2,066 $ 1,987
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  
v3.25.4
Goodwill (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2024
Dec. 31, 2025
May 31, 2025
Dec. 31, 2023
Goodwill [Line Items]        
Acquisition(a) $ (28)      
Divestiture(b) (9)      
Goodwill 20,084 $ 20,084   $ 20,121
Goodwill, Impaired, Accumulated Impairment Loss   (6,786)   (6,786)
Natural Gas Pipelines        
Goodwill [Line Items]        
Acquisition(a) (28)      
Divestiture(b) 0      
Goodwill 16,720 16,720   16,748
Goodwill, Impaired, Accumulated Impairment Loss   (4,240)   (4,240)
Products Pipelines        
Goodwill [Line Items]        
Acquisition(a) 0      
Divestiture(b) 0      
Goodwill 1,529 1,529   1,529
Goodwill, Impaired, Accumulated Impairment Loss   (1,267)   (1,267)
Terminals        
Goodwill [Line Items]        
Acquisition(a) 0      
Divestiture(b) 0      
Goodwill 802 802   802
Goodwill, Impaired, Accumulated Impairment Loss   (679)   (679)
CO2        
Goodwill [Line Items]        
Acquisition(a) 0      
Divestiture(b) (9)      
Goodwill $ 1,033 1,033   1,042
Goodwill, Impaired, Accumulated Impairment Loss   (600)   $ (600)
ETV        
Goodwill [Line Items]        
Goodwill   $ 114    
Minimum | Natural Gas Pipelines - Nonregulated        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | Natural Gas Pipelines - Regulated        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | Products Pipelines        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | Products Pipelines, Terminals        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | Terminals        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | CO2, Excluding ETV        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
Minimum | ETV        
Goodwill [Line Items]        
Fair value in excess of their respective carrying values (percentage)     10.00%  
v3.25.4
Debt - Schedule of Debt (Details) - USD ($)
$ in Millions
May 01, 2025
Dec. 31, 2025
Dec. 31, 2024
Debt Instrument [Line Items]      
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
Commercial paper notes      
Debt Instrument [Line Items]      
Less: Current portion of debt   $ 13 $ 331
Weighted average interest rate   3.85% 4.60%
Credit facility and commercial paper borrowings(a)      
Debt Instrument [Line Items]      
Less: Current portion of debt   $ 13 $ 331
EPC Building, LLC, promissory note, 3.967%, due January 2024 through December 2035 | EPC Building LLC      
Debt Instrument [Line Items]      
Interest rate, stated percentage   3.967%  
Total debt – KMI and Subsidiaries   $ 290 310
Trust I Preferred Securities, 4.75%, due March 2028(d) | Capital Trust I      
Debt Instrument [Line Items]      
Interest rate, stated percentage   4.75%  
Total debt – KMI and Subsidiaries   $ 221 221
Less: Current portion of debt   111 111
Other miscellaneous debt(e)      
Debt Instrument [Line Items]      
Total debt – KMI and Subsidiaries   159 205
Less: Current portion of debt   27 $ 67
Senior Notes      
Debt Instrument [Line Items]      
Proceeds from debt, net $ 1,834    
Senior Notes | 4.30%, due June 2025      
Debt Instrument [Line Items]      
Interest rate, stated percentage     4.30%
Total debt – KMI and Subsidiaries   0 $ 1,500
Less: Current portion of debt   $ 0 1,500
Senior Notes | 1.75%, due November 2026      
Debt Instrument [Line Items]      
Interest rate, stated percentage   1.75%  
Total debt – KMI and Subsidiaries   $ 500 500
Less: Current portion of debt   $ 500 0
Senior Notes | 6.70%, due February 2027      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.70%  
Total debt – KMI and Subsidiaries   $ 7 7
Senior Notes | 2.25%, due March 2027(c)      
Debt Instrument [Line Items]      
Interest rate, stated percentage   2.25%  
Total debt – KMI and Subsidiaries   $ 587 518
Senior Notes | 6.67%, due November 2027      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.67%  
Total debt – KMI and Subsidiaries   $ 7 7
Senior Notes | 4.30%, due March 2028      
Debt Instrument [Line Items]      
Interest rate, stated percentage   4.30%  
Total debt – KMI and Subsidiaries   $ 1,250 1,250
Senior Notes | 7.25%, due March 2028      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.25%  
Total debt – KMI and Subsidiaries   $ 32 32
Senior Notes | 6.95%, due June 2028      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.95%  
Total debt – KMI and Subsidiaries   $ 31 31
Senior Notes | 5.00%, due February 2029      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.00%  
Total debt – KMI and Subsidiaries   $ 1,250 1,250
Senior Notes | 5.10% due August 2029      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.10%  
Total debt – KMI and Subsidiaries   $ 500 500
Senior Notes | 5.15% due June 2030      
Debt Instrument [Line Items]      
Interest rate, stated percentage 5.15% 5.15%  
Total debt – KMI and Subsidiaries $ 1,100 $ 1,100 0
Senior Notes | 8.05%, due October 2030      
Debt Instrument [Line Items]      
Interest rate, stated percentage   8.05%  
Total debt – KMI and Subsidiaries   $ 234 234
Senior Notes | 2.00%, due February 2031      
Debt Instrument [Line Items]      
Interest rate, stated percentage   2.00%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 7.40%, due March 2031      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.40%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 7.80%, due August 2031      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.80%  
Total debt – KMI and Subsidiaries   $ 537 537
Senior Notes | 7.75%, due January 2032      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.75%  
Total debt – KMI and Subsidiaries   $ 1,005 1,005
Senior Notes | 7.75%, due March 2032      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.75%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 4.80%, due February 2033      
Debt Instrument [Line Items]      
Interest rate, stated percentage   4.80%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 5.20%, due June 2033      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.20%  
Total debt – KMI and Subsidiaries   $ 1,500 1,500
Senior Notes | 7.30%, due August 2033      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.30%  
Total debt – KMI and Subsidiaries   $ 500 500
Senior Notes | 5.40%, due February 2034      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.40%  
Total debt – KMI and Subsidiaries   $ 1,000 1,000
Senior Notes | 5.30%, due December 2034      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.30%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 5.80%, due March 2035      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.80%  
Total debt – KMI and Subsidiaries   $ 500 500
Senior Notes | 5.85% due June 2035      
Debt Instrument [Line Items]      
Interest rate, stated percentage 5.85% 5.85%  
Total debt – KMI and Subsidiaries $ 750 $ 750 0
Senior Notes | 7.75%, due October 2035      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.75%  
Total debt – KMI and Subsidiaries   $ 1 1
Senior Notes | 6.40%, due January 2036      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.40%  
Total debt – KMI and Subsidiaries   $ 36 36
Senior Notes | 6.50%, due February 2037      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.50%  
Total debt – KMI and Subsidiaries   $ 400 400
Senior Notes | 7.42%, due February 2037      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.42%  
Total debt – KMI and Subsidiaries   $ 47 47
Senior Notes | 6.95%, due January 2038      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.95%  
Total debt – KMI and Subsidiaries   $ 1,175 1,175
Senior Notes | 6.50%, due September 2039      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.50%  
Total debt – KMI and Subsidiaries   $ 600 600
Senior Notes | 6.55%, due September 2040      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.55%  
Total debt – KMI and Subsidiaries   $ 400 400
Senior Notes | 7.50%, due November 2040      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.50%  
Total debt – KMI and Subsidiaries   $ 375 375
Senior Notes | 6.375%, due March 2041      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.375%  
Total debt – KMI and Subsidiaries   $ 600 600
Senior Notes | 5.625%, due September 2041      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.625%  
Total debt – KMI and Subsidiaries   $ 375 375
Senior Notes | 5.00%, due August 2042      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.00%  
Total debt – KMI and Subsidiaries   $ 625 625
Senior Notes | 4.70%, due November 2042      
Debt Instrument [Line Items]      
Interest rate, stated percentage   4.70%  
Total debt – KMI and Subsidiaries   $ 475 475
Senior Notes | 5.00%, due March 2043      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.00%  
Total debt – KMI and Subsidiaries   $ 700 700
Senior Notes | 5.50%, due March 2044      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.50%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 5.40%, due September 2044      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.40%  
Total debt – KMI and Subsidiaries   $ 550 550
Senior Notes | 5.55%, due June 2045      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.55%  
Total debt – KMI and Subsidiaries   $ 1,750 1,750
Senior Notes | 5.05%, due February 2046      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.05%  
Total debt – KMI and Subsidiaries   $ 800 800
Senior Notes | 5.20%, due March 2048      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.20%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 3.25%, due August 2050      
Debt Instrument [Line Items]      
Interest rate, stated percentage   3.25%  
Total debt – KMI and Subsidiaries   $ 500 500
Senior Notes | 3.60%, due February 2051      
Debt Instrument [Line Items]      
Interest rate, stated percentage   3.60%  
Total debt – KMI and Subsidiaries   $ 1,050 1,050
Senior Notes | 5.45%, due August 2052      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.45%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 5.95% due August 2054      
Debt Instrument [Line Items]      
Interest rate, stated percentage   5.95%  
Total debt – KMI and Subsidiaries   $ 750 750
Senior Notes | 7.45%, due March 2098      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.45%  
Total debt – KMI and Subsidiaries   $ 26 26
Senior Notes | 7.00%, due March 2027 | TGP      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.00%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 7.00%, due October 2028 | TGP      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.00%  
Total debt – KMI and Subsidiaries   $ 400 400
Senior Notes | 2.90%, due March 2030 | TGP      
Debt Instrument [Line Items]      
Interest rate, stated percentage   2.90%  
Total debt – KMI and Subsidiaries   $ 1,000 1,000
Senior Notes | 8.375%, due June 2032 | TGP      
Debt Instrument [Line Items]      
Interest rate, stated percentage   8.375%  
Total debt – KMI and Subsidiaries   $ 240 240
Senior Notes | 7.625%, due April 2037 | TGP      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.625%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 7.50%, due November 2026      
Debt Instrument [Line Items]      
Less: Current portion of debt   $ 200 0
Senior Notes | 7.50%, due November 2026 | EPNG      
Debt Instrument [Line Items]      
Interest rate, stated percentage   7.50%  
Total debt – KMI and Subsidiaries   $ 200 200
Senior Notes | 3.50%, due February 2032 | EPNG      
Debt Instrument [Line Items]      
Interest rate, stated percentage   3.50%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 8.375%, due June 2032 | EPNG      
Debt Instrument [Line Items]      
Interest rate, stated percentage   8.375%  
Total debt – KMI and Subsidiaries   $ 300 300
Senior Notes | 4.15%, due August 2026      
Debt Instrument [Line Items]      
Less: Current portion of debt   $ 375 0
Senior Notes | 4.15%, due August 2026 | CIG      
Debt Instrument [Line Items]      
Interest rate, stated percentage   4.15%  
Total debt – KMI and Subsidiaries   $ 375 375
Senior Notes | 6.85%, due June 2037 | CIG      
Debt Instrument [Line Items]      
Interest rate, stated percentage   6.85%  
Total debt – KMI and Subsidiaries   $ 100 $ 100
v3.25.4
Debt - Additional Information (Details)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
$ / shares
$ / €
shares
Dec. 31, 2024
USD ($)
$ / €
Debt Instrument [Line Items]    
Aggregate principal amount $ 31,823 $ 31,788
Exchange rate | $ / € 1.1746 1.0354
Debt Fair Value Adjustments $ 180 $ 102
Commercial paper notes    
Debt Instrument [Line Items]    
Weighted average interest rate 3.85% 4.60%
Capital Trust I    
Debt Instrument [Line Items]    
Ownership percentage 100.00%  
Senior Notes    
Debt Instrument [Line Items]    
Redemption Price 100.00%  
2.250% Senior Notes due March 2027 | Senior Notes    
Debt Instrument [Line Items]    
Interest rate, stated percentage 2.25%  
Aggregate principal amount $ 587 $ 518
Change to debt as a result of changes in exchange rate $ 44 (25)
Trust I Preferred Securities, 4.75%, due March 2028(d) | Capital Trust I    
Debt Instrument [Line Items]    
Interest rate, stated percentage 4.75%  
Aggregate principal amount $ 221 $ 221
Trust Convertible Preferred Securities Outstanding | shares 4.4  
Liquidation preference | $ / shares $ 50  
Conversion price | $ / shares $ 25.18  
Trust I Preferred Securities, 4.75%, due March 2028(d) | Capital Trust I | Class P    
Debt Instrument [Line Items]    
Conversion rate 0.7197  
v3.25.4
Debt - Schedule of Current Portion of Debt (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Debt Instrument [Line Items]    
Current portion of debt $ 1,226 $ 2,009
$3.5 billion credit facility due August 20, 2027    
Debt Instrument [Line Items]    
Current portion of debt 0 0
Maximum borrowing capacity 3,500  
Commercial paper notes    
Debt Instrument [Line Items]    
Current portion of debt 13 $ 331
Maximum borrowing capacity 3,500  
4.30%, due June 2025 | Senior Notes    
Debt Instrument [Line Items]    
Interest rate, stated percentage   4.30%
Current portion of debt 0 $ 1,500
4.15%, due August 2026 | Senior Notes    
Debt Instrument [Line Items]    
Current portion of debt $ 375 0
4.15%, due August 2026 | CIG | Senior Notes    
Debt Instrument [Line Items]    
Interest rate, stated percentage 4.15%  
1.75%, due November 2026 | Senior Notes    
Debt Instrument [Line Items]    
Interest rate, stated percentage 1.75%  
Current portion of debt $ 500 0
7.50%, due November 2026 | Senior Notes    
Debt Instrument [Line Items]    
Current portion of debt $ 200 0
7.50%, due November 2026 | EPNG | Senior Notes    
Debt Instrument [Line Items]    
Interest rate, stated percentage 7.50%  
Trust I Preferred Securities, 4.75%, due March 2028(d) | Capital Trust I    
Debt Instrument [Line Items]    
Interest rate, stated percentage 4.75%  
Current portion of debt $ 111 111
Current portion of other debt    
Debt Instrument [Line Items]    
Current portion of debt $ 27 $ 67
v3.25.4
Debt - Credit Facilities and Restrictive Covenants (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Line of Credit Facility [Line Items]    
Current portion of debt $ 1,226 $ 2,009
$3.5 billion credit facility due August 20, 2027    
Line of Credit Facility [Line Items]    
Maximum borrowing capacity 3,500  
Borrowing Capacity, Optional Increase $ 1,000  
Maximum ratio of consolidated total funded debt to consolidated earnings before interest income taxes DDA 5.50  
Current portion of debt $ 0 0
Letters of credit outstanding 10  
Remaining borrowing capacity $ 3,477  
$3.5 billion credit facility due August 20, 2027 | Minimum    
Line of Credit Facility [Line Items]    
Standby fee rate 0.10%  
$3.5 billion credit facility due August 20, 2027 | Maximum    
Line of Credit Facility [Line Items]    
Standby fee rate 0.25%  
$3.5 billion credit facility due August 20, 2027 | Secured Overnight Financing Rate (SOFR) | Minimum    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 1.00%  
$3.5 billion credit facility due August 20, 2027 | Secured Overnight Financing Rate (SOFR) | Maximum    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 1.75%  
$3.5 billion credit facility due August 20, 2027 | Federal Funds Rate    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 0.50%  
$3.5 billion credit facility due August 20, 2027 | Eurodollar    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 1.00%  
$3.5 billion credit facility due August 20, 2027 | SOFR Alternative Base Rate | Minimum    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 0.10%  
$3.5 billion credit facility due August 20, 2027 | SOFR Alternative Base Rate | Maximum    
Line of Credit Facility [Line Items]    
Basis spread on variable rate 0.75%  
Commercial paper notes    
Line of Credit Facility [Line Items]    
Maximum borrowing capacity $ 3,500  
Debt term 270 days  
Current portion of debt $ 13 $ 331
v3.25.4
Debt - Schedule of Maturities of Debt (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Debt Disclosure [Abstract]    
2026 $ 1,226  
2027 942  
2028 1,867  
2029 1,781  
2030 2,367  
Thereafter 23,640  
Total debt – KMI and Subsidiaries $ 31,823 $ 31,788
v3.25.4
Debt - Schedule of Debt Fair Value Adjustments (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Debt Disclosure [Abstract]    
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
v3.25.4
Debt - Schedule of Fair Value of Financial Instruments (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Carrying value    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Total debt $ 32,003 $ 31,890
Estimated fair value(a)    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Total debt 31,966 30,794
Estimated fair value(a) | Capital Trust I | Trust I preferred securities, 4.75%, due March 2028    
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]    
Convertible Debt $ 217 $ 201
v3.25.4
Debt - Interest Rates, Interest Rate Swaps and Contingent Debt (Details)
Dec. 31, 2025
Dec. 31, 2024
Debt Disclosure [Abstract]    
Debt, weighted average interest rate 5.59% 5.83%
v3.25.4
Share-based Compensation and Employee Benefits - Summary of Stock Compensation Plans (Details) - Restricted Stock Awards - Class P
 12 Months Ended
Dec. 31, 2025
shares
Directors' Plan  
Share-based Compensation  
Total number of shares of Class P common stock authorized 1,190,000
Vesting period 6 months
Grants during the period (shares) 9,620
LTIP  
Share-based Compensation  
Total number of shares of Class P common stock authorized 63,000,000
Grants during the period (shares) 3,420,000
LTIP | Minimum  
Share-based Compensation  
Vesting period 1 year
LTIP | Maximum  
Share-based Compensation  
Vesting period 10 years
v3.25.4
Share-based Compensation and Employee Benefits - Summary of Activity and Related Balances of Restricted Stock Awards (Details) - LTIP - Restricted Stock Awards - Class P - $ / shares
shares in Thousands
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Shares      
Outstanding at beginning of period (shares) 13,405    
Granted (shares) 3,420    
Vested (shares) (4,573)    
Forfeited (shares) (409)    
Outstanding at end of period (shares) 11,843 13,405  
Weighted Average Grant Date Fair Value      
Outstanding at beginning of period (dollars per share) $ 18.30    
Granted (dollars per share) 27.97 $ 20.27 $ 17.41
Vested (dollars per share) 17.50    
Forfeited (dollars per share) 19.00    
Outstanding at end of period (dollars per share) $ 21.38 $ 18.30  
v3.25.4
Share-based Compensation and Employee Benefits - Summary of Additional Information Related to Restricted Stock Awards (Details) - LTIP - Restricted Stock Awards - Class P - USD ($)
$ / shares in Units, $ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]      
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 68 64 60
Restricted stock awards capitalized 11 $ 10 $ 9
Unrecognized restricted stock awards compensation costs, less estimated forfeitures $ 132    
Weighted average remaining amortization period 2 years 14 days    
v3.25.4
Share-based Compensation and Employee Benefits - Pensions and Other Postretirement Benefit Plans - Narrative (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Savings plan - defined contribution plan      
Pension and Other Postretirement Benefit Plans      
Percentage of eligible compensation contributed 5.00%    
Plan vesting period 2 years    
Pension Benefits      
Pension and Other Postretirement Benefit Plans      
Percentage of employees covered 100.00%    
Vesting period 3 years    
OPEB      
Pension and Other Postretirement Benefit Plans      
Medicare participation, age 65    
Savings plan - defined contribution plan      
Pension and Other Postretirement Benefit Plans      
Plan cost $ 58 $ 56 $ 53
v3.25.4
Share-based Compensation and Employee Benefits - Benefit Obligation, Plan Assets and Funded Status (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Benefits      
Change in benefit obligation:      
Benefit obligation at beginning of period $ 1,809 $ 1,902  
Service cost 50 52 $ 55
Interest cost 91 91 107
Actuarial loss (gain) 27 (82)  
Benefits paid (163) (154)  
Participant contributions 0 0  
Benefit obligation at end of period 1,814 1,809 1,902
Change in plan assets:      
Fair value of plan assets at beginning of period 1,614 1,562  
Actual return on plan assets 183 156  
Employer contributions 50 50  
Participant contributions 0 0  
Benefits paid (163) (154)  
Fair value of plan assets at end of period 1,684 1,614 1,562
Funded status - net (liability) asset at December 31, (130) (195)  
Amounts recognized in the consolidated balance sheets:      
Non-current benefit asset(a) 0 0  
Current benefit liability 0 0  
Non-current benefit liability (130) (195)  
Funded status - net (liability) asset at December 31, (130) (195)  
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:      
Unrecognized net actuarial (loss) gain (176) (230)  
Unrecognized prior service credit 0 0  
Accumulated other comprehensive (loss) income (176) (230)  
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:      
Accumulated benefit obligation 1,268 1,782  
Fair value of plan assets 1,165 1,614  
OPEB      
Change in benefit obligation:      
Benefit obligation at beginning of period 169 177  
Service cost 1 1 1
Interest cost 8 8 10
Actuarial loss (gain) 7 8  
Benefits paid (24) (26)  
Participant contributions 1 1  
Benefit obligation at end of period 162 169 177
Change in plan assets:      
Fair value of plan assets at beginning of period 331 323  
Actual return on plan assets 44 33  
Employer contributions 0 0  
Participant contributions 1 1  
Benefits paid (24) (26)  
Fair value of plan assets at end of period 352 331 $ 323
Funded status - net (liability) asset at December 31, 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 (98) (102)  
Funded status - net (liability) asset at December 31, 190 162  
Amounts of pre-tax accumulated other comprehensive (loss) income recognized in the consolidated balance sheets:      
Unrecognized net actuarial (loss) gain 139 139  
Unrecognized prior service credit 1 2  
Accumulated other comprehensive (loss) income 140 141  
Information related to plans whose accumulated benefit obligations exceeded the fair value of plan assets:      
Accumulated benefit obligation 113 117  
Fair value of plan assets 0 2  
OPEB | Other Affiliates      
Amounts recognized in the consolidated balance sheets:      
Non-current benefit asset(a) $ 68 $ 59  
v3.25.4
Share-based Compensation and Employee Benefits - Target Asset Allocation (Details)
Dec. 31, 2025
Pension Benefits | Equities | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 42.00%
Pension Benefits | Equities | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 52.00%
Pension Benefits | Fixed Income Securities | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 37.00%
Pension Benefits | Fixed Income Securities | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 47.00%
Pension Benefits | Real Estate | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 2.00%
Pension Benefits | Real Estate | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 12.00%
Pension Benefits | Company Securities | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 0.00%
Pension Benefits | Company Securities | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 10.00%
OPEB | Cash | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 0.00%
OPEB | Cash | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 23.00%
OPEB | Equities | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 43.00%
OPEB | Equities | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 71.00%
OPEB | Fixed Income Securities | Minimum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 26.00%
OPEB | Fixed Income Securities | Maximum  
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]  
Target allocation percentage 50.00%
v3.25.4
Share-based Compensation and Employee Benefits - Fair Value of Pension and OPEB Assets by Level of Assets (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Benefits      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value $ 1,684 $ 1,614 $ 1,562
Pension Benefits | Total      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 573 583  
Pension Benefits | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 147 203  
Pension Benefits | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 426 380  
Pension Benefits | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 1,111 1,031  
Pension Benefits | Short-term Investment Funds | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 27 29  
Pension Benefits | Equities | Total      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 147 203  
Pension Benefits | Equities | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 147 203  
Pension Benefits | Equities | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 0 0  
Pension Benefits | Fixed Income Securities | Total      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 426 380  
Pension Benefits | Fixed Income Securities | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 0 0  
Pension Benefits | Fixed Income Securities | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 426 380  
Pension Benefits | Common/Collective Trusts | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value $ 1,084 $ 1,002  
Pension Benefits | Common/Collective Trusts Invested in Equity Securities | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Percentage of category allocated to investments 65.00% 66.00%  
Pension Benefits | Common/Collective Trusts Invested in Fixed Income Securities | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Percentage of category allocated to investments 23.00% 22.00%  
Pension Benefits | Common/Collective Trusts Invested in Real Estate | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Percentage of category allocated to investments 12.00% 12.00%  
OPEB      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value $ 352 $ 331 $ 323
OPEB | Short-term Investment Funds | Total      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 4 3  
OPEB | Short-term Investment Funds | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 0 0  
OPEB | Short-term Investment Funds | Level 2      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value 4 3  
OPEB | Common/Collective Trusts | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Total plan assets fair value $ 348 $ 328  
OPEB | Common/Collective Trusts Invested in Equity Securities | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Percentage of category allocated to investments 63.00% 62.00%  
OPEB | Common/Collective Trusts Invested in Fixed Income Securities | Measured at NAV      
Defined Benefit Plan Disclosure [Line Items]      
Percentage of category allocated to investments 37.00% 38.00%  
Class P | Pension Benefits | Equities | Level 1      
Defined Benefit Plan Disclosure [Line Items]      
Amount of KMI securities invested in $ 118 $ 167  
v3.25.4
Share-based Compensation and Employee Benefits - Schedule of Expected Payment of Future Benefits and Employer Contributions (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Pension Benefits  
Defined Benefit Plan Disclosure [Line Items]  
Contributions expected in 2026 $ 60
Benefit payments expected in:  
2026 191
2027 186
2028 181
2029 177
2030 170
2031 - 2035 755
OPEB  
Defined Benefit Plan Disclosure [Line Items]  
Contributions expected in 2026 0
Benefit payments expected in:  
2026 22
2027 21
2028 19
2029 18
2030 16
2031 - 2035 $ 62
v3.25.4
Share-based Compensation and Employee Benefits - Schedule of Weighted-Average Actuarial Assumptions (Details)
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Benefits      
Assumptions related to benefit obligations:      
Discount rate 5.32% 5.58%  
Rate of compensation increase 3.50% 3.50%  
Interest crediting rate 3.85% 3.78%  
Assumptions related to benefit costs:      
Discount rate 5.58% 5.13% 5.41%
Expected return on plan assets 7.00% 7.00% 7.00%
Rate of compensation increase 3.50% 3.50% 3.50%
Interest crediting rate 3.78% 3.85% 3.50%
OPEB      
Assumptions related to benefit obligations:      
Discount rate 5.02% 5.44%  
Assumptions related to benefit costs:      
Discount rate 5.44% 5.08% 5.38%
Expected return on plan assets 6.00% 6.00% 6.00%
Actuarial Assumptions      
Weighted-average annual rate of increase in the per capita cost of covered health care benefits 7.60%    
Ultimate health care cost trend rate 4.00%    
v3.25.4
Share-based Compensation and Employee Benefits - Schedule of Components of Net Benefit Cost and Other Amounts Recognized in Other Comprehensive Income (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Pension Benefits      
Components of net benefit cost (credit):      
Service cost $ 50 $ 52 $ 55
Interest cost 91 91 107
Expected return on assets (109) (106) (117)
Amortization of prior service cost (credit) 0 0 1
Amortization of net actuarial loss (gain) 8 22 35
Settlement loss 0 0 46
Net benefit cost (credit) 40 59 127
Other changes in plan assets and benefit obligations recognized in OCI:      
Net (gain) loss arising during period (46) (132) 10
Amortization or settlement recognition of net actuarial (loss) gain (8) (22) (81)
Amortization of prior service (cost) credit 0 0 (1)
Total recognized in OCI(a) (54) (154) (72)
Total recognized in net benefit cost (credit) and OCI (14) (95) 55
Pension Benefits | Other Plans      
Other changes in plan assets and benefit obligations recognized in OCI:      
Total recognized in OCI(a) (1) 1  
OPEB      
Components of net benefit cost (credit):      
Service cost 1 1 1
Interest cost 8 8 10
Expected return on assets (15) (14) (13)
Amortization of prior service cost (credit) (1) (3) (3)
Amortization of net actuarial loss (gain) (16) (17) (16)
Settlement loss 0 0 0
Net benefit cost (credit) (23) (25) (21)
Other changes in plan assets and benefit obligations recognized in OCI:      
Net (gain) loss arising during period (15) (6) (30)
Amortization or settlement recognition of net actuarial (loss) gain 15 16 16
Amortization of prior service (cost) credit 1 1 1
Total recognized in OCI(a) 1 11 (13)
Total recognized in net benefit cost (credit) and OCI $ (22) $ (14) $ (34)
v3.25.4
Stockholders' Equity - Common Equity (Details) - USD ($)
$ / shares in Units, shares in Millions, $ in Millions
 12 Months Ended 98 Months Ended
Jan. 21, 2026
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Feb. 12, 2026
Jul. 19, 2017
Dec. 19, 2014
Class of Stock [Line Items]              
Common share buy-back program, amount           $ 3,000  
Total value of shares repurchased   $ 0 $ 7 $ 522      
Average repurchase price per share   $ 0 $ 16.50 $ 16.56      
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      
Subsequent Event              
Class of Stock [Line Items]              
Total value of shares repurchased         $ 1,472    
Average repurchase price per share         $ 17.09    
Remaining repurchase authorization amount         $ 1,500    
Per share cash dividend declared for the period $ 0.2925            
Equity distribution agreement | Class P              
Class of Stock [Line Items]              
Value of Stock Available for Sale Under Equity Distribution Agreement             $ 5,000
Shares, Issued   0 0 0      
Common stock              
Class of Stock [Line Items]              
Total number of shares repurchased   0 1 32      
Common stock | Subsequent Event              
Class of Stock [Line Items]              
Total number of shares repurchased         86    
v3.25.4
Stockholders' Equity - Accumulated Other Comprehensive Loss (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Balance $ 31,867 $ 31,729 $ 32,114
Balance 32,449 31,867 31,729
Net unrealized gains/(losses) on cash flow hedge derivatives      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Balance (33) (44) (164)
Other comprehensive (loss) gain before reclassifications 184 (29) 155
Losses (gains) reclassified from accumulated other comprehensive loss (84) 40 (35)
Net current-period change in accumulated other comprehensive loss/income 100 11 120
Balance 67 (33) (44)
Pension and other postretirement liability adjustments      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Balance (62) (173) (238)
Other comprehensive (loss) gain before reclassifications 40 111 65
Losses (gains) reclassified from accumulated other comprehensive loss 0 0 0
Net current-period change in accumulated other comprehensive loss/income 40 111 65
Balance (22) (62) (173)
Total Accumulated other comprehensive (loss)income      
Accumulated Other Comprehensive Income (Loss) [Line Items]      
Balance (95) (217) (402)
Other comprehensive (loss) gain before reclassifications 224 82 220
Losses (gains) reclassified from accumulated other comprehensive loss (84) 40 (35)
Net current-period change in accumulated other comprehensive loss/income 140 122 185
Balance $ 45 $ (95) $ (217)
v3.25.4
Related Party Transactions (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Balance sheet location      
Accounts receivable $ 1,714 $ 1,506  
Other current assets 357 246  
Assets 72,748 71,407  
Current portion of debt 1,226 2,009  
Accounts Payable 1,408 1,395  
Other current liabilities 898 878  
Long-term Debt, Excluding Current Maturities 30,777 29,881  
Other long-term liabilities and deferred credits 2,309 2,488  
Total Liabilities 40,299 39,540  
Income statement location      
Revenues 16,937 15,100 $ 15,334
Operating Costs, Expenses, and Other      
Other operating expenses (15) (92) (13)
Related Party      
Balance sheet location      
Accounts receivable 54 48  
Other current assets 4 1  
Assets 58 49  
Current portion of debt 5 5  
Accounts Payable 20 21  
Other current liabilities 7 8  
Long-term Debt, Excluding Current Maturities 127 132  
Other long-term liabilities and deferred credits 69 60  
Total Liabilities 228 226  
Income statement location      
Revenues 349 346 172
Operating Costs, Expenses, and Other      
Costs of sales 177 145 132
Other operating expenses $ 101 $ 69 $ 57
v3.25.4
Commitments and Contingent Liabilities Capital Commitments (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Capital Addition Purchase Commitments  
Unrecorded Unconditional Purchase Obligation [Line Items]  
Capital Commitments $ 2,020
v3.25.4
Commitments and Contingent Liabilities Rights-of-way obligations (Details)
$ in Millions
Dec. 31, 2025
USD ($)
ROW  
Other Commitments [Line Items]  
Contractual Obligation $ 96
v3.25.4
Commitments and Contingent Liabilities Contingent Debt (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
investees
Dec. 31, 2024
USD ($)
investees
Indirect Guarantee of Indebtedness    
Guarantor Obligations [Line Items]    
Guarantor Obligations, Maximum Exposure, Undiscounted $ 127 $ 149
Cortez Pipeline Company    
Guarantor Obligations [Line Items]    
Percentage of Debt Guaranteed 100.00% 100.00%
Cortez Pipeline Company | Indirect Guarantee of Indebtedness    
Guarantor Obligations [Line Items]    
Number of equity investees subject to contingent obligation | investees 1 1
Long-term Debt | Cortez Pipeline Company | Indirect Guarantee of Indebtedness    
Guarantor Obligations [Line Items]    
Guarantor Obligations, Maximum Exposure, Undiscounted $ 91 $ 120
v3.25.4
Risk Management - Energy Commodity Price Risk Management (Details) - Short - Energy commodity derivative contracts
 12 Months Ended
Dec. 31, 2025
Bcf
MMBbls
Designated as Hedging Instrument | Crude Oil Fixed Price  
Derivative [Line Items]  
Net open position (13.8)
Not Designated as Hedging Instrument | Crude Oil Fixed Price  
Derivative [Line Items]  
Net open position (0.8)
Not Designated as Hedging Instrument | Crude Oil Basis  
Derivative [Line Items]  
Net open position (0.9)
Not Designated as Hedging Instrument | Natural Gas Fixed Price  
Derivative [Line Items]  
Net open position | Bcf (63.0)
Not Designated as Hedging Instrument | Natural Gas Basis  
Derivative [Line Items]  
Net open position | Bcf (77.3)
Not Designated as Hedging Instrument | NGL Fixed Price  
Derivative [Line Items]  
Net open position (1.2)
v3.25.4
Risk Management - Interest Rate Risk Management (Details) - Fixed-to-variable interest rate contracts
$ in Millions
Dec. 31, 2025
USD ($)
Fair Value Hedging | Designated as Hedging Instrument  
Derivative [Line Items]  
Notional amount $ 3,500
Long-term Debt  
Derivative [Line Items]  
Principal amount of hedged senior notes $ 3,500
v3.25.4
Risk Management - Foreign Currency Risk Management (Details)
$ in Millions
Dec. 31, 2025
USD ($)
Cash Flow Hedging | Cross Currency Swap Contract  
Derivative [Line Items]  
Notional amount $ 543
v3.25.4
Risk Management - Fair Value of Derivative Contracts (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Derivatives, Fair Value [Line Items]    
Asset derivatives $ 248 $ 62
Liability derivatives (213) (389)
Energy commodity derivative contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 171 35
Liability derivatives (75) (106)
Foreign currency contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 41 0
Liability derivatives (2) (29)
Designated as Hedging Instrument    
Derivatives, Fair Value [Line Items]    
Asset derivatives 169 39
Liability derivatives (138) (337)
Designated as Hedging Instrument | Energy commodity derivative contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 92 19
Liability derivatives 0 (54)
Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 56 10
Designated as Hedging Instrument | Energy commodity derivative contracts | (Other Current Liabilities)    
Derivatives, Fair Value [Line Items]    
Liability derivatives 0 (46)
Designated as Hedging Instrument | Energy commodity derivative contracts | Deferred Charges and Other Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 36 9
Designated as Hedging Instrument | Energy commodity derivative contracts | (Other Long-Term Liabilities and Deferred Credits)    
Derivatives, Fair Value [Line Items]    
Liability derivatives 0 (8)
Designated as Hedging Instrument | Interest rate contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 36 20
Liability derivatives (136) (254)
Designated as Hedging Instrument | Interest rate contracts | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 4 1
Designated as Hedging Instrument | Interest rate contracts | (Other Current Liabilities)    
Derivatives, Fair Value [Line Items]    
Liability derivatives (25) (51)
Designated as Hedging Instrument | Interest rate contracts | Deferred Charges and Other Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 32 19
Designated as Hedging Instrument | Interest rate contracts | (Other Long-Term Liabilities and Deferred Credits)    
Derivatives, Fair Value [Line Items]    
Liability derivatives (111) (203)
Designated as Hedging Instrument | Foreign currency contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 41 0
Liability derivatives (2) (29)
Designated as Hedging Instrument | Foreign currency contracts | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 0 0
Designated as Hedging Instrument | Foreign currency contracts | (Other Current Liabilities)    
Derivatives, Fair Value [Line Items]    
Liability derivatives (2) (3)
Designated as Hedging Instrument | Foreign currency contracts | Deferred Charges and Other Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 41 0
Designated as Hedging Instrument | Foreign currency contracts | (Other Long-Term Liabilities and Deferred Credits)    
Derivatives, Fair Value [Line Items]    
Liability derivatives 0 (26)
Not Designated as Hedging Instrument    
Derivatives, Fair Value [Line Items]    
Asset derivatives 79 23
Liability derivatives (75) (52)
Not Designated as Hedging Instrument | Energy commodity derivative contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 79 15
Liability derivatives (75) (50)
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 75 14
Not Designated as Hedging Instrument | Energy commodity derivative contracts | (Other Current Liabilities)    
Derivatives, Fair Value [Line Items]    
Liability derivatives (74) (35)
Not Designated as Hedging Instrument | Energy commodity derivative contracts | Deferred Charges and Other Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 4 1
Not Designated as Hedging Instrument | Energy commodity derivative contracts | (Other Long-Term Liabilities and Deferred Credits)    
Derivatives, Fair Value [Line Items]    
Liability derivatives (1) (15)
Not Designated as Hedging Instrument | Interest rate contracts    
Derivatives, Fair Value [Line Items]    
Asset derivatives 0 8
Liability derivatives 0 (2)
Not Designated as Hedging Instrument | Interest rate contracts | Other Current Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 0 4
Not Designated as Hedging Instrument | Interest rate contracts | (Other Current Liabilities)    
Derivatives, Fair Value [Line Items]    
Liability derivatives 0 0
Not Designated as Hedging Instrument | Interest rate contracts | Deferred Charges and Other Assets    
Derivatives, Fair Value [Line Items]    
Asset derivatives 0 4
Not Designated as Hedging Instrument | Interest rate contracts | (Other Long-Term Liabilities and Deferred Credits)    
Derivatives, Fair Value [Line Items]    
Liability derivatives $ 0 $ 2
v3.25.4
Risk Management - FV Input Level - Assets (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Derivative [Line Items]    
Gross amount $ 248 $ 62
Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount 171 35
Contracts available for netting (68) (19)
Cash collateral held(a) 0 0
Net amount 103 16
Interest rate contracts    
Derivative [Line Items]    
Gross amount 36 27
Contracts available for netting (6) 0
Cash collateral held(a) 0 0
Net amount 30 27
Foreign currency contracts    
Derivative [Line Items]    
Gross amount 41 0
Contracts available for netting 0 0
Cash collateral held(a) 0 0
Net amount 41 0
Level 1 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount 20 6
Level 1 | Interest rate contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 1 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 2 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount 151 29
Level 2 | Interest rate contracts    
Derivative [Line Items]    
Gross amount 36 27
Level 2 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount 41 0
Level 3 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 3 | Interest rate contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 3 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount $ 0 $ 0
v3.25.4
Risk Management - FV Input Level - Liabilities (Details) - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Derivative [Line Items]    
Gross amount $ (213) $ (389)
Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount (75) (106)
Contracts available for netting 68 19
Cash collateral posted(a)   52
Cash collateral posted (2)  
Net amount (9) (35)
Interest rate contracts    
Derivative [Line Items]    
Gross amount (136) (254)
Contracts available for netting 6 0
Cash collateral posted(a) 0 0
Net amount (130) (254)
Foreign currency contracts    
Derivative [Line Items]    
Gross amount (2) (29)
Contracts available for netting 0 0
Cash collateral posted(a) 0 0
Net amount (2) (29)
Level 1 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount (12) (17)
Level 1 | Interest rate contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 1 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 2 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount (63) (89)
Level 2 | Interest rate contracts    
Derivative [Line Items]    
Gross amount (136) (254)
Level 2 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount (2) (29)
Level 3 | Energy commodity derivative contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 3 | Interest rate contracts    
Derivative [Line Items]    
Gross amount 0 0
Level 3 | Foreign currency contracts    
Derivative [Line Items]    
Gross amount $ 0 $ 0
v3.25.4
Risk Management - FV Hedging Effect on Income Statements (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative [Line Items]      
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments" $ 101 $ 241  
Designated as Hedging Instrument | Fair Value Hedging | Interest rate contracts      
Derivative [Line Items]      
Location Interest, net Interest, net Interest, net
Gain/(loss) recognized in income on derivatives and related hedged item $ 132 $ (3) $ 138
Designated as Hedging Instrument | Fair Value Hedging | Hedged Fixed Rate Debt      
Derivative [Line Items]      
Location Interest, net Interest, net Interest, net
Gain/(loss) recognized in income on derivatives and related hedged item $ (140) $ 5 $ (132)
Cumulative amount of fair value hedging adjustments included in "Debt fair value adjustments" $ 101    
v3.25.4
Risk Management - CF Hedging Effect on the Income Statements (Details) - Designated as Hedging Instrument - Cash Flow Hedging - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) recognized in OCI on derivative $ 238 $ (37) $ 202
Gain/(loss) reclassified from Accumulated OCI into income 110 (52) 47
Loss to be reclassified within twelve months 63    
Energy commodity derivative contracts      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) recognized in OCI on derivative 171 (26) 182
Energy commodity derivative contracts | Revenues—Commodity sales      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) reclassified from Accumulated OCI into income 47 7 103
Energy commodity derivative contracts | Costs of sales      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) reclassified from Accumulated OCI into income (6) (29) (73)
Interest rate contracts      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) recognized in OCI on derivative 0 13 (10)
Interest rate contracts | Interest, net      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) reclassified from Accumulated OCI into income 0 4 0
Foreign currency contracts      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) recognized in OCI on derivative 67 (24) 30
Foreign currency contracts | Other, net      
Derivative Instruments, Gain (Loss) [Line Items]      
Gain/(loss) reclassified from Accumulated OCI into income $ 69 $ (34) $ 17
v3.25.4
Risk Management - Not Designated as Hedges Effect on Income Statements (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives $ 14 $ (66) $ 178
Natural gas, crude and NGL derivative contract settlements      
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives (3) 8 58
Revenues—Commodity sales | Energy commodity derivative contracts      
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives 79 20 75
Costs of sales | Energy commodity derivative contracts      
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives (61) (89) 100
Earnings from equity investments | Energy commodity derivative contracts      
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives 1 0 2
Interest, net | Interest rate contracts      
Derivative [Line Items]      
Gain/(loss) recognized in income on derivatives $ (5) $ 3 $ 1
v3.25.4
Risk Management - Credit Risks (Details) - Energy commodity derivative contracts - USD ($)
$ in Millions
Dec. 31, 2025
Dec. 31, 2024
Credit Derivatives [Line Items]    
Letters of credit outstanding $ 0 $ 0
Cash margin, asset   52
Variation margin, asset 0 0
Restricted Cash | Contract and Over the Counter    
Credit Derivatives [Line Items]    
Cash margin, asset 24 $ 104
Initial margin requirement 26  
Variation margin, asset $ 2  
v3.25.4
Revenue Recognition - Schedule of Disaggregation of Revenue (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers $ 15,202 $ 13,483 $ 13,647
Leasing services(b) 1,464 1,400 1,368
Derivatives adjustments on commodity sales 126 27 178
Other 145 190 141
Total other revenues 1,735 1,617 1,687
Total revenues 16,937 15,100 15,334
Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 5,342 4,957 4,537
Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 2,719 2,597 2,502
Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 8,061 7,554 7,039
Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 3,949 2,340 2,666
Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 3,063 3,486 3,884
Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 129 103 58
Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 7,141 5,929 6,608
Total revenues 7,255 5,957 6,786
Natural Gas Pipelines      
Disaggregation of Revenue [Line Items]      
Total revenues 10,990 8,930 9,152
Products Pipelines      
Disaggregation of Revenue [Line Items]      
Total revenues 2,686 2,955 3,066
Terminals      
Disaggregation of Revenue [Line Items]      
Total revenues 2,094 2,013 1,911
CO2      
Disaggregation of Revenue [Line Items]      
Total revenues 1,167 1,202 1,205
Operating Segments | Natural Gas Pipelines      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 10,354 8,225 8,312
Leasing services(b) 455 459 475
Derivatives adjustments on commodity sales 96 113 285
Other 104 145 96
Total other revenues 655 717 856
Total revenues 11,009 8,942 9,168
Operating Segments | Natural Gas Pipelines | Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 4,254 3,893 3,543
Operating Segments | Natural Gas Pipelines | Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,161 1,044 1,008
Operating Segments | Natural Gas Pipelines | Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 5,415 4,937 4,551
Operating Segments | Natural Gas Pipelines | Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 3,909 2,303 2,631
Operating Segments | Natural Gas Pipelines | Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,001 965 1,110
Operating Segments | Natural Gas Pipelines | Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 29 20 20
Operating Segments | Natural Gas Pipelines | Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 4,939 3,288 3,761
Operating Segments | Products Pipelines      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 2,468 2,723 2,842
Leasing services(b) 192 209 200
Derivatives adjustments on commodity sales 0 (1) 0
Other 26 24 24
Total other revenues 218 232 224
Total revenues 2,686 2,955 3,066
Operating Segments | Products Pipelines | Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 221 220 171
Operating Segments | Products Pipelines | Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,090 1,059 1,036
Operating Segments | Products Pipelines | Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,311 1,279 1,207
Operating Segments | Products Pipelines | Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 0 0 0
Operating Segments | Products Pipelines | Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,157 1,444 1,635
Operating Segments | Products Pipelines | Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 0 0 0
Operating Segments | Products Pipelines | Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,157 1,444 1,635
Operating Segments | Terminals      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,357 1,356 1,279
Leasing services(b) 747 666 638
Derivatives adjustments on commodity sales 0 0 0
Other 0 0 0
Total other revenues 747 666 638
Total revenues 2,104 2,022 1,917
Operating Segments | Terminals | Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 870 846 819
Operating Segments | Terminals | Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 431 460 427
Operating Segments | Terminals | Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,301 1,306 1,246
Operating Segments | Terminals | Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 0 0 0
Operating Segments | Terminals | Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 56 50 33
Operating Segments | Terminals | Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 0 0 0
Operating Segments | Terminals | Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 56 50 33
Operating Segments | CO2      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,055 1,202 1,240
Leasing services(b) 70 66 55
Derivatives adjustments on commodity sales 30 (85) (107)
Other 15 21 21
Total other revenues 115 2 (31)
Total revenues 1,170 1,204 1,209
Operating Segments | CO2 | Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1 2 1
Operating Segments | CO2 | Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 45 41 40
Operating Segments | CO2 | Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 46 43 41
Operating Segments | CO2 | Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 49 43 43
Operating Segments | CO2 | Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 857 1,031 1,114
Operating Segments | CO2 | Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 103 85 42
Operating Segments | CO2 | Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers 1,009 1,159 1,199
Corporate and Eliminations      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (32) (23) (26)
Leasing services(b) 0 0 0
Derivatives adjustments on commodity sales 0 0 0
Other 0 0 0
Total other revenues 0 0 0
Total revenues (32) (23) (26)
Corporate and Eliminations | Firm services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (4) (4) 3
Corporate and Eliminations | Fee-based services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (8) (7) (9)
Corporate and Eliminations | Total services      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (12) (11) (6)
Corporate and Eliminations | Natural gas sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (9) (6) (8)
Corporate and Eliminations | Product sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (8) (4) (8)
Corporate and Eliminations | Other sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers (3) (2) (4)
Corporate and Eliminations | Total commodity sales      
Disaggregation of Revenue [Line Items]      
Revenues from contracts with customers $ (20) $ (12) $ (20)
v3.25.4
Revenue Recognition - Contract Balances (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Contract Assets    
Contract assets balances $ 30 $ 15
Transfer to accounts receivable 8  
Contract Liabilities    
Contract liability balances 459 377
Transfer to revenues 78  
Long-Term Terminaling Customer    
Contract Liabilities    
Lease services liability $ 531 $ 587
v3.25.4
Revenue Recognition - Revenue Allocated to Remaining Performance Obligations (Details)
$ in Billions
Dec. 31, 2025
USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2026-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Estimated Revenue $ 5
Performance obligation, period of recognition 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2027-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Estimated Revenue $ 5
Performance obligation, period of recognition 1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Year [Axis]: 2028-01-01  
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]  
Estimated Revenue $ 26
Performance obligation, period of recognition
v3.25.4
Reportable Segments (Details)
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Dec. 31, 2023
USD ($)
Segment Reporting Information [Line Items]      
Revenues $ 16,937 $ 15,100 $ 15,334
Costs of sales (5,529) (4,337) (4,938)
Taxes, other than income taxes (445) (433) (421)
Earnings from equity investments 896 840 772
Net income 3,160 2,720 2,486
Depreciation, depletion, and amortization 2,453 2,354 2,250
General and administrative and corporate charges (746) (736) (759)
Interest, net (1,801) (1,844) (1,797)
Income Tax Expense (832) (687) (715)
Capital Expenditures 3,026 2,629 2,317
Investments 7,532 7,845  
Other intangibles, net 1,730 1,760  
Assets 72,748 71,407  
Non-cash mark-to-market derivative hedge contract $ 23 (72) 126
Number of Reportable Segments 4    
Operating Segments      
Segment Reporting Information [Line Items]      
Net income $ 8,992 8,341 8,007
Other      
Segment Reporting Information [Line Items]      
Revenues (32) (23) (26)
Depreciation, depletion, and amortization 26 22 24
Capital Expenditures 38 34 36
Investments 0 0  
Other intangibles, net 0 0  
Assets 633 697  
Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Revenues (32) (23) (26)
Natural Gas Pipelines      
Segment Reporting Information [Line Items]      
Revenues 10,990 8,930 9,152
Natural Gas Pipelines | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 11,009 8,942 9,168
Costs of sales (4,299) (2,837) (3,258)
Labor (331) (322) (300)
Fuel and power (87) (74) (79)
Field - non-labor(a) (901) (854) (801)
Taxes, other than income taxes (287) (269) (262)
Earnings from equity investments 817 748 746
Other segment items(b) 159 59 38
Net income 6,080 5,393 5,252
Depreciation, depletion, and amortization 1,173 1,105 1,041
Capital Expenditures 2,092 1,654 1,299
Investments 6,962 7,252  
Other intangibles, net 900 687  
Assets 52,546 50,402  
Non-cash mark-to-market derivative hedge contract 37 (75) 122
Natural Gas Pipelines | Operating Segments | Previously Reported      
Segment Reporting Information [Line Items]      
Net income   5,427 5,282
Natural Gas Pipelines | Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Revenues (19) (12) (16)
Products Pipelines      
Segment Reporting Information [Line Items]      
Revenues 2,686 2,955 3,066
Products Pipelines | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 2,686 2,955 3,066
Costs of sales (1,112) (1,394) (1,588)
Labor (132) (128) (121)
Fuel and power (90) (92) (88)
Field - non-labor(a) (209) (193) (185)
Taxes, other than income taxes (45) (43) (42)
Earnings from equity investments 58 57 (6)
Other segment items(b) 1 2 (3)
Net income 1,157 1,164 1,033
Depreciation, depletion, and amortization 358 365 367
Capital Expenditures 242 210 221
Investments 381 387  
Other intangibles, net 403 597  
Assets 8,044 8,639  
Non-cash mark-to-market derivative hedge contract (1)   1
Products Pipelines | Operating Segments | Previously Reported      
Segment Reporting Information [Line Items]      
Net income   1,173 1,062
Products Pipelines | Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Revenues 0 0 0
Terminals      
Segment Reporting Information [Line Items]      
Revenues 2,094 2,013 1,911
Terminals | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 2,104 2,022 1,917
Costs of sales (50) (42) (33)
Labor (282) (273) (254)
Fuel and power (20) (20) (19)
Field - non-labor(a) (558) (558) (535)
Taxes, other than income taxes (55) (53) (55)
Earnings from equity investments (2) 8 9
Other segment items(b) 6 15 10
Net income 1,143 1,099 1,040
Depreciation, depletion, and amortization 518 508 493
Capital Expenditures 326 385 406
Investments 122 132  
Other intangibles, net 13 18  
Assets 7,917 8,086  
Terminals | Operating Segments | Previously Reported      
Segment Reporting Information [Line Items]      
Net income   1,099 1,040
Terminals | Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Revenues (10) (9) (6)
CO2      
Segment Reporting Information [Line Items]      
Revenues 1,167 1,202 1,205
CO2 | Operating Segments      
Segment Reporting Information [Line Items]      
Revenues 1,170 1,204 1,209
Costs of sales (94) (82) (77)
Labor (53) (50) (49)
Fuel and power (141) (153) (137)
Field - non-labor(a) (242) (241) (232)
Taxes, other than income taxes (51) (60) (55)
Earnings from equity investments 23 27 23
Other segment items(b) 0 40 0
Net income 612 685 682
Depreciation, depletion, and amortization 378 354 325
Capital Expenditures 328 346 355
Investments 67 74  
Other intangibles, net 414 458  
Assets 3,608 3,583  
Non-cash mark-to-market derivative hedge contract 4 (2) (4)
CO2 | Operating Segments | Previously Reported      
Segment Reporting Information [Line Items]      
Net income   692 689
CO2 | Intersegment Eliminations      
Segment Reporting Information [Line Items]      
Revenues $ (3) $ (2) $ (4)
Revenue Benchmark | Customer Concentration Risk      
Segment Reporting Information [Line Items]      
Concentration Risk, Percentage Meet Certain Threshold 10.00% 10.00% 10.00%
v3.25.4
Reportable Segments Geographical information (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Segment Reporting Information [Line Items]      
Revenues $ 16,937 $ 15,100 $ 15,334
Long-term assets, excluding goodwill and other intangibles 48,180 47,042 46,400
U.S.      
Segment Reporting Information [Line Items]      
Revenues 16,926 15,057 15,255
Long-term assets, excluding goodwill and other intangibles 48,115 46,972 46,328
Mexico      
Segment Reporting Information [Line Items]      
Revenues 11 43 79
Long-term assets, excluding goodwill and other intangibles $ 65 $ 70 $ 72
v3.25.4
Leases - Lessee (Details) - USD ($)
$ in Millions
 12 Months Ended
Dec. 31, 2025
Dec. 31, 2024
Dec. 31, 2023
Lease, Cost [Abstract]      
Operating leases $ 74 $ 80 $ 71
Short-term and variable leases 152 131 127
Total lease cost 226 211 198
Lessee, Operating Lease, Description [Abstract]      
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 years 21 days 8 years 1 month 24 days 8 years 8 months 19 days
Weighted average discount rate 4.85% 4.84% 4.59%
Assets and Liabilities, Lessee [Abstract]      
Operating Lease, Right-of-Use Asset, Statement of Financial Position [Extensible List] Deferred charges and other assets Deferred charges and other assets  
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] Other current liabilities Other current liabilities  
Operating Lease, Liability, Noncurrent, Statement of Financial Position [Extensible List] Other long-term liabilities and deferred credits Other long-term liabilities and deferred credits  
ROU assets $ 216 $ 253  
Short-term lease liability 49 60  
Long-term lease liability 167 $ 193  
Lessee, Operating Lease, Liability, Payment, Due [Abstract]      
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    
v3.25.4
Litigation and Environmental - Other Commercial Matters (Details) - Pending Litigation
$ in Millions
 12 Months Ended
Dec. 31, 2025
USD ($)
claims
Freeport LNG Marketing, LLC Case  
Loss Contingencies [Line Items]  
Loss Contingency, Damages Sought, Value $ 104
Pension Plan Litigation  
Loss Contingencies [Line Items]  
Loss Contingency, Damages Sought, Value $ 100
Loss Contingency, Pending Claims, Number | claims 6
v3.25.4
Litigation and Environmental - Portland (Details) - Environmental Protection Agency - Portland Harbor Superfund Site, Willamette River, Portland, Oregon
$ in Billions
 12 Months Ended
Dec. 31, 2025
USD ($)
Terminals
Parties
KMBT  
Site Contingency [Line Items]  
Number of Liquid Terminals 2
KMLT  
Site Contingency [Line Items]  
Site Contingency, Loss Exposure Not Accrued, Best Estimate | $ $ 2.8
Site Contingency, Disbursement Period, Estimate, Unrecognized 10 years
Loss Contingency, Number of Defendants | Parties 90
Number of Liquid Terminals 2
v3.25.4
Litigation and Environmental - Lower Passaic River (Details) - Environmental Protection Agency
$ in Millions
Jan. 17, 2024
Parties
Dec. 16, 2022
USD ($)
Parties
Oct. 04, 2021
USD ($)
Mar. 04, 2016
USD ($)
Dec. 31, 2025
Lower Passaic River Study Area | EPA Proposed Consent Decree          
Site Contingency [Line Items]          
Loss Contingency, Number of Defendants | Parties   85      
Litigation Settlement, Amount Awarded to Other Party | $   $ 150      
Lower Passaic River Study Area | EPA Complaint Filed          
Site Contingency [Line Items]          
Loss Contingency, Number of Defendants | Parties 82 85      
Lower Passaic River Study Area | Pending Litigation | EPA preferred alternative estimate          
Site Contingency [Line Items]          
Site Contingency, Loss Exposure Not Accrued, Best Estimate | $       $ 1,700  
Lower Passaic River Study Area | Pending Litigation | Clean Up Implementation          
Site Contingency [Line Items]          
Site Contingency, Disbursement Period, Estimate, Unrecognized         6 years
Lower Passaic River Study Area | Litigation Dismissed | EPA Complaint Filed          
Site Contingency [Line Items]          
Loss Contingency, Number of Defendants | Parties 3        
Upper Passaic River Study Area, Upper Portion | Pending Litigation          
Site Contingency [Line Items]          
Site Contingency, Loss Exposure Not Accrued, Best Estimate | $     $ 440    
v3.25.4
Litigation and Environmental - Louisiana Governmental (Details) - Coastal Zone
Mar. 29, 2019
Parties
Nov. 08, 2013
Parties
Dec. 31, 2025
cases
Judicial District of Louisiana      
Loss Contingencies [Line Items]      
Loss Contingency, Pending Claims, Number     40
Judicial District of Louisiana | TGP      
Loss Contingencies [Line Items]      
Loss Contingency, Pending Claims, Number     1
Judicial District of Louisiana | SNG      
Loss Contingencies [Line Items]      
Loss Contingency, Pending Claims, Number     1
Parish of Plaquemines, Louisiana | TGP      
Loss Contingencies [Line Items]      
Loss Contingency, Number of Defendants | Parties   17  
Parish of Orleans, Louisiana | SNG      
Loss Contingencies [Line Items]      
Loss Contingency, Number of Defendants | Parties 10    
v3.25.4
Litigation and Environmental - Environmental Matters - General (Details)
$ in Millions
Jan. 27, 2026
Plans
Dec. 31, 2025
USD ($)
Dec. 31, 2024
USD ($)
Loss Contingency, Information about Litigation Matters [Abstract]      
Accrual for Environmental Loss Contingencies   $ 176 $ 188
Environmental Loss Contingency, Statement Of Financial Position [Extensible Enumeration], Not Disclosed Flag   true true
Recorded Third-Party Environmental Recoveries Receivable   $ 10 $ 10
Environmental Protection Agency | Ozone emissions | Challenge to Federal Good Neighbor Plan | Subsequent Event      
Loss Contingencies [Line Items]      
Number of State Implementation Plans | Plans 8