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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

_____________

Form 10-K


☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, ~~2024~~2025


☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from _____to_____

Commission file number: 001-35081

Kinder Morgan, Inc.

(Exact name of registrant as specified in its charter)


Delaware						80-0682103
(State or other jurisdiction of incorporation or organization)						(I.R.S. Employer Identification No.)

1001 Louisiana Street, Suite 1000, Houston, Texas 77002

(Address of principal executive offices) (zip code)

Registrant’s telephone number, including area code: 713-369-9000

____________

Securities registered pursuant to Section 12(b) of the Act:


Title of each class	Trading Symbol(s)	Name of each exchange on which registered
Class P Common Stock	KMI	New York Stock Exchange
2.250% Senior Notes due 2027	KMI 27 A	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “non-accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C.7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Securities Exchange Act of 1934). Yes ☐ No ☑

Aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant, based on closing prices in the daily composite list for transactions on the New York Stock Exchange on June 2830, ~~2024~~2025 was approximately $3857,~~478~~054,~~431~~291,~~485~~328. As of February 12, ~~2025~~2026, the registrant had 2,~~221~~224,~~963~~806,~~025~~397 shares of Class P common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Registrant’s definitive proxy statement for the ~~2025~~2026 Annual Meeting of Stockholders, which shall be filed no later than April 30, ~~2025~~2026, are incorporated into PART III, as specifically set forth in PART III.

KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
		PageNumber
	Glossary	1
	Information Regarding Forward-Looking Statements	2
	PART I
Items 1. and 2.	Business and Properties	4
	General Development of Business	4
	Recent Developments	4
	Narrative Description of Business	6
	Business Strategy	6
	Business Segments	6
	Natural Gas Pipelines	7
	Products Pipelines	10
	Terminals	12
	CO2	14
	Major Customers	16
	Industry Regulation	17
	Regulation	17
	Environmental Matters and Safety Regulation	19
	Cybersecurity	21
	Human Capital	22
	Properties and Rights-of-Way	23
	Available Information	23
Item 1A.	Risk Factors	23
Item 1B.	Unresolved Staff Comments	3637
Item 1C.	Cybersecurity	3637
Item 3.	Legal Proceedings	38
Item 4.	Mine Safety Disclosures	3839
	PART II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	3940
Item 6.	[Reserved]	3940
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	3940
	General	3940
	Critical Accounting Estimates	4041
	Results of Operations	4142
	Overview	4142
	Consolidated Earnings Results	4546
	Non-GAAP Financial Measures	4748
	Segment Earnings Results	50
	Liquidity and Capital Resources	56
	General	56
	Short-term Liquidity	57
	Long-term Financing	58
	Capital Expenditures	58

KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
TABLE OF CONTENTS
		PageNumber
	Long-term Financing	58
	Off Balance Sheet Arrangements	60
	Capital Expenditures	58
	Contractual Obligations and Commercial Commitments	60
	Off Balance Sheet Arrangements	61
	Cash Flows	61
	Contractual Obligations and Commercial Commitments	61
	Dividends and Stock Buy-back Program	62
	Cash Flows	62
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	63
	Dividends and Stock Buy-back Program	63
	Recent Accounting Pronouncements	64
	Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	64
	Recent Accounting Pronouncements	65
	Energy Commodity Market Risk	64
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	65
	Interest Rate Risk	65
	Energy Commodity Market Risk	65
	Foreign Currency Risk	65
	Interest Rate Risk	66
Item 8.	Financial Statements and Supplementary Data	66
	Foreign Currency Risk	67
	Index to Financial Statements	66
Item 8.	Financial Statements and Supplementary Data	68
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	119
	Index to Financial Statements	68
Item 9A.	Controls and Procedures	120
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	126
Item 9B.	Other Information	120
Item 9A.	Controls and Procedures	127
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	120
Item 9B.	Other Information	127
Item 9C.	Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	127
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	~~128~~121
Item 11.	Executive Compensation	~~128~~121
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	~~128~~121
Item 13.	Certain Relationships and Related Transactions, and Director Independence	~~128~~121
Item 14.	Principal Accounting Fees and Services	~~128~~121
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	~~129~~122
Item 16.	Form 10-K Summary	~~132~~125
Signatures		~~133~~126

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

CALNEV

Calnev Pipe Line LLC

~~KMP~~KMLP

Kinder Morgan ~~Energy~~Louisiana ~~Partners,~~Pipeline ~~L.P. and its majority-owned and/or controlled subsidiaries~~LLC

CIG

Colorado Interstate Gas Company, L.L.C.

KMLT

Kinder Morgan Liquid Terminals, LLC

CPGPL

Cheyenne Plains Gas Pipeline Company, L.L.C.

~~KMTP~~KMP

Kinder Morgan ~~Texas~~Energy ~~Pipeline~~Partners, ~~LLC~~L.P. and its majority-owned and/or controlled subsidiaries

EagleHawk

BPX (Eagle Ford) Gathering LLC, formerly known as EagleHawk Field Services ~~LLC~~

~~MEP~~

~~Midcontinent Express Pipeline LLC~~

MEP

Midcontinent Express Pipeline LLC

Elba Express

Elba Express Company, L.L.C.

NGPL

Natural Gas Pipeline Company of America LLC and certain affiliates

ELC

Elba Liquefaction Company, L.L.C.

EPNG

El Paso Natural Gas Company, L.L.C.

PHP

Permian Highway Pipeline LLC

FEP

Fayetteville Express Pipeline LLC

~~Ruby~~SFPP

~~Ruby Pipeline Holding Company~~SFPP, L.LP.C.

GCX

Gulf Coast Express Pipeline LLC

~~SFPP~~SLNG

~~SFPP~~Southern LNG Company, L.PL.C.

Hiland

Hiland Partners, LP

~~SLNG~~SNG

Southern ~~LNG~~Natural Gas Company, L.L.C.

KinderHawk

KinderHawk Field Services LLC

~~SNG~~Stagecoach

~~Southern~~Stagecoach ~~Natural~~ Gas ~~Company,~~Services ~~L.L.C.~~LLC

KMBT

Kinder Morgan Bulk Terminals, Inc.

~~Stagecoach~~TGP

~~Stagecoach~~Tennessee Gas ~~Services~~Pipeline ~~LLC~~Company, L.L.C.

KMI

Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries

~~TGP~~WIC

~~Tennessee~~Wyoming ~~Gas~~Interstate ~~Pipeline~~ Company, L.L.C.

WIC

Wyoming Interstate Company, L.L.C.

WYCO

WYCO Development L.L.C.

KMLP

Kinder Morgan Louisiana Pipeline LLC

WYCO

WYCO Development L.L.C.

KMLT

Kinder Morgan Liquid Terminals, LLC

Unless the context otherwise requires, references to “we,” “us,” “our,” or “the Company” are intended to mean Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries.

Common Industry and Other Terms

per day

MBbl

thousand barrels

AFUDC

allowance for funds used during construction

MMBbl

million barrels

Bbl

barrels

MMtons

million tons

BBtu

billion British Thermal Units

NGL

natural gas liquids

Bcf

billion cubic feet

NYMEX

New York Mercantile Exchange

CERCLA

Comprehensive Environmental Response, Compensation and Liability Act

NYSE

New York Stock Exchange

OTC

over-the-counter

CO2

carbon dioxide or our CO2 business segment

PHMSA

United States Department of Transportation Pipeline and Hazardous Materials Safety Administration

CPUC

California Public Utilities Commission

DD&A

depreciation, depletion, and amortization

EPA

United States Environmental Protection Agency

RIN

renewable identification number

FASB

Financial Accounting Standards Board

RNG

renewable natural gas

FERC

Federal Energy Regulatory Commission

ROU

right-of-use

GAAP

United States Generally Accepted Accounting Principles

SEC

United States Securities and Exchange Commission

GTE

gas-to-electric

SOFR

Secured Overnight Financing Rate

Information Technology

U.S.

United States of America

LLC

limited liability company

WTI

West Texas Intermediate

LNG

liquefied natural gas

Information Regarding Forward-Looking Statements

This report includes forward-looking statements. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “intend,” “plan,” “projection,” “forecast,” “strategy,” “outlook,” “continue,” “estimate,” “expect,” “may,” “will,” “shall,” or the negative of those terms or other variations of them or comparable terminology. In particular, expressed or implied statements concerning future actions, conditions or events, future operating results, or the ability to generate revenues, income or cash flow, service debt, or pay dividends, are forward-looking statements. Forward-looking statements in this report include, among others, express or implied statements pertaining to: long term demand for our assets and services, our business strategy, expected financial results, dividends, sustaining and discretionary/expansion capital expenditures, our cash requirements and our financing and capital allocation strategy, anticipated impacts of litigation and legal or regulatory developments, and our capital projects, including expected completion timing and benefits of those projects.

Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results may differ materially from those expressed in our forward-looking statements. Many of the factors that will determine these results are beyond our ability to control or accurately predict. Specific factors that could cause actual results to differ from those in our forward-looking statements include:

•changes in supply of and demand for natural gas, NGL, refined petroleum products, oil, renewable fuels, CO2, electricity, petroleum coke, steel and other bulk materials and chemicals, and certain agricultural products;

•competition from other pipelines, terminals, or other forms of transportation, or from emerging technologies ~~such as CO2 capture and sequestration~~;

•changes in our tariff rates required by the FERC, the CPUC, or another regulatory agency;

•the timing and success of our commercial and business development efforts, including our ability to renew long-term customer contracts at economically attractive rates;

•our ability to safely operate and maintain our existing assets and to access or construct new assets or expand our existing assets, including pipelines, terminals, and gas processing, gas storage, and NGL fractionation capacity;

•cost overruns, delays, stoppages, or other issues adversely impacting expansion projects;

•regulatory, environmental, political, grass roots opposition, legal, operational, and geological uncertainties that could affect our ability to complete our expansion projects on time and on budget or at all;

•changes in commodity prices, including prices for crude oil, natural gas, and NGL, and prices for environmental attributes such as RINs, and our ability to use hedging arrangements to reduce our direct exposure to such price changes;

•economic activity, weather, alternative energy sources, conservation, and technological advances that may affect price trends and demand;

•our ability to achieve cost savings and revenue growth;

•our ability to attract and retain key management and operations personnel;

•difficulties or delays experienced by railroads, barges, trucks, ships or pipelines in delivering products to or from our terminals or pipelines;

•shut-downs or cutbacks at major refineries, chemical or petrochemical plants, natural gas processing plants, LNG export facilities, ports, utilities, military bases, or other businesses that use our services or provide services or products to us;

•changes in crude oil and natural gas production (and the NGL content of natural gas production) from exploration and production areas that we serve, such as the Permian Basin area of West Texas, the shale plays in Louisiana, North Dakota, Ohio, Oklahoma, Pennsylvania, ~~and~~ Texas, and the U.S. Rocky Mountains;

•changes in laws or regulations, third-party relations and approvals, and decisions of courts, regulators, and governmental bodies that may increase our compliance costs, restrict our ability to provide or reduce demand for our services, or otherwise adversely affect our business;

•~~changes~~interruptions inof ~~laws~~operations orat ~~regulations,~~our ~~third-party~~facilities ~~relations~~due ~~and~~to ~~approvals~~natural disasters, ~~and~~damage ~~decisions~~by ofthird ~~courts~~parties, ~~regulators~~power ~~and~~shortages, ~~governmental~~strikes, ~~bodies that may increase our compliance costs~~riots, ~~restrict~~terrorism ~~our~~(including ~~ability to provide or reduce demand for our services~~cyber-attacks), or ~~otherwise~~other ~~adversely affect our business~~causes;

•~~interruptions~~extraordinary ofevents ~~operations~~such atas ~~our~~pandemics, ~~facilities~~acts ~~due~~of towar, ~~natural~~or ~~disasters~~terrorist acts, ~~damage~~including bycybersecurity ~~third parties~~breaches, ~~power~~and ~~shortages,~~the ~~strikes,~~collateral ~~riots,~~impacts ~~terrorism~~of (such events, including ~~cyber-attacks)~~disruptions orof ~~other~~supply ~~causes~~chains and economic activity;

•~~extraordinary~~the ~~events~~extent ~~such~~of asour ~~pandemics,~~success ~~acts~~in ofdeveloping ~~war~~and orproducing ~~terrorist~~CO2 ~~acts,~~and ~~including~~oil ~~cybersecurity~~and ~~breaches~~gas reserves, ~~and~~including the ~~collateral~~risks ~~impacts~~inherent ofin ~~such~~development ~~events~~drilling, ~~including~~well ~~disruptions~~completion, ofand ~~supply~~other ~~chains~~development and ~~economic~~production ~~activity~~activities;

•the extent of our success in developing and producing CO2 and oil and gas reserves, including the risks inherent in development drilling, well completion and other development and production activities;

•engineering and mechanical or technological difficulties that we may experience with operational equipment;

•the uncertainty inherent in estimating future oil, natural gas, and CO2 production or reserves;

•our ability to acquire new businesses and assets and integrate those operations into our existing operations, and make cost-saving changes in operations, particularly if we undertake multiple acquisitions in a relatively short period of time;

•the ability of our customers and other counterparties to perform under their contracts with us, including as a result of our customers’ financial distress or bankruptcy;

•our ability to obtain insurance coverage without significant levels of self-retention risk;

•natural disasters, sabotage, terrorism (including cyber-attacks), or other similar acts or accidents causing damage to our properties greater than our insurance coverage limits;

•compromise of our IT systems, operational systems, or sensitive data as a result of errors, malfunctions, hacking events or coordinated cyber-attacks;

•changes in technologies, possibly introducing new cybersecurity risks and other new risks inherent in the use, either by us or our counterparties, of new technologies in the developmental stage including, without limitation, generative artificial intelligence;

•changes in accounting pronouncements that impact the measurement of our results of operations, the timing of when such measurements are to be made and recorded, and the disclosures surrounding these activities;

•changes in tax laws and tax rates;

•national, international, regional, and local economic, competitive, and regulatory conditions and developments, or changes in trade policies, including the effects of any enactment of import or export duties, tariffs, or similar measures;

•our ability to access external sources of financing in sufficient amounts and on acceptable terms to the extent needed to fund acquisitions of operating businesses and assets and expansions of our facilities;

•our indebtedness, which could make us vulnerable to general adverse economic and industry conditions, limit our ability to borrow additional funds, place us at a competitive disadvantage compared to our competitors that have less debt, or have other adverse consequences;

•~~possible~~ changes in our and our subsidiaries’ credit outlook or credit ratings;

•conditions in the capital and credit markets, inflation and higher interest rates;

•political and economic instability of the oil and natural gas producing nations of the world; and

•national, international, regional and local economic, competitive and regulatory conditions and developments, including the effects of any enactment of import or export duties, tariffs or similar measures; and

•unfavorable results of litigation and the outcome of contingencies referred to in Note 17 “Litigation and Environmental” to our consolidated financial statements.

The foregoing list should not be construed to be exhaustive. We believe the forward-looking statements in this report are reasonable. However, there is no assurance that any of the actions, events, or results expressed in forward-looking statements will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any of our forward-looking statements.

will occur, or if any of them do, of their timing or what impact they will have on our results of operations or financial condition. Because of these uncertainties, you should not put undue reliance on any of our forward-looking statements.

Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including in Item 1A. “Risk Factors,” Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk—Energy Commodity Market Risk.” When considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. We disclaim any obligation, other than as required by applicable law, to publicly update or revise any of our forward-looking statements to reflect future events or developments.

PART I

Items 1 and 2. Business and Properties.

We are one of the largest energy infrastructure companies in North America. As of December 31, ~~2024~~2025, we owned an interest in or operated approximately 7978,000 miles of pipelines, ~~139~~136 terminals, approximately ~~700~~706 Bcf of working natural gas storage capacity, and RNG generation capacity of approximately 6.19 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels, and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, petroleum coke, metals, and ethanol and other renewable fuels and feedstocks.

General Development of Business

Recent Developments

The following is a listing of significant developments and updates related to our major ~~acquisitions~~acquisition, divestiture, projects, and financing transactions. “Capital Scope” is estimated for our share of the described project and includes portions not yet completed. All expected in-service dates for projects listed below assume timely receipt and continued effectiveness of all necessary permits and approvals.

Asset or project

Description

Activity

Approx. Capital Scope (KMI Share)

Acquisition

Acquisition or divestiture

Gas gathering and processing system announced acquisition

Acquisition of a natural gas gathering and processing system in North Dakota from Outrigger Energy II which 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.

Expected to close in the first quarter of 2025, pending clearance under Hart-Scott-Rodino.

$640 million

Gas gathering and processing system acquisition

Completed February 2025.

$648 million

EagleHawk divestiture

Sold our 25% non-operated equity interest in EagleHawk.

Completed December 2025.

$382 million

Projects placed in service

KMTP system expansion

Expansion project included a new 30-mile, 30-inch pipeline, to deliver up to 0.4Bcf/d of Eagle Ford natural gas supply to markets along the Texas Gulf Coast and Mexico. Expansion provides transportation services, including treating, for Kimmeridge Texas Gas and other third parties. Supported by a long-term contract.

Placed in service October 2024

$158 million

TGP and SNG Evangeline Pass projects

Two-phase 2 Bcf/d project serving Venture Global’s Plaquemines LNG facility (Plaquemines). With the first phase, TGP is providing approximately 0.9 Bcf/d natural gas transportation capacity to Plaquemines. With the second phase, TGP and SNG is jointly providing volumes up to the remaining 1.1 Bcf/d to Plaquemines. Supported by a long-term contract.

First phase placed in service in July 2024. Second phase placed in service in July 2025.

$661 million

Central Texas pipeline

Project included installation of 22 miles of 30-inch pipeline from PHP to Sand Hill Lateral, 1.75 miles of 20-inch pipeline from Sand Hill Lateral to Texas Gas Services and three meter stations and one regulator station.

Placed in service November 2024.

$110 million

Altamont Green River pipeline project

Constructed 43 miles of 20-inch pipeline and associated compression providing approximately 0.15 Bcf/d of capacity from the Uinta basin to the Western Chipeta processing plant.

Placed in service September 2025.

$263 million

Other Construction Projects

Tejas South to North expansion

South Texas to Houston Market expansion project. First phase added compression on Tejas’ mainline and second phase constructed 14 miles of pipeline looping. Combined these projects provide approximately 0.781 Bcf/d of capacity to key markets. Supported by long-term contracts.

First phase placed in service in February 2025. Second phase placed in service in June 2025.

$145 million

Natural Gas Pipelines

South System Expansion 4 (SSE4)

Expansion project designed to increase SNG’s South Line capacity by approximately 1.2 Bcf/d. Expansion will be completed in two phases and is almost entirely comprised of brownfield looping and horsepower compression additions on the SNG and Elba Express pipeline systems. Supported by long-term contracts.

First phase expected in-service date is fourth quarter of 2028. Second phase expected in-service date is fourth quarter of 2029.

$1,659 million

Asset or project

Description

Activity

Approx. Capital Scope (KMI Share)

Trident Intrastate pipeline project

Project is designed to construct 216-mile pipeline which will provide approximately 1.5 Bcf/d of capacity from Katy, Texas to the LNG and industrial corridor near Port Arthur, Texas. Supported by long-term contracts.

Expected in-service date is first quarter of 2027.

$1,650 million

Other Construction Projects

Mississippi Crossing project

Project is designed to transport up to 2.1 Bcf/d of natural gas through the construction of approximately 206 miles of 42-inch and 36-inch pipeline and three new compressor stations. Project will originate near Greenville, Mississippi, and conclude near Butler, Alabama, with connections to the existing TGP system and third-party pipelines. Supported by long-term contracts.

Expected in-service date is November 2028.

$1,637 million

Natural Gas Pipelines

TGP and SNG Evangeline Pass projects

Two-phase 2 Bcf/d project to serve Venture Global’s Plaquemines LNG facility (Plaquemines). With the first phase, TGP is providing approximately 0.9 Bcf/d natural gas transportation capacity to Plaquemines. Second phase, TGP and SNG will jointly provide volumes up to the remaining 1.1 Bcf/d to Plaquemines. Supported by a long-term contract.

First phase placed in service in July 2024. Second phase expected in-service date is July 2025.

$672 million

South System Expansion 4 (SSE4)

Expansion project designed to increase SNG’s South Line capacity by approximately 1.3 Bcf/d. Expansion will be completed in two phases and is almost entirely comprised of brownfield looping and horsepower compression additions on the SNG and Elba Express pipeline systems. Supported by long-term contracts.

First phase expected in-service date is fourth quarter of 2028. Second phase expected in-service date is fourth quarter of 2029.

$1,830 million

Altamont Green River pipeline project

Construct 43 miles of 20-inch pipeline and associated compression providing approximately 0.15 Bcf/d of capacity from the Uinta basin to the Western Chipeta processing plant.

Expected in-service date is third quarter of 2025.

$263 million

Trident Intrastate pipeline project

Project is designed to construct 216-mile pipeline which will provide approximately 2.0 Bcf/d of capacity from Katy, Texas to the LNG and industrial corridor near Port Arthur, Texas. Supported by long-term contracts.

First phase expected in-service date is first quarter of 2027. Second phase expected in-service date is fourth quarter 2028.

$1,799 million

TVA Cumberland project

Project includes a new 32-mile pipeline to transport approximately 0.245 Bcf/d of natural gas from the existing TGP system to Tennessee Valley Authority’s (TVA) proposed 1,450 megawatt generation facility at an existing site in Cumberland, Tennessee. Supported by a long-term contract.

Expected in-service date is third quarter of 2025. (a)

$222 million

Mississippi Crossing project

Project is designed to transport up to 2.1 Bcf/d of natural gas through the construction of approximately 208 miles of 42-inch and 36-inch pipeline and three new compressor stations. Project will originate near Greenville, Mississippi, and terminates near Butler, Alabama, with connections to the existing TGP system and third-party pipelines. Supported by long-term contracts.

Expected in-service date is second quarter 2028.

$1,703 million

Florida Gas Transmission (FGT) projects

Phase IX project designed to construct 82 miles of pipeline looping, as well as new and upgraded compressor station turbines, which will expand capacity to multiple locations across FGT’s market area. South Florida project designed to construct 37-mile lateral to supply the South Florida area, along with compression and a new meter station. Combined, projects will provide approximately 0.8 Bcf/d of additional capacity. Both projects supported by long-term contracts.

Phase IX expected in-service date is fourth quarter 2028 and South Florida project expected in-service date is first quarter 2030.

$700 million

KinderHawk Plantation North expansion

New Plantation treating plant for an added 1.0 Bcf/d of treating at 3.75% CO2, and four pipeline loop/expansions for hydraulic relief.

Expected in-service date is fourth quarter of 2026.

$516 million

Elba Express Bridge project

Project includes a 71-mile extension of Elba Express’s pipeline system into South Carolina and is designed to provide 0.325 Bcf/d of firm transportation capacity. Supported by long-term contracts.

Expected in-service date is second quarter of 2030.

$430 million

TVA Cumberland project

Expected in-service date is first quarter of 2026.

$231 million

North Extension project

Project to expand NGPL’s natural gas transportation capacity from its existing Iowa-Illinois receipt zones to a new proposed interconnect in NGPL’s market delivery zone. Project is designed to provide up to 0.21 Bcf/d of incremental firm transportation service. Supported by a long-term contract.

Expected in-service date is fourth quarter of 2028.

$170 million

GCX pipeline expansion

Expansion project designed to increase natural gas deliveries by 0.57 Bcf/d from the Permian Basin to South Texas markets. Supported by long-term contracts.

Expected in-service date is second quarter of 2026.

$161 million

Tejas South to North expansion

South Texas to Houston Market expansion project. First phase will add compression on Tejas’ mainline and second phase will construct 14 miles of pipeline looping. Combined these projects will provide approximately 0.781 Bcf/d of capacity to key markets.

First phase expected in-service date is first quarter of 2025. Second phase expected in-service date is third quarter of 2025.

$154 million

Hiland Express project (Double H Pipeline system conversion)

Project to convert Double H Pipeline system from crude oil to NGL service, providing Williston Basin producers and midstream companies with pipeline capacity to key market hubs.

Expected in-service date is first quarter of 2026.

$158 million

Products Pipelines

Pelican project

Horsepower replacement project of existing units which will increase TGP’s capacity in southeast Louisiana by 0.29 Bcf/d. Supported by a long-term contract.

Expected in-service date is fourth quarter of 2027.

$135 million

Double H Pipeline system conversion

Project to convert Double H Pipeline system from crude oil to NGL service, providing Williston Basin producers and midstream companies with pipeline capacity to key market hubs.

Expected in-service date is first quarter of 2026.

$149 million

CO2

Diamond M expansion

Enhanced oil recovery expansion at our Diamond M field that will result in peak oil production of over 5,000 Bbl/d.

First phase placed in service in October 2024. Second phase expected in-service date in mid 2025, and peak production in 2026.

$185 million

(a) Pending litigation may delay project.

Financings

During 2024, we issued $3,500 million of new senior notes to repay short-term borrowings, to fund maturing debt and for general corporate purposes and repaid a combined $1,900 million of maturing senior notes.

Asset or project

Description

Activity

Approx. Capital Scope (KMI Share)

Texas Access project (TAP)

TAP is designed to provide KMLP shippers with firm transportation from Texas, including firm receipts from Trident Intrastate pipeline, to new and existing markets in South Louisiana. Supported by customer contracts with a new LNG customer for 1.0 Bcf/d of firm transportation.

Expected in-service date is fourth quarter of 2028.

$112 million

CO2

Diamond M expansion

Enhanced oil recovery expansion at our Diamond M field that will result in peak oil production of approximately 5,400 Bbl/d.

First phase placed in service in October 2024. Expected in-service for second and third phases is in 2026. Peak production of all three phases expected in 2027.

$209 million

Financings

During 2025, we issued $1,850 million of new senior notes to repay short-term borrowings, to fund maturing debt and for general corporate purposes and repaid a combined $1,500 million of maturing senior notes.

Narrative Description of Business

Business Strategy

Our business strategy is to:

•focus on stable, fee-based energy transportation and storage assets that are central to the energy infrastructure of growing markets within North America or served by U.S. exports;

•increase utilization of our existing assets while controlling costs, operating safely, and employing environmentally sound operating practices;

•exercise discipline in capital allocation decisions, including evaluating expansion projects and acquisition opportunities;

•leverage economies of scale through growth from asset expansions and acquisitions that fit within our strategy; and

•maintain a strong financial profile and enhance and return value to our stockholders.

It is our intention to carry out the above business strategy, modified as necessary to reflect changing economic conditions and other circumstances. However, as discussed under Item 1A. “Risk Factors” below and at the beginning of this report in “Information Regarding Forward-Looking Statements,” there are factors that could affect our ability to carry out our strategy or affect its level of success even if carried out.

We regularly consider and enter into discussions regarding potential acquisitions and divestitures, and we are currently contemplating potential transactions. Any such transaction would be subject to negotiation of mutually agreeable terms and conditions, and, as applicable, receipt of fairness opinions, approval of our Board and regulatory approval. While there are currently no unannounced purchase or sale agreements for the acquisition or sale of any material business or assets, such transactions can be effected quickly, may occur at any time and may be significant in size relative to our existing assets or operations.

Business Segments

For financial information on our reportable business segments, see Note 15 “Reportable Segments” to our consolidated financial statements.

Natural Gas Pipelines

Our Natural Gas Pipelines business segment includes interstate and intrastate pipelines, underground storage facilities, ~~our~~ LNG liquefaction and terminal facilities, and NGL fractionation facilities, and includes both FERC regulated and non-FERC regulated assets.

KM Pipelines NG Outlook Assets Labels.jpg

Our primary businesses in this segment consist of natural gas transportation, storage, sales, gathering, processing and treating, and various LNG services. Within this segment are: (i) approximately 4142,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 2625,000 miles of natural gas pipelines, along with associated storage and supply lines for these transportation networks, which are strategically located throughout the North American natural gas pipeline grid. Our transportation network provides access to the major natural gas supply areas and consumers in the western U.S., Rocky Mountain, Midwest, Texas, Louisiana, Southeastern, and Northeast regions. Our LNG terminal facilities also serve natural gas market areas in the southeast. The following table summarizes our significant Natural Gas Pipelines business segment assets as of December 31, ~~2024~~2025. The design capacity represents transmission, gathering, regasification, or liquefaction capacity, depending on the nature of the asset.

Asset	Ownership Interest		Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity
East Region
TGP(a)	100	%	11,~~755~~760	1214.3856	76
NGPL	37.5	%	9,~~100~~105	78.8440	288
KMLP	100	%	140	43.0089	—
Stagecoach	100	%	185	3.22	41
SNG(a)	50	%	6,~~805~~830	4.39	66
Florida Gas Transmission (Citrus)	50	%	5,~~380~~375	4.3970	—
MEP	50	%	515	1.81	—
Elba Express	100	%	190	1.16	—
FEP	50	%	185	2.00	—
Gulf LNG Holdings	50	%	5	1.50	7

Asset	Ownership Interest		Miles of Pipeline	Design (Bcf/d) [(MBbl/d)] Capacity	Storage (Bcf) [Processing (Bcf/d)] Capacity
SLNG	100	%	—	1.76	12
ELC	25.5	%	—	0.35	—
West Region
EPNG/Mojave	100	%	10,~~720~~725	6.41	44
CIG(b)	100	%	4,305	6.00	38
WIC	100	%	850	3.3950	—
CPGPL	100	%	415	1.20	—
TransColorado	100	%	310	0.80	—
Sierrita	35	%	60	0.52	—
Young Gas Storage	47.5	%	15	—	6
Keystone Gas Storage	100	%	15	—	6
Midstream
KM Texas and Tejas pipelines(c)	100	%	6,~~045~~125	9.5030	~~141~~146[0.52]
Mier-Monterrey pipeline(c)	100	%	90	0.65	—
Mier-Monterrey pipeline	100	%	90	0.65	—
KM North Texas pipeline(c)	100	%	80	0.33	—
KM North Texas pipeline	100	%	80	0.33	—
GCX	34	%	530	2.0002	—
PHP	27.74	%	440	2.6566	—
South Texas
South Texas system	100	%	1,~~155~~145	12.9007	[1.02]
Webb/Duval gas gathering system	91	%	~~140~~145	0.1520	—
Camino Real	100	%	75	0.15	—
EagleHawk	25	%	585	1.20	—
KM Altamont	100	%	1,365	0.21	[0.10]
KM Altamont	100	%	1,490	0.16	[0.10]
Red Cedar	49	%	845	0.33	—
Red Cedar	49	%	855	0.33	—
Rocky Mountain
Fort Union	50	%	315	1.25	—
Bighorn	51	%	215	01.6030	—
KinderHawk	100	%	~~570~~585	2.40	—
Greenholly Gathering	39.25	%	40	1.15	—
KM Treating	100	%	40	—	—
Hiland - Williston - gas	100	%	2,205	0.62	[0.33]
Hiland Midstream	100	%	2,310	0.89	[0.60]
Eagle Ford Transmission system	100	%	170	1.05	—
Hiland Express	100	%	550	0.95	—
Eagle Ford Transmission system	100	%	170	1.42	—
NET Mexico	90	%	140	2.15	—
Dos Caminos	50	%	7595	1.20	—
Mission Natural Gas	100	%	1	—	—
Liberty pipeline	50	%	85	[140]	—
South Texas NGL pipelines(d)	100	%	340	[115]	—
Utopia pipeline	50	%	265	[50]	—
Cypress pipeline	50	%	105	[56]	—
EagleHawk - Condensate(e)	25	%	395	[220]	—

(a)Includes proportionate share of storage capacity from our Bear Creek Storage joint venture.

(b)Includes leased pipeline miles and proportionate share of design and storage capacity from our WYCO joint venture.

(c)Collectively referred to as Texas intrastate natural gas pipeline operations.

(d)Includes proportionate share of design capacity from our Liberty pipeline joint venture.

(e)Asset also has storage capacity of 60 MBbl.

Natural Gas Pipelines Segment Contracts

Revenues from our interstate and intrastate natural gas pipelines, related storage facilities, and LNG terminals are primarily received under long-term fixed contracts. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate risk of reduced volumes and prices by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. These long-term contracts are typically structured with a fixed fee reserving the right to transport or store natural gas and specify that we receive the majority of our fee for making the capacity available, whether or not the customer actually chooses to utilize that capacity. ~~Similarly, our Texas Intrastate natural gas pipeline operations currently derive approximately 76% of sales and transport margins from long-term transport and sales contracts.~~ As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, ~~2024~~2025, the remaining weighted average contract life of our natural gas transportation contracts held by assets we own or have equity interests in (including intrastate pipelines’ sales portfolio) was approximately seven years and our LNG regasification and liquefaction and associated storage contracts were subscribed under long-term agreements with a weighted average remaining contract life of approximately 1012 years.

~~Our~~The ~~Midstream assets provide natural gas gathering and processing services. These assets are mostly fee-based, and the~~ revenues and earnings we realize from gathering natural gas, processing natural gas in order to remove NGL from the natural gas stream, and fractionating NGL into its base components, are mostly fee-based and are affected by the volumes of natural gas made available to our systems. Such volumes are impacted by producer rig count and drilling activity. In addition to fee-based arrangements, some of which may include minimum volume commitments, we also provide some services based on percent-of-proceeds, percent-of-index, and keep-whole contracts. Our service contracts sometimes rely solely on a single type of arrangement, but more often they combine elements of two or more of the above, which helps us and our counterparties manage the extent to which each shares in the potential risks and benefits of changing commodity prices. Our natural gas marketing activities generate revenues from the sale and delivery of natural gas purchased either directly from producers or from others on the open market.

Natural Gas Pipelines Segment Competition

The market for natural gas infrastructure is highly competitive, and new pipelines, storage facilities, treating facilities, and facilities for related services are currently being built to serve demand for natural gas in the domestic and export markets served by the pipelines in our Natural Gas Pipelines business segment. We compete with interstate and intrastate pipelines for connections to new markets and supplies and for transportation, processing, storage, and treating services. We believe the principal elements of competition in our various markets are location, rates, terms of service, flexibility, availability of alternative forms of energy, and reliability of service. From time to time, projects are proposed that compete with our existing assets. Whether or when any such projects would be built, or the extent of their impact on our operations or profitability, is typically not known.

Our customers who ship through our natural gas pipelines compete with other forms of energy available to their natural gas customers and end users, including oil, coal, nuclear, and renewables such as hydro, wind, and solar power, along with other evolving forms of renewable energy. Several factors influence the demand for natural gas, including price changes, the availability of supply, other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the ability to convert to alternative fuels, and weather.

Products Pipelines

Our Products Pipelines business segment consists of our refined petroleum products, crude oil, and condensate pipelines, and associated terminals, our condensate processing facility, and our transmix processing facilities.

OSGGIS-3164 Products Segment Outlook Slide 12 10K.jpg

The following summarizes the significant Products Pipelines business segment assets that we owned and operated as of December 31, 2025:


Asset	Ownership Interest		Miles of Pipeline	Number of Terminals (a) or locations	Terminal Capacity (MMBbl)
Crude & Condensate
KM Crude & Condensate pipeline	100	%	266	5	2.6
Camino Real Gathering	100	%	66	1	0.1
Hiland - Williston Basin - oil	100	%	1,662	7	0.8
Double Eagle pipeline	50	%	204	2	0.6
KM Condensate Processing Facility (Splitter)	100	%	—	1	2.1
Southeast Refined Products
Products (SE) pipeline	51	%	3,181	—	—
Central Florida pipeline	100	%	206	2	2.6
Southeast Terminals	100	%	—	25	9.3
Transmix Operations	100	%	—	5	0.6
West Coast Refined Products
Pacific (SFPP)	99.5	%	2,800	13	15.9
CALNEV	100	%	566	2	2.1
West Coast Terminals	100	%	38	8	10.1

(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection, and ethanol blending.

The following summarizes the significant Products Pipelines business segment assets that we owned and operated as of December 31, 2024:

Asset	Ownership Interest		Miles of Pipeline	Number of Terminals (a) or locations	Terminal Capacity(MMBbl)
Crude & Condensate
KM Crude & Condensate pipeline	100	%	266	5	2.6
Camino Real Gathering	100	%	67	1	0.1
Hiland - Williston Basin - oil(b)	100	%	1,618	7	0.8
Double H pipeline(b)	100	%	512	—	—
Double Eagle pipeline	50	%	204	2	0.6
KM Condensate Processing Facility (Splitter)	100	%	—	1	2.1
Southeast Refined Products
Products (SE) pipeline	51	%	3,186	—	—
Central Florida pipeline	100	%	206	2	2.6
Southeast Terminals	100	%	—	25	9.3
Transmix Operations	100	%	—	5	0.6
West Coast Refined Products
Pacific (SFPP)	99.5	%	2,806	13	15.9
CALNEV	100	%	566	2	2.1
West Coast Terminals	100	%	43	8	10.1

(a)The terminals provide services including short-term product storage, truck loading, vapor handling, additive injection, dye injection and ethanol blending.

(b)Collectively referred to as Bakken Crude assets.

Products Pipelines Segment Contracts

The profitability of our refined petroleum products pipeline transportation business generally is driven by the volume of refined petroleum products that we transport and the prices we receive for our services. Included in the number of terminals above are refined products liquids terminals that store fuels and offer blending services for ethanol and biodiesel. The transportation and storage volume levels are primarily driven by the demand for the refined petroleum products being shipped or stored. Demand for refined petroleum products tends to follow trends in population and economic growth, and, with the exception of periods of time with very high product prices or recessionary conditions, demand tends to be relatively stable. Because of that, we seek to own refined petroleum products pipelines and terminals located in, or that transport to, stable or growing markets and population centers. The ~~prices~~transportation ~~for~~rates ~~shipping~~we charge are generally based on regulated tariffs that are adjusted annually based on changes in the U.S. Producer Price Index and a FERC index rate.

Our crude, condensate, and refined petroleum products transportation services are primarily provided pursuant to (i) FERC or state tariffs, which do not require contractual commitments, or (ii) long-term contracts that normally contain minimum volume commitments. ~~Where~~ we have long-term contracts, our settlement volumes are generally not sensitive to changing market conditions in the shorter term; however, the revenues and earnings we realize from our pipelines and terminals are affected by the volumes of crude oil, refined petroleum products and condensate available to our pipeline systems, which are impacted by the levels of oil and gas drilling activity and product demand in the respective regions that we serve. Our petroleum condensate processing facility splits condensate into its various components, such as light and heavy naphtha, under a long-term fee-based agreement with a major integrated oil company. Our crude oil marketing activities generate revenues from the sale and delivery of crude oil and condensate purchased either directly from producers or from others on the open market. In general, sales prices referenced in underlying purchase and sales contracts are market-based and include pricing differentials for factors such as delivery location or crude oil quality.

Products Pipelines Segment Competition

Our Products Pipelines’ pipeline and terminal operations compete against proprietary pipelines and terminals owned and operated by major oil companies, other independent products pipelines and terminals, and trucking and marine transportation firms (for short-haul movement of products). Our transmix operations compete with refineries owned by major oil companies and independent transmix facilities.

Terminals

Our Terminals business segment includes the operations of our refined petroleum product, chemical, renewable fuel, and other liquid terminal facilities (other than those included in the Products Pipelines business segment) and all of our bulk terminal facilities, which handle products such as petroleum coke, metal, and ores, among others. Our terminals are located primarily near large U.S. urban centers. We believe the location of our facilities and our ability to provide flexibility to customers help attract new and retain existing customers at our terminals and provide expansion opportunities. We often classify our terminal operations based on the handling of either liquids or dry-bulk material products. In addition, our Terminals’ operations include Jones Act-qualified product tankers that provide marine transportation of crude oil, condensate, refined petroleum products, and renewable fuel between U.S. ports.

The following summarizes our Terminals business segment assets, as of December 31, ~~2024~~2025:

	Number	Capacity(MMBbl)
Liquids terminals	47	78.67
Bulk terminals	2724	—
Jones Act tankers	16	5.3

Terminals Segment Contracts

The factors impacting our Terminals business segment generally differ between liquid and bulk terminals. Our liquids terminals business generally enters into long-term contracts that require the customer to pay our fee regardless of whether they use the capacity. Thus, similar to our natural gas pipelines business, our liquids terminals business is less sensitive to short-term changes in supply and demand. Therefore, the extent to which changes in supply and demand affect our terminals business in the near term is a function of the remaining length of the underlying service contracts (which on a weighted average basis was approximately two years as of December 31, ~~2024~~2025), the extent to which revenues under the contracts are a function of the amount of product stored or transported, and the extent to which such contracts expire during any given period of time.

As with our refined petroleum products pipelines transportation business, the revenues from our bulk terminals business are generally driven by the volumes we handle and/or store, as well as the prices we receive for our services, which in turn are driven by the demand for the products being shipped or stored. While we handle and store a large variety of products inat our bulk terminals, the primary products are petroleum coke, metals, and ores. In addition, the majority of our contracts for this business contain minimum volume guarantees and/or service exclusivity arrangements under which customers are required to utilize our terminals for all or a specified percentage of their handling and storage needs. The profitability of our minimum volume contracts is generally unaffected by short-term variation in economic conditions; however, to the extent we expect volumes above the minimum and/or have contracts which are volume-based, we can be sensitive to changing market conditions. To the extent practicable and economically feasible in light of our strategic plans and other factors, we generally attempt to mitigate the risk of reduced volumes and pricing by negotiating contracts with longer terms, with higher per-unit pricing and for a greater percentage of our available capacity. The remaining weighted average length of our service contracts was approximately five years as of December 31, 2025. In addition, weather-related events, including hurricanes, may impact our facilities and access to them and, thus, the profitability of certain terminals for limited periods of time or, in relatively rare cases of severe damage to facilities, for longer periods.

Our Jones Act-qualified tankers are primarily operating pursuant to fixed price term charters with major integrated oil companies, major refiners, and the U.S. Military Sealift Command. The remaining weighted average length of our contracts was approximately three years as of December 31, 2025.

Terminals Segment Competition

We are one of the largest independent operators of liquids terminals in the U.S., based on barrels of liquids terminaling capacity. Our liquids terminals compete with other publicly or privately held independent liquids terminals and terminals owned by oil, chemical, pipeline, and refining companies. Our bulk terminals compete with numerous independent terminal operators, terminals owned by producers and distributors of bulk commodities, stevedoring companies, and other industrial companies opting not to outsource terminaling services. In some locations, competitors are smaller, independent operators with lower cost structures. Our Jones Act-qualified tankers compete with other Jones Act-qualified vessel fleets.

CO2

Our CO2 business segment produces, transports, and markets CO2 for use in enhanced oil recovery projects as a flooding medium for recovering crude oil from mature oil fields. We also own and operate oil and gas producing fields, and RNG, LNG, and landfill GTE facilities. Our CO2 pipelines and related assets allow us to market a complete package of CO2 supply and transportation services to our customers.

Source and Transportation Activities

CO2 Resource Interests

Our ownership of CO2 resources as of December 31, ~~2024~~2025 includes:


	Ownership Interest		Compression Capacity (Bcf/d)
McElmo Dome unit	45	%	1.5
Doe Canyon Deep unit	87	%	0.2
Bravo Dome unit(a)	11	%	0.3

(a)We do not operate this unit.

CO2 and Crude Oil Pipelines

Industry demand for transportation on our CO2 pipelines is expected to remain stable for the foreseeable future.

Our ownership of CO2 and crude oil pipelines as of December 31, ~~2024~~2025 includes:

Asset	Ownership Interest		Miles of Pipeline	Transport Capacity (Bcf/d)[(MBbl/d)]
CO2 pipelines
Cortez	53	%	~~569~~572	1.5
Central Basin	100	%	326	0.7
Bravo(a)	13	%	218	0.43
Canyon Reef Carriers	97	%	163	0.3
Centerline	100	%	113	0.3
Eastern Shelf	100	%	98	0.1
Pecos	95	%	25	0.1
Crude oil pipeline
Wink	100	%	~~434~~433	[145]

(a)We do not operate Bravo.

Oil, Gas and RNG Producing Activities

Oil and Gas Producing Interests

Our ownership interests in oil and gas producing fields as of December 31, ~~2024~~2025 included the following:

	Working Interest		KMI Gross Developed Acres
SACROC	97	%	5152,~~457~~029
North McElroy	9899	%	11,612
Yates	50	%	9,~~676~~718
Diamond M	99.5	%	5,396
Sharon Ridge(a)	14	%	2,619
MidCross(a)	13	%	320

(a)We do not operate these fields.

Our oil and gas producing activities are not significant to KMI as a whole; therefore, we do not include the supplemental information on oil and gas producing activities under Accounting Standards Codification Topic 932, Extractive Activities – Oil and Gas.

Gas Plant Interests

Our ownership and operation of gas plants as of December 31, ~~2024~~2025 included:

Asset	Ownership Interest		Source
Snyder gas plant(a)	22	%	The SACROC unit and neighboring CO2 projects, specifically the Lion Diamond M, Reinecke, and Cogdell units
Diamond M gas plant	51	%	Snyder gas plant
North Snyder gas plant	100	%	Snyder gas plant

(a)This is a working interest; in addition, we have a 28% net profits interest.

RNG, LNG, and GTE Facilities

Our ownership and operation of RNG, LNG, and GTE facilities as of December 31, ~~2024~~2025 included:

Asset

Ownership Interest

Production [Storage] Generation Capacity(a)

Product

LNG Indy

100

[2 Bcf]

LNG

Indy High BTU

1.0 Bcf/y

RNG

Twin Bridges

100

1.5 Bcf/y

RNG

Liberty

100

1.5 Bcf/y

RNG

Prairie View

100

0.8 Bcf/y

RNG

Arlington RNG

100

1.3 Bcf/y

RNG

Shreveport RNG(b)

—

0.7 Bcf/y

Medium BTU

Autumn Hills

100

0.8 Bcf/y

RNG

Victoria RNG

100

0.4 Bcf/y

Medium BTU

Southeast Berrien

100

4.8 mW/h

GTE

Central

100

4.0 mW/h

GTE

Venice Park

100

6.4 mW/h

GTE

Morehead

100

1.6 mW/h

GTE

Blue Ridge

100

1.6 mW/h

GTE

(a)GTE generation capacity is measured in megawatts per hour (mW/h). RNG and Medium British Thermal Units (BTU) gas capacities are measured in Bcf per year (Bcf/y).

(b)We operate Shreveport for a fee and receive royalties on RNG sales.

CO2 Segment Contracts

Our CO2 source and transportation business primarily has third-party sales contracts with minimum volume requirements, which as of December 31, ~~2024~~2025 had a remaining average contract life of approximately six years. Our CO2 sales contracts vary from customer to customer and generally provide for a delivered price tied to the price of crude oil, in some cases based on a fixed fee or floor price. Our success in this portion of the CO2 business segment can be impacted by the demand for CO2. In the CO2 business segment’s oil and gas producing activities, we monitor the amount of capital we expend in relation to the amount of production that we expect to add. The revenues we receive from our crude oil, NGL, and ~~NGL~~RIN sales are affected by the prices we realize from ~~the~~these ~~sale~~sales ofand, ~~these~~over ~~products. Over~~ the long term, we tend to receive prices that are driven by the related demand and overall market. ~~price~~However, ~~for~~in ~~these products. In~~ the shorter term, ~~however~~and particularly for crude oil, market prices generally are not indicative of the revenues we will receive due to our hedging program, in which the prices to be realized for certain of our future sales quantities are fixed or bracketed through the use of financial derivative contracts~~, particularly for crude oil~~. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations—Segment Earnings Results” for more information on crude oil sales prices.

CO2 Segment Competition

Our primary competitors for the sale of CO2 include suppliers that have an ownership interest in McElmo Dome, Bravo Dome, and Sheep Mountain CO2 resources. Our ownership interests in the Central Basin, Cortez, and Bravo pipelines are in direct competition with other CO2 pipelines. We compete with other interest owners in the McElmo Dome unit and the Bravo Dome unit for transportation of CO2 to the Denver City, Texas market area.

Major Customers

Our revenue is derived from a wide customer base. For each of the years ended December 31, 2025, 2024, ~~2023~~ and ~~2022~~2023, no revenues from transactions with a single external customer accounted for 10% or more of our total consolidated revenues. We do not believe that a loss of revenues from any single customer would have a material adverse effect on our business, financial position, results of operations or cash flows.

Regulation

Industry Regulation

Our business operations are subject to extensive federal, state, and local laws and regulations. Please read Item 1A. “Risk Factors—Risks Related to Regulation” for discussions of the risks we face related to regulation. For information related to pending regulatory proceedings, see Note 17 “Litigation and Environmental” to our consolidated financial statements.

Interstate Natural Gas Transportation and Storage Regulation

We operate our interstate natural gas pipeline and storage facilities subject to the jurisdiction of the FERC and the provisions of the Natural Gas Act of 1938 (NGA), the Natural Gas Policy Act of 1978 (NGPA), and the Energy Policy Act of 2005 (the Energy Policy Act). These laws give the FERC authority over the siting, construction, and operation of such facilities, including their modification, extension, enlargement and abandonment.

Pursuant to the NGA, the FERC also has authority over the rates charged and terms and conditions of services offered by interstate natural gas pipeline and storage companies. The FERC’s regulatory authority extends to establishing minimum and maximum rates for services and allows operators to discount or negotiate rates on a non-discriminatory basis. The rates, terms and conditions of service are set forth in posted tariffs approved by the FERC for each of our interstate natural gas pipeline and storage companies. Posted tariff rates are deemed just and reasonable and cannot be changed without FERC authorization following an evidentiary hearing or settlement. The FERC can initiate proceedings, on its own initiative or in response to a complaint, that could result in a rate change or confirm existing rates. Negotiated rates provide certainty to the pipeline and the shipper of agreed-upon rates during the term of the transportation agreement, regardless of changes to the posted tariff rates. Negotiated rate agreements must be filed with the FERC or included in summary form in the pipeline’s tariff.

FERC regulations also include a comprehensive framework for market transparency and nondiscrimination, as well as the FERC’s prohibition against market manipulation. Under the Energy Policy Act and related regulations, it is unlawful for any entity, directly or indirectly in connection with the purchase or sale of natural gas subject to the jurisdiction of the FERC, or the purchase or sale of transportation services subject to the jurisdiction of the FERC, to engage in fraudulent conduct. FERC Standards of Conduct regulate, among other things, the manner in which interstate natural gas pipelines may interact with their marketing affiliates. The FERC’s market oversight and transparency regulations require annual reports of purchases or sales of natural gas meeting certain thresholds and criteria and certain public postings of information on scheduled volumes.

The FERC has authority to impose civil penalties of ~~more~~nearly ~~than~~ $1.56 million per day per violation. If we fail to comply with all applicable statutes, rules, regulations, and orders administered by the FERC, we could be subject to substantial civil penalties and fines.

In addition to having jurisdiction over interstate natural gas pipelines and storage companies, the FERC also has jurisdiction over the interstate transportation and storage services that are provided by intrastate natural gas pipelines and storage companies under Section 311 of the NGPA. We have numerous intrastate pipelines and storage companies that provide interstate services pursuant to Section 311 of the NGPA. Under Section 311, along with the FERC’s implementing regulations, an intrastate pipeline may transport gas “on behalf of” an interstate pipeline company or any local distribution company served by an interstate pipeline, without becoming subject to the FERC’s broader regulatory authority under the NGA. These services must be provided on an open and nondiscriminatory basis, and the rates charged for these services may not exceed a “fair and equitable” level as determined by the FERC in periodic rate proceedings.

Interstate Common Carrier Refined Petroleum Products and Oil Pipeline Rate Regulation

Some of our U.S. refined petroleum products, NGL, and crude oil gathering and transmission pipelines are interstate common carrier pipelines, subject to regulation by the FERC under the Interstate Commerce Act, or ICA. The ICA requires that we maintain our tariffs on file with the FERC. Those tariffs set forth the rates we charge for providing gathering or transportation services on our interstate common carrier liquids pipelines as well as the rules and regulations governing these services. The ICA requires, among other things, that rates on interstate common carrier liquids pipelines be “just and reasonable” and nondiscriminatory. The ICA permits interested persons to challenge newly proposed or changed rates and authorizes the FERC to suspend the effectiveness of such rates for a period of up to seven months and to investigate such rates. If, upon completion of an investigation, the FERC finds that the new or changed rate is unlawful, it is authorized to require the carrier to refund to shippers the difference between the revenues collected during the pendency of the investigation and the revenues that would have been collected based on the rate the FERC finds to be just and reasonable. The FERC also may investigate, upon complaint or on its own motion, rates that are already in effect and may order a carrier to change its rates ~~prospectively. Upon an appropriate showing, a shipper may obtain reparations for damages sustained during the two years prior to the filing of a complaint.~~

~~Petroleum~~prospectively. ~~products~~Upon ~~and crude oil pipelines may change their rates within prescribed ceiling levels that are tied to~~ an ~~inflation~~appropriate ~~index. Shippers may protest rate increases made within the ceiling levels~~showing, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. Generally, a ~~petroleum~~shipper ~~products~~may orobtain ~~crude~~reparations ~~oil~~for ~~pipeline~~damages ~~will~~sustained ~~utilize~~during the ~~FERC’s~~two ~~indexing~~years ~~methodology~~prior to ~~adjust its rates, as indexing serves as~~ the ~~default~~filing ~~rate-adjustment mechanism. Cost-~~of~~-service~~ ~~based~~a ~~rates, market-based rates and settlement rates are alternatives to the default indexing mechanism and may be used in certain specified circumstances to change rates~~complaint.

Petroleum products and crude oil pipelines may change their rates within prescribed ceiling levels that are calculated using an inflation index formula determined by the FERC in rulemaking proceedings that occur every five years. Shippers may protest rate increases made within the ceiling levels calculated using this inflation index, but such protests must show that the portion of the rate increase resulting from application of the index is substantially in excess of the pipeline’s increase in costs from the previous year. Generally, a petroleum products or crude oil pipeline will utilize the FERC’s indexing methodology to adjust its rates, as indexing serves as the default rate-adjustment mechanism. Cost-of-service based rates, market-based rates and settlement rates are alternatives to the default indexing mechanism and may be used in certain specified circumstances to change rates.

CPUC Rate Regulation

The intrastate common carrier operations of our refined products pipelines in California are subject to regulation by the CPUC under a “depreciated book plant” methodology, which is based on an original cost measure of investment. Intrastate tariffs filed by us with the CPUC have been established on the basis of revenues, expenses and investments allocated as applicable to the California intrastate portion of the refined products operations’ business. Tariff rates with respect to intrastate pipeline service in California are subject to challenge by protest by interested parties or by independent action of the CPUC.

Railroad Commission of Texas (RCT) Rate Regulation

The intrastate operations of our crude oil and liquids pipelines and natural gas pipelines and storage facilities in Texas are subject to regulation with respect to such intrastate transportation by the RCT. The RCT has the authority to regulate our rates, though it generally has not investigated the rates or practices of our intrastate pipelines in the absence of shipper complaints.

State and Local Regulation

Certain of our activities are subject to various state and local laws and regulations, as well as orders of regulatory bodies, governing a wide variety of matters, including marketing, production, pricing, pipeline safety, protection of the environment, and human health and safety.

Marine Operations

The operation of tankers and marine equipment is subject to maritime obligations involving property, personnel and cargo under General Maritime Law and involves a variety of risks, including, among other things, the risk of collision or allision, which may result in claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities.

We are subject to the Jones Act and other federal laws that restrict maritime transportation (between U.S. departure and destination points) to vessels built and registered in the U.S. and owned and crewed by U.S. citizens. As a result, we monitor the foreign ownership of our common stock and, under certain circumstances consistent with our certificate of incorporation, we have the right to redeem shares of our common stock owned by non-U.S. citizens. If we do not comply with such requirements, we would be prohibited from operating our vessels in U.S. coastwise trade, and under certain circumstances we would be deemed to have undertaken an unapproved foreign transfer, resulting in severe penalties, including permanent loss of U.S. coastwise trading rights for our vessels, fines, or forfeiture of the vessels. From time to time, legislation has been introduced unsuccessfully in the U.S. Congress to amend the Jones Act to ease or remove the requirement that vessels operating between U.S. ports be built and registered in the U.S. and owned and crewed by U.S. citizens. If the Jones Act were amended in such fashion, we could face competition from foreign-flagged vessels.

In addition, the U.S. Coast Guard and the American Bureau of Shipping maintain a very stringent regime of vessel inspection, which tends to result in higher regulatory compliance costs for U.S.-flagged operators than for owners of vessels registered under foreign flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.

The Merchant Marine Act of 1936 is a federal law that provides the U.S. Secretary of Transportation, upon proclamation by the U.S. President of a national emergency or a threat to the national security, the authority to requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our vessels were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.

the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, we would not be entitled to compensation for any consequential damages suffered as a result of such purchase or requisition.

Derivatives Regulation

We use energy commodity derivative contracts as part of our strategy to hedge our exposure to energy commodity market risk and other external risks in the ordinary course of business. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments such as futures and options contracts, fixed price swaps and basis swaps. The Dodd-Frank Wall Street Reform and Consumer Protection Act (Dodd-Frank Act) requires the U.S. Commodity Futures Trading Commission and the SEC to promulgate rules and regulations establishing federal oversight and regulation of the OTC derivatives market and entities that participate in that market including broad aggregate position limits for OTC swaps and futures and options traded on regulated exchanges. These rules include exemptions for hedging positions.

Environmental Matters and Safety Regulation

Our business operations are subject to extensive federal, state, and local laws and regulations relating to environmental protection and human health and safety. For example, if a leak, release or spill of liquid petroleum products, CO2, natural gas, methane, chemicals, or other hazardous substances occurs at or from our pipelines, storage, or other facilities, we may experience significant operational disruptions, and we may have to pay a significant amount to clean up the leak, release, or spill (in the case of a non-gaseous substance), pay government penalties, address natural resource damages, compensate for human exposure or property damage, install pollution control equipment, or a combination of these and other measures. Furthermore, new projects may require permits, approvals, and environmental analyses under federal and state laws, including the ~~Pipeline Safety Act, the~~ Clean Water Act, the Clean Air Act, the National Environmental Policy Act, and the Endangered Species Act. The resulting costs and liabilities could be material to us, and increasing compliance costs under federal and state, and in some cases local, environmental and safety laws for both new and existing facilities could require us to make significant capital expenditures. Please read Item 1A. “Risk Factors—Risks Related to Regulation.”

AIn ~~certain~~accordance ~~degree~~with ofGAAP, ~~regulatory~~we ~~uncertainty~~record isliabilities ~~created~~for byenvironmental ~~the~~matters ~~recent~~when ~~change~~it inis ~~U.S.~~probable ~~presidential~~that ~~administrations. It~~obligations ~~remains~~have ~~unclear~~been ~~specifically~~incurred ~~what~~and the ~~new~~amounts ~~administration~~can ~~may~~be doreasonably ~~with respect to future policies and regulations that may affect us~~estimated. In ~~general,~~For ~~the~~information ~~cost~~related to ~~comply~~pending ~~with~~ environmental ~~and~~matters, ~~safety~~including ~~regulations~~our isaccruals ~~increasing. These~~of ~~costs~~environmental ~~have~~liabilities, ~~the~~see ~~potential~~Note to17 ~~limit~~“Litigation ~~the return on capital projects~~ and ~~the~~Environmental” ~~number~~to ofour ~~capital~~consolidated ~~projects~~financial ~~that are economically viable~~statements. ~~Please read Item 1A. “Risk Factors—Risks Related to Regulation.”~~

In accordance with GAAP, we record liabilities for environmental matters when it is probable that obligations have been incurred and the amounts can be reasonably estimated. For information related to pending environmental matters, including our accruals of environmental reserves, see Note 17 “Litigation and Environmental” to our consolidated financial statements.

Hazardous and Non-Hazardous Waste

We generate both hazardous and non-hazardous wastes that are subject to the requirements of the Federal Resource Conservation and Recovery Act (RCRA) and comparable state statutes. RCRA establishes standards for the generation, treatment, storage, transport, and disposal of solid wastes, including hazardous wastes.

Superfund

The CERCLA or the Superfund law, and analogous state laws, impose joint and several liability, without regard to fault or the legality of the original conduct, on certain classes of potentially responsible persons for releases of hazardous substances into the environment. These persons include the owner or operator of a site and/or companies that disposed or arranged for the disposal of the hazardous substances found at the site. CERCLA authorizes the EPA and, in some cases, third parties to take actions in response to threats to public health or the environment and to seek to recover from the responsible classes of persons the costs they incur, including remediation costs. Additionally, CERCLA allows for the recovery of compensation for natural resource damages, if any. Although petroleum is excluded from CERCLA’s definition of a “hazardous substance,” in the course of our ordinary operations, we have and will generate materials that may fall within such definition. If we are determined to be a potentially responsible person by operation of law under CERCLA, we may be responsible for all or part of the costs required to evaluate and remediate sites at which such materials are present, in addition to compensation for natural resource damages, if any.

Clean Air Act

Our operations are subject to the Clean Air Act, its implementing regulations, and analogous state statutes and regulations. The EPA regulations under the Clean Air Act contain requirements for the monitoring, reporting, and control of emissions of regulated substances. Substances regulated under the Clean Air Act have included greenhouse gas (GHG) emissions from stationary sources; however, the EPA’s recent rulemakings indicate its intention to revisit its regulation of GHG emissions under the Clean Air Act. For further information, see “—Climate Change” below.

regulated substances, including greenhouse gas (GHG) emissions from stationary sources. For further information, see “—Climate Change” below.

Clean Water Act

Our operations can result in the discharge of pollutants. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, and analogous state laws impose restrictions and controls regarding the discharge of fills and pollutants into waters of the U.S. The discharge of fills and pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by applicable federal or state authorities. The Oil Pollution Act was enacted in 1990 and amends provisions of the Clean Water Act pertaining to prevention of and response to oil spills. Spill prevention, control and countermeasure requirements of the Clean Water Act and some state laws require containment and similar structures to help prevent contamination of navigable waters in the event of an overflow or release of oil.

EPA Revisions to National Ambient Air Quality Standards

As required by the Clean Air Act, the EPA establishes National Ambient Air Quality Standards (NAAQS) setting acceptable levels of common pollutants such as ozone, particulate matter, and sulfur dioxide. States then are required to adopt State Implementation Plans (SIPs) ensuring their air quality meets the applicable NAAQS. The EPA reviews these SIPs to ensure they comply with the NAAQS and other provisions of the Clean Air Act~~, including the Good Neighbor provision~~. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation,” and Note 17 “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements.

For ground level ozone, the EPA published a rule in October 2015 that lowered NAAQS from 75 parts per billion (ppb) to a more stringent 70 ppb standard. This change triggered a process under which the EPA designated the areas of the country in or out of compliance with the 2015 standards. In December 2020, the EPA completed a review of the ozone NAAQS and published a rule retaining the 2015 standards.

State rules implementing the NAAQS require the installation of more stringent air pollution controls on newly installed equipment and possibly require the retrofitting of existing KMI facilities with air pollution controls. These rules will have financial impacts to our Natural Gas Pipelines business segment. Future state or federal rules relating to the EPA’s establishment of NAAQS for ozone, particulate matter, or other criteria air pollutants could have financial impacts on multiple business units.

Climate Change

Due to concern over climate change, numerous proposals to monitor and limit emissions of GHGs have been made and are likely to continue to be made at the federal, state, and local levels of government and by the governments of other nations. Methane, a primary component of natural gas, and CO2, which is naturally occurring and also a byproduct of burning natural gas, are examples of GHGs. Various laws and regulations exist or are under development to regulate the emission of ~~such~~ GHGs~~, including the EPA programs requiring the reduction, monitoring, and reporting of GHG emissions levels and state actions to develop statewide or regional programs~~. The U.S. Congress has in the past considered and, in some cases, passed legislation to reduce emissions of GHGs. In addition, the European Union has approved a law to impose limits on methane emissions intensity applicable to imports of natural gas and crude oil beginning in 2030.

Beginning in 2009, the EPA published several findings, including a finding that GHGs present a danger to public health and the environment, known as the “endangerment finding,” and rulemakings under the Clean Air Act requiring the permitting and reporting of certain GHGs~~, including CO2 and methane~~. Certain of our facilities are subject to these reporting requirements~~. Operational~~, and operational or physical changes to other existing facilities could ~~require~~subject those facilities to ~~comply with~~ these requirements. In ~~addition,~~ recent years, EPA also made regulatory changes ~~require~~requiring many existing oil and natural gas facilities to reduce GHG emissions,. ~~and~~However, ~~pursuant~~in ~~to a Congressional mandate~~2025, ~~PHMSA~~EPA ~~has~~announced ~~proposed~~its ~~regulations~~intention to ~~impose~~reconsider ~~leak~~the ~~detection~~endangerment ~~and~~finding, ~~repair~~as ~~requirements~~well onas ~~natural~~EPA’s ~~gas~~mandatory ~~pipelines~~GHG Reporting Program, and aon ~~final~~February ~~rule~~12, is2026, ~~pending. See~~the ~~Item~~EPA ~~1A.~~announced ~~“Risk~~that ~~Factors—Risks~~it ~~Related~~will toissue ~~Regulation—New~~a ~~laws,~~final ~~policies,~~rule ~~regulations,~~rescinding ~~rulemaking~~the ~~and~~endangerment ~~oversight~~finding, asthereby ~~well~~eliminating asthe ~~changes~~basis tofor ~~those~~much ~~currently~~of inits ~~effect,~~regulation ~~could~~of ~~adversely~~GHG ~~impact~~emissions. ~~our~~Based ~~earnings,~~on ~~cash~~EPA’s ~~flows~~recent rulemakings and ~~operations.”~~disclosed ~~and~~objectives, “we ~~—Increased~~may ~~regulatory~~experience ~~requirements~~a ~~relating~~reduction toin ~~the~~GHG ~~safety~~reporting and ~~integrity~~other ofregulatory ~~our~~obligations ~~pipelines~~at ~~may~~the ~~require~~federal uslevel toover ~~incur~~the ~~significant~~near ~~capital and operating expense outlays to comply~~term.”

At the state level, more than one-third of the states, either individually or through multi-state regional initiatives, already have begun implementing legal measures to reduce emissions of GHGs, such as through mandatory reporting, establishment of GHG emission reduction targets, or regional GHG “cap-and-trade” programs. It is possible that sources such as our gas-fueled compressors and processing plants could become subject to these state GHG reduction regulations. Various states are also proposing or have implemented stricter regulations for reporting, monitoring, or reducing GHGs that go beyond the requirements of the EPA as they existed at the end of 2025. Compliance with state rules could require additional expenditures, above and beyond those spent to comply with EPA GHG rules for new and existing sources. In addition, the European Union has approved a law to impose limits on methane emissions intensity applicable to imports of natural gas and crude oil beginning in 2030.

Because our operations, including the compressor stations and processing plants, emit various types of GHGs, primarily methane and CO2, such new legislation or regulation could increase the costs related to operating and maintaining our facilities. Depending on the particular law, regulation or program, we may be required to incur significant additional operating or capital

~~implemented~~costs ~~stricter~~to ~~regulations~~install new monitoring equipment or emission controls on the facilities, acquire and surrender allowances for ~~reporting~~the GHG emissions, ~~monitoring~~replace certain GHG-emitting devices or ~~reducing~~technologies, ~~GHGs~~pay ~~that~~taxes gorelated ~~beyond~~to the ~~requirements~~GHG ofemissions, ~~the~~and ~~EPA~~administer and manage a more comprehensive GHG emissions program. ~~Compliance~~ ~~with~~While ~~state~~we ~~rules~~may ~~could~~be ~~require~~able ~~additional~~to ~~expenditures~~include some or all of such increased costs in the rates charged by our pipelines, ~~above~~recovery of costs is uncertain and may depend on events beyond ~~those~~our ~~spent~~control, toincluding ~~comply~~the ~~with~~outcome ~~EPA~~of ~~GHG~~future ~~rules~~rate ~~for~~proceedings ~~new~~before the FERC or other regulatory bodies, and ~~existing~~the ~~sources~~provisions of any final legislation or other regulations.

Because ~~our~~the ~~operations,~~combustion ~~including~~of ~~the~~natural ~~compressor~~gas ~~stations~~produces ~~and~~lower ~~processing~~GHG ~~plants,~~emissions ~~emit~~per ~~various~~unit ~~types~~ of ~~GHGs,~~energy ~~primarily~~than ~~methane~~competing ~~and~~fossil ~~CO2~~fuels, ~~such~~cap-and-trade ~~new~~ legislation or ~~regulation~~EPA ~~could~~regulatory ~~increase~~initiatives ~~the costs related~~ to ~~operating~~reduce ~~and~~GHGs ~~maintaining~~could ~~our~~stimulate ~~facilities. Depending~~demand onfor ~~the~~natural ~~particular~~gas ~~law,~~by ~~regulation~~increasing orthe ~~program,~~relative wecost ~~may~~of becompeting ~~required~~fuels tosuch ~~incur~~as ~~significant~~coal ~~additional~~and ~~operating~~oil. orIn ~~capital~~addition, ~~costs~~we toanticipate ~~install~~that ~~new~~GHG ~~monitoring~~regulations ~~equipment~~will orincrease ~~emission~~demand ~~controls~~for oncarbon ~~the~~sequestration ~~facilities~~technologies, ~~acquire~~such ~~and~~as ~~surrender allowances for~~ the ~~GHG~~techniques ~~emissions,~~we ~~replace~~have ~~certain~~successfully ~~GHG-emitting~~demonstrated ~~devices~~in orour ~~technologies,~~enhanced ~~pay~~oil ~~taxes~~recovery ~~related~~operations towithin ~~the~~our ~~GHG~~CO2 ~~emissions~~business ~~and~~segment. ~~administer~~However, ~~and~~these ~~manage~~potential apositive ~~more~~effects ~~comprehensive~~on ~~GHG~~our ~~emissions~~markets ~~program. While we~~ may be ~~able~~offset toif ~~include~~these ~~some~~same orregulations ~~all~~also ofcause ~~such~~the ~~increased~~cost ~~costs~~of innatural ~~the~~gas ~~rates~~to ~~charged~~increase byrelative ~~our~~to ~~pipelines,~~competing ~~recovery~~non-fossil offuels. ~~costs~~Although iswe ~~uncertain~~currently ~~and~~cannot ~~may~~predict ~~depend~~the onmagnitude ~~events~~and ~~beyond~~direction ~~our~~of ~~control~~these impacts, ~~including~~GHG ~~the~~regulations ~~outcome~~could ofhave ~~future~~material ~~rate~~adverse ~~proceedings~~effects ~~before~~on ~~the~~our ~~FERC~~business, orfinancial ~~other regulatory bodies~~position, ~~and~~results ~~the provisions~~ of ~~any~~operations, ~~final legislation~~ or ~~other~~cash ~~regulations~~flows.

Because the combustion of natural gas produces lower GHG emissions per unit of energy than competing fossil fuels, cap-and-trade legislation or EPA regulatory initiatives to reduce GHGs could stimulate demand for natural gas by increasing the relative cost of competing fuels such as coal and oil. In addition, we anticipate that GHG regulations will increase demand for carbon sequestration technologies, such as the techniques we have successfully demonstrated in our enhanced oil recovery operations within our CO2 business segment. However, these potential positive effects on our markets may be offset if these same regulations also cause the cost of natural gas to increase relative to competing non-fossil fuels. Although we currently cannot predict the magnitude and direction of these impacts, GHG regulations could have material adverse effects on our business, financial position, results of operations or cash flows.

Pipeline Safety Regulation

We are subject to pipeline safety regulations issued by PHMSA as well as any states that are certified by PHMSA to regulate pipeline safety for regulated intrastate ~~pipelines~~assets in their respective states. These regulations apply to natural gas and hazardous liquid pipelines and pipeline facilities, including associated underground natural gas storage, terminals, and LNG facilities. PHMSA regulations in particular, require us to develop and maintain pipeline integrity management programs to evaluate our pipelines and take additional measures to protect pipeline segments located in what are referred to as High Consequence Areas (HCAs) for both gas and liquid pipelines, where a release could potentially have the most adverse consequences. ~~Additionally,~~ PHMSA ~~recently~~also ~~issued~~requires ~~requirements that require~~ us to conduct additional assessments to identify risks in what are referred to as Moderate Consequence Areas (MCAs) for gas pipelines.

~~Since 2019,~~ PHMSA has implemented several rules that ~~impose~~have ~~additional~~increased our pipeline safety ~~requirements~~regulatory obligations, including without limitation: (i) expanding certain integrity management program requirements outside of HCAs (with some exceptions) for both gas and hazardous liquid pipelines; (ii) expanding the application of integrity management requirements relevant to hazardous liquid pipelines to include additional areas, including certain coastal waters; (iii) requiring reconfirmation of the maximum allowable operating pressure (MAOP) by 2035 and material verification on certain gas pipelines; (iv) requiring installation of remote control or automatic shut-off valves (or alternative equivalent technology) on certain newly constructed or replaced gas and liquid pipelines; (v) increasing requirements for corrosion control for gas pipelines; (vi) providing additional prescriptive requirements that increase conservatism and specificity on the evaluation of discovered anomalies and their associated repair criteria for gas pipelines; and (vii) expanding certain regulations to previously unregulated gas gathering assets.

Employee Health and Safety Regulations

We are subject to the requirements of federal and state agencies, including, where appropriate, the Occupational Safety and Health Administration (OSHA), that address, among other things, employee health and safety.

Cybersecurity Regulation

In response to ongoing cybersecurity threats affecting the pipeline industry, the Department of Homeland Security’s (DHS) Transportation Security Administration, or TSA, has issued a series of security directives setting forth specific elements that owners and operators of certain “critical” pipelines must include in their cybersecurity planning and their reporting of any incidents. These security directives require, among other things, that identified pipeline owners comply with mandatory reporting measures; designate a cybersecurity coordinator; provide vulnerability assessments; ensure compliance with certain cybersecurity requirements; establish and implement a TSA-approved Cybersecurity Implementation Plan; develop and maintain a Cybersecurity Incident Response Plan (CIRP), which shall ~~include~~identify the individuals ~~identified~~responsible asfor ~~active~~implementing ~~participants~~the specific measures in the CIRP ~~exercises,~~ and annually test at least two CIRP objectives; and establish a Cybersecurity Assessment Plan (CAP), and annually submit an updated CAP to TSA for review and approval, which shall include a schedule for assessing and auditing specific cybersecurity measures for effectiveness. TSA issued a proposed rulemaking in 2024 to codify and expand these requirements for certain pipeline assets and LNG facilities, including obligations to report cybersecurity incidents to the Cybersecurity and Infrastructure Security Agency (CISA) and physical security incidents to TSA. This proposed rule is currently categorized by DHS as a long-term regulatory action with no projected timetable for a final rule.

Our Jones Act Tankers and coastal terminal facilities are subject to a final rule, titled Cybersecurity in the Marine Transportation System (MTS), which was issued by the U.S. Coast Guard and became effective on July 16, 2025. Requirements

~~annually~~in ~~submit~~the anfinal ~~updated~~rule ~~CAP~~include todeveloping ~~TSA~~and ~~for~~maintaining ~~review~~a ~~and~~cybersecurity ~~approval~~plan, ~~which~~designating ~~shall include~~ a ~~schedule~~cybersecurity ~~for~~officer ~~assessing~~(CySO), and ~~auditing~~taking ~~specific~~various ~~cybersecurity~~ measures ~~for~~to ~~effectiveness. TSA~~maintain ~~recently~~cybersecurity ~~issued~~within athe ~~proposed~~MTS. ~~rulemaking~~The toregulation ~~codify~~contains ~~and~~a ~~expand~~phased ~~these~~implementation ~~requirements~~schedule, ~~for~~with ~~certain~~the ~~pipeline~~full ~~assets~~cybersecurity plan submission and ~~LNG~~CySO ~~facilities,~~designation ~~including~~due ~~obligations~~by toJuly ~~report~~16, ~~cybersecurity~~2027, ~~incidents~~aiming to strengthen the ~~Cybersecurity~~MTS ~~and~~against ~~Infrastructure~~cyber ~~Security Agency and physical security incidents to TSA~~threats.

In addition, PHMSA requires reporting of certain events that involve a release from a pipeline or the shutdown of aan ~~pipeline~~LNG facility or underground natural gas storage facility, including those that may be caused by a cyber-attack. On July 26, 2023, the SEC adopted new disclosure requirements regarding cybersecurity risk management, strategy, governance, and incidents. ~~Please~~ ~~read~~In ~~Item~~2024, ~~1C.~~CISA ~~“Cybersecurity.” Regulations~~also ~~are~~issued ~~also~~a ~~under~~proposed ~~development~~rulemaking to implement ~~reporting~~the requirements ~~under~~set forth in the Cyber Incident Reporting for Critical Infrastructure Act of 2022, a law concerning the reporting of cyber incidents and ransomware payments. ~~that~~A final rule is ~~expected~~currently toprojected ~~take~~for ~~effect~~the inmiddle ~~2024~~of 2026. Please read Item 1C. “Cybersecurity.”

Human Capital

In managing our human capital resources, we use a strategic approach to attract, develop, and retain talent and support our employees’ career and development goals. We value our employees’ opinions and encourage them to engage with management and ask questions on topics such as our goals, challenges, and employee concerns.

We employed 1011,~~933~~028 full-time personnel at December 31, ~~2024~~2025, including approximately ~~883~~867 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between ~~2025~~2026 and 2029. We consider relations with our employees to be good.

We value the safety of our workforce and integrate a culture of safety, emergency preparedness, and environmental responsibility through our operations management system (OMS). Our OMS conforms to common industry standards and establishes a framework that helps us (i) provide employees and contractors with a safe work environment; (ii) comply with laws, rules, regulations, policies, and procedures; and (iii) identify opportunities to improve. Although our ultimate target is zero incidents, we also have ~~three~~ non-zero employee safety performance targets as follows:

Non-zero employee safety performance target						2024 Company-wide TRIR
Non-zero employee safety performance targets						2025 Company-wide TRIR(a)
Outperform the annual industry average total recordable incident rate (TRIR)						0.89
Outperform our own three-year TRIR average
Improve our company-wide employee TRIR from 1.0 in the baseline year 2019 to 0.7 by 2024

(a)TRIR is an OSHA-defined metric that represents the number of recordable workplace incidents per 100 full‑time employees in a given year.

We seek to constantly improve our contractor TRIR performance through initiatives to address recent incident trends and new best practices.

The Nominating and Governance Committee (Nom/Gov Committee) of our Board is responsible for planning for succession in our senior management ranks, including our chief executive officer. Our chief executive officer reports to the Nom/Gov Committee annually, generally at the time of the regularly scheduled July Board meeting, regarding the succession plan and processes in place to identify talent within and outside the Company to succeed to senior management positions, development opportunities for potential successors, and the information developed during the then-current calendar year pursuant to those processes. As part of our annual succession planning process, we identify a range of potential candidates to include in the plan for senior positions.

We support equal opportunity employment and consider a range of talents and experience an asset. It is our policy to employ and advance in employment all persons without regard to their race/ethnicity;, sex;, sexual orientation;, gender;, veteran status;, disability;, or other protected categories, and base employment decisions solely on valid job requirements. We are committed to a harassment free workplace, supported with online and face-to-face workplace harassment and discrimination prevention training for our employees. In addition to training received at the time of hiring, employees and supervisors review our harassment and discrimination prevention policy every two years as part of our required training.

Our employees are an integral part of our success, and we value their career development. We support our employees’ ongoing career goals and development through several programs, including workforce training, tuition reimbursement, leadership and other development programs. These programs help improve recruitment, development, and retention and help maximize our employees’ potential by providing opportunities to gain skills they need to further enhance their careers.

Our compensation program is linked to long- and short-term strategic financial and operational objectives, including environmental, safety, and compliance targets. Compensation includes competitive base salaries in the markets in which we operate and competitive benefits, including retirement plans, opportunities for annual bonuses, and, for eligible employees, long-term incentives and an employee stock purchase plan.

Properties and Rights-of-Way

We believe we generally have satisfactory title to the properties we own and use in our businesses, subject to liens for current taxes, liens incident to minor encumbrances, and easements and restrictions, which do not materially detract from the value of such property, the interests in those properties, or the use of such properties in our businesses. Our terminals, storage facilities, treating and processing plants, regulator and compressor stations, oil and gas wells, offices, and related facilities are located on real property owned or leased by us. In some cases, the real property we lease is on federal, state or local government land.

We generally do not own the land on which our pipelines are constructed. Instead, we obtain and maintain rights to construct and operate the pipelines on other people’s land, generally under agreements that are perpetual or provide for renewal rights. Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of such property. In many instances, lands over which rights-of-way have been obtained are subject to prior liens that have not been subordinated to the right-of-way grants. In some cases, not all of the apparent record owners have joined in the right-of-way grants, but in substantially all such cases, signatures of the owners of a majority of the interests have been obtained. Permits have been obtained from public authorities to cross over or under, or to lay facilities in or along, water courses, county roads, municipal streets, and state highways, and in some instances, such permits are revocable at the election of the grantor, or, the pipeline may be required to move its facilities at its own expense. Permits also have been obtained from railroad companies to run along or cross over or under lands or rights-of-way, many of which are also revocable at the grantor’s election. Some such permits require annual or other periodic payments. In a few minor cases, we purchased property for pipeline purposes.

Available Information

We make available free of charge on or through our internet website, at www.kindermorgan.com, our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC. The SEC maintains an internet site that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC at http://www.sec.gov. The information contained on or connected to our internet website is not incorporated by reference into this Form 10-K and should not be considered part of this or any other report that we file with or furnish to the SEC.

Item 1A. Risk Factors.

You should carefully consider the risks described below, in addition to the other information contained in this document. Realization of any of the following risks could have a material adverse effect on our business, financial condition, cash flows, and results of operations.

Risks Related to our Business

Our businesses are dependent on the supply of and demand for the products we handle.

Our pipelines, terminals, and other assets and facilities, including the availability of expansion opportunities, depend in part on continued production of natural gas, crude oil, and other products in the geographic areas that they serve. Without additions to crude oil and gas reserves, production will decline over time as reserves are depleted, and production costs may rise. Producers in areas served by us may not be successful in exploring for and developing additional reserves, or their costs of doing so may become uneconomic. Commodity prices and tax incentives may not remain at levels that encourage producers to explore for and develop additional reserves, produce existing marginal reserves, or renew transportation contracts as they expire. Our business also depends in part on the levels of demand for natural gas, crude oil, NGL, refined petroleum products, CO2, steel, chemicals, and other products in the geographic areas to which our pipelines, terminals, shipping vessels, and other facilities deliver or provide service, and the ability and willingness of our shippers and other customers to supply such demand. Decreases in the supply of or demand for natural gas, crude oil, and other products could adversely impact the utilization of our assets.

Conditions in the business environment generally, such as declining or sustained low commodity prices, supply disruptions, or higher development or production costs, could result in a slowing of supply to our pipelines, terminals, and other assets. Also, sustained lower demand for hydrocarbons, or changes in the regulatory environment or applicable government policies and priorities, including in relation to climate change or other environmental concerns, may have a negative impact on the supply of crude oil and other products. ~~Public~~ In recent years, public concern about the potential risks posed by climate change has resulted in increased demand for energy efficiency and a transition to energy provided from renewable energy sources rather than fossil fuels, fuel-efficient alternatives such as hybrid and electric vehicles, and pursuit of other technologies to reduce GHG emissions, such as carbon capture and sequestration. ~~We have seen and may see further intensification of these trends.~~

Each of the foregoing supply and demand issues could negatively impact our business directly, as well as our shippers and other customers, which in turn could negatively impact our prospects for new contracts for transportation, terminaling, or other midstream services, or renewals of existing contracts or the ability of our customers and shippers to honor their contractual commitments. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.” below. Furthermore, such unfavorable conditions may compound the adverse effects of larger economic disruptions. See “—Our operating results may be adversely affected by unfavorable economic and market conditions.”

We cannot predict the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, governmental regulation, and/or tax incentives or technological advances in fuel economy and energy generation devices, all of which could reduce the production of and/or demand for the products we handle.

Expanding our existing assets and constructing new assets is part of our growth strategy. Our ability to begin and complete expansion and new-build projects may be inhibited by difficulties in obtaining permits and rights-of-way, public opposition, increases in costs of construction materials, cost overruns, inclement weather, and other delays. If we pursue projects through joint ventures with others, we will share control of and any benefits from those projects.

We regularly undertake construction projects to expand our existing assets and to construct new assets. ~~New~~ ~~growth~~These projects generally will be subject to, among other things, the receipt of regulatory approvals, feasibility and cost analyses, funding availability, industry, market and demand conditions, and environmental ~~justice~~ considerations. A variety of factors outside of our control, such as difficulties in obtaining rights-of-way and permits or other regulatory approvals, have caused, and may continue to cause, delays in or cancellations of our construction projects. Regulatory authorities may modify their permitting policies in ways that disadvantage our construction projects. Federal regulators may also expand existing regulatory requirements, such as PHMSA’s ~~recent~~2021 expansion of gas gathering pipeline regulation and the Congressional mandate under the Pipeline Safety Act that PHMSA regulate the transportation of gaseous CO2. Such factors can be exacerbated by public opposition to our projects. See “—We are subject to reputational risks and risks relating to public opinion.” Inclement weather, natural disasters, and delays in performance by third-party contractors have also resulted in, and may ~~continue~~in tothe future result in, increased costs or delays in construction. In addition, we ~~may~~have ~~experience~~experienced increasing costs for construction materials, including cost increases associated with increased tariffs (such as those ~~proposed~~discussed byunder ~~the~~“—Changes ~~new~~in U.S. ~~presidential~~trade ~~administration~~policy and the impact of tariffs may have a material adverse effect on our business and results of operations.”) and may continue to experience such cost impacts. Significant increases in costs of construction materials, cost overruns or delays, or our inability to obtain a required permit or right-of-way, could have a material adverse effect on our return on investment, results of operations, and cash flows, and could result in project cancellations or otherwise limit our ability to pursue growth opportunities.

If we pursue joint ventures with third parties, those parties may share approval rights over major decisions and may act in their own interests, which may differ from our interests or our views of the interests of the venture. Such differences in actual or perceived interests could result in operational delays or impasses, which in turn could affect the financial expectations of and our expected benefits from the venture.

We face competition from other pipelines and terminals, as well as other forms of transportation and storage.

Competition is a factor affecting our existing businesses and our ability to secure new project opportunities. Any current or future pipeline system or other form of transportation (such as barge, rail, or truck) that delivers the products we handle into the areas that our pipelines serve could offer transportation services that are more desirable to shippers than those we provide because of price, location, facilities, or other factors. Likewise, competing terminals or other storage options may become more attractive to our customers. To the extent that competitors offer the markets we serve more desirable transportation or storage options, or customers opt to construct their own facilities for services previously provided by us, this could result in unused capacity on our pipelines and in our terminals. We also could experience competition for the supply of the products we handle from both existing and proposed pipeline systems; for example, several pipelines access many of the same areas of supply as our pipeline systems and transport to destinations not served by us. If capacity on our assets remains unused, our ability to re-contract for expiring capacity at favorable rates or otherwise retain existing customers could be impaired. In addition, to the extent that companies pursuing development of carbon capture and sequestration technology are successful, they could compete with us for customers who purchase CO2 for use in enhanced oil recovery operations.

~~The~~contract ~~volatility~~for ofexpiring ~~crude~~capacity ~~oil~~at favorable rates or otherwise retain existing customers could be impaired. In addition, ~~NGL~~to the extent that companies pursuing development of carbon capture and ~~natural~~sequestration ~~gas~~technology ~~prices~~are successful, they could ~~adversely~~compete ~~affect~~with ~~our~~us ~~business~~for customers who purchase CO2 for use in enhanced oil recovery operations.

The ~~revenues,~~volatility ~~cash flows, profitability and future growth~~ of ~~some of our businesses (and the carrying values of certain of their respective assets, which include related goodwill) depend to a large degree on prevailing~~ crude oil, NGL, and natural gas prices could adversely affect our business.

~~Prices~~The ~~for crude oil~~revenues, ~~NGL~~cash ~~and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil~~flows, ~~NGL and natural gas~~profitability, ~~uncertainties within the market~~ and afuture ~~variety~~growth of ~~other~~some ~~factors~~of ~~beyond~~ our ~~control. These~~businesses ~~factors include, among other things~~ (~~i) weather conditions~~ and ~~events such as hurricanes in~~ the ~~U.S.;~~carrying ~~(ii)~~values ~~domestic and global economic conditions; (iii) the activities~~ of ~~the~~certain ~~OPEC and other countries that are significant producers~~ of ~~crude~~their ~~oil~~respective ~~(OPEC+);~~assets, ~~(iv)~~which ~~governmental~~include ~~regulation;~~related (vgoodwill) ~~armed~~depend ~~conflict~~to ora ~~political~~large ~~instability~~degree inon prevailing crude oil, ~~and~~NGL, ~~natural gas producing countries; (vi) the foreign supply of~~ and ~~demand for crude oil and~~ natural gas; ~~(vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and~~ prices ~~of alternative fuel sources~~. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.” In addition, wide fluctuations in commodity prices can impact the accuracy of assumptions used in our budgeting process.

Prices for crude oil, NGL, and natural gas are subject to large fluctuations in response to relatively minor changes in the supply of and demand for crude oil, NGL, and natural gas, uncertainties within the market and a variety of other factors beyond our control. These factors include, among other things (i) weather conditions and events such as hurricanes in the U.S.; (ii) domestic and global economic conditions; (iii) the activities of the OPEC and other countries that are significant producers of crude oil (OPEC+); (iv) governmental regulation; (v) armed conflict or political instability in crude oil and natural gas producing countries; (vi) the foreign supply of and demand for crude oil and natural gas; (vii) the price of foreign imports; (viii) the proximity and availability of storage and transportation infrastructure and processing and treating facilities; and (ix) the availability and prices of alternative fuel sources. We use hedging arrangements to partially mitigate our exposure to commodity prices, but these arrangements also are subject to inherent risks. Please read “—Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.” In addition, wide fluctuations in commodity prices can impact the accuracy of assumptions used in our budgeting process.

If commodity prices fall substantially or remain low for a sustained period and we are not sufficiently protected through hedging arrangements, we may be unable to realize a profit from these businesses and would operate at a loss.

Sharp declines in the prices of crude oil, NGL, or natural gas, or a prolonged unfavorable price environment, may result in a commensurate reduction in our revenues, income, and cash flows from our businesses that produce, process, or purchase and sell crude oil, NGL, or natural gas, and could have a material adverse effect on the carrying value (which includes assigned goodwill) of our CO2 business segment’s proved reserves, and to a lesser extent, certain assets in certain midstream businesses within our Natural Gas Pipelines business segment, and certain assets within our Products Pipelines business segment.

For more information about our energy and commodity market risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk.”

Commodity transportation and storage activities involve numerous risks that may result in accidents or otherwise adversely affect our operations.

There are a variety of hazards and operating risks inherent to the transportation and storage of the products we handle, such as leaks; releases; the breakdown, underperformance or failure of equipment, facilities, information systems, or processes; damage to our pipelines caused by third-party construction; the compromise of information and control systems; spills at terminals and hubs; spills associated with loading and unloading harmful substances at rail facilities; adverse sea conditions (including storms and rising sea levels) and releases or spills from our shipping vessels or vessels loaded at our marine terminals; operator error; labor disputes/work stoppages; disputes with interconnected facilities and carriers; operational disruptions or apportionment on third-party systems or refineries on which our assets depend; and catastrophic events or natural disasters such as fires, floods, explosions, earthquakes, acts of terrorists and saboteurs, cyber security breaches, and other similar events, many of which are beyond our control. Additional risks to our vessels include capsizing, collision, allision, grounding, and navigation errors.

The occurrence of any of these risks could result in serious injury and loss of human life, significant damage to property and natural resources, environmental pollution, significant reputational damage, impairment or suspension of operations, fines or other regulatory penalties, costs associated with allegations of criminal liability, costs associated with responding to an investigation or enforcement action brought by a governmental agency, and revocation of regulatory approvals or imposition of new requirements, any of which also could result in substantial financial losses, including lost revenue and cash flow to the extent that an incident causes an interruption of service. For pipeline and storage assets located near populated areas, including residential areas, commercial business centers, industrial sites and other public gathering areas, the level of damage resulting from these risks may be greater. In addition, the consequences of any operational incident (including as a result of adverse sea conditions) at one of our marine terminals may be even more significant as a result of the complexities involved in addressing leaks and releases occurring in the ocean or along coastlines and/or the repair of marine terminals.

Our operating results may be adversely affected by unfavorable economic and market conditions.

Unfavorable conditions such as a general slowdown of the global or U.S. economy, uncertainty and volatility in the financial markets, or inflation and rising interest rates, could materially adversely affect our operating results. For example, the

~~global~~Our ~~economic~~operating ~~downturn~~results ~~caused~~may bybe ~~the~~adversely ~~coronavirus pandemic in 2020~~ affected ~~numerous~~by ~~industries,~~unfavorable including the crude oil and gas industry, the steel industry and specific segments and markets in which we operate, resulting in reduced demand and increased price competition for our products and services. Also, economic ~~conditions in the wake of the pandemic included inflationary pressure, which resulted in higher operating expenses~~ and ~~project costs for us, as well as higher interest rates. More recently, we may see increasing~~ market ~~uncertainty and volatility due to possible shifts in U~~conditions.~~S. and foreign trade, economic and other policies following the recent change in U.S. presidential administration.~~

InUnfavorable ~~addition,~~conditions ~~uncertain~~such oras ~~changing~~a ~~economic~~general ~~conditions~~slowdown ~~within~~of ~~one~~the global or ~~more~~U.S. ~~geographic~~economy, ~~regions~~uncertainty ~~may~~and ~~affect~~volatility ~~our~~in ~~operating~~the ~~results~~financial ~~within~~markets, ~~the~~or ~~affected~~inflation ~~regions. Sustained~~and ~~unfavorable~~rising ~~commodity~~interest ~~prices~~rates, ~~volatility~~could inmaterially ~~commodity~~adversely ~~prices~~affect orour ~~changes~~operating inresults. ~~markets~~For ~~for~~example, athe ~~given~~global ~~commodity~~economic ~~might~~downturn ~~also~~caused ~~have~~by athe ~~negative~~coronavirus ~~impact~~pandemic onin ~~many~~2020 ofaffected ~~our~~numerous ~~customers~~industries, ~~which~~including ~~could~~the ~~impair~~crude ~~their~~oil ~~ability~~and togas ~~meet~~industry, ~~their~~the ~~obligations~~steel toindustry, ~~us. See~~and ~~“—Financial~~specific ~~distress~~segments ~~experienced~~and bymarkets ~~our~~in ~~customers~~which orwe ~~other~~operate, ~~counterparties~~resulting ~~could~~in ~~have~~reduced andemand ~~adverse~~and ~~impact~~increased onprice uscompetition infor ~~the~~our ~~event~~products ~~they~~and ~~are~~services. ~~unable~~Also, toeconomic ~~pay~~conditions usin ~~for~~the wake of the ~~products~~pandemic orincluded ~~services~~inflationary wepressure, ~~provide~~which orresulted ~~otherwise~~in ~~fulfill~~higher ~~their~~operating ~~obligations~~expenses toand ~~us.” In~~project ~~addition~~costs for us, ~~decreases~~as inwell ~~the~~as ~~prices~~higher ofinterest ~~crude~~rates. ~~oil~~More recently, ~~NGL~~we ~~and~~may ~~natural~~see ~~gas~~increasing ~~are~~market ~~likely~~uncertainty toand ~~have~~volatility adue ~~negative~~to ~~impact~~shifts onin ~~our~~U.S. ~~operating~~and ~~results~~foreign trade, economic, and ~~cash~~other ~~flow~~policies. See “—~~The~~Changes ~~volatility~~in ofU.S. ~~crude~~trade ~~oil,~~policy ~~NGL~~ and ~~natural~~the ~~gas~~impact ~~prices~~of ~~could~~tariffs ~~adversely~~may ~~affect~~have a material adverse effect on our business and results of operations.”

IfIn ~~economic~~addition, ~~and~~uncertain ~~market~~or changing economic conditions ~~(including~~within one or more geographic regions may affect our operating results within the affected regions. Sustained unfavorable commodity prices, volatility in commodity prices or changes in markets) ~~globally~~for a given commodity might also have a negative impact on many of our customers, inwhich ~~the~~could Uimpair their ability to meet their obligations to us.S. See “—Financial distress experienced by our customers or other counterparties could have an adverse impact on us in ~~other~~the ~~key~~event ~~markets~~they ~~become~~are ~~more~~unable ~~volatile~~to pay us for the products or ~~deteriorate,~~services we ~~may~~provide ~~experience~~or ~~material~~otherwise ~~impacts~~fulfill ontheir ~~our~~obligations ~~business~~to us.” In addition, ~~financial~~decreases ~~condition~~in the prices of crude oil, NGL, and natural gas are likely to have a negative impact on our operating results and cash flow. See “—The volatility of ~~operations~~crude oil, NGL, and natural gas prices could adversely affect our business.”

If economic and market conditions (including volatility in commodity markets) globally, in the U.S., or in other key markets become more volatile or deteriorate, we may experience material impacts on our business, financial condition, and results of operations.

Financial distress experienced by our customers or other counterparties could have an adverse impact on us in the event they are unable to pay us for the products or services we provide or otherwise fulfill their obligations to us.

We are exposed to the risk of loss in the event of nonperformance by our customers or other counterparties, such as hedging counterparties, joint venture partners and suppliers. Many of our counterparties finance their activities through cash flow from operations or debt or equity financing, and some of them may be highly leveraged and unable to access additional capital to sustain their operations in the future. Our counterparties are subject to their own operating, market, financial, and regulatory risks, and some have experienced, are experiencing, or may experience in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. Further, the security we are able to obtain from such customers may be limited, including by FERC regulation. While certain of our customers are subsidiaries of an entity that has an investment grade credit rating, in many cases the parent entity has not guaranteed the obligations of the subsidiary and, therefore, the parent’s credit ratings may have no bearing on such customers’ ability to pay us for the services we provide or otherwise fulfill their obligations to us.

Furthermore, financially distressed customers might be forced to reduce or curtail their future use of our products and services, which also could have a material adverse effect on our results of operations, financial condition, and cash flows.

We cannot provide any assurance that such customers and key counterparties will not become financially distressed or that such financially distressed customers or counterparties will not default on their obligations to us or file for bankruptcy protection. If one or more customers or counterparties files for bankruptcy protection, we likely would be unable to collect all, or even a significant portion of, amounts they owe to us. Similarly, our contracts with such customers may be renegotiated at lower rates or terminated altogether. Significant customer and other counterparty defaults and bankruptcy filings could have a material adverse effect on our business, financial position, results of operations, or cash flows.

We are subject to reputational risks and risks relating to public opinion.

Our business, operations, or financial condition generally may be negatively impacted as a result of negative public opinion towards our industry sector, the products we handle, or us specifically. Public opinion may be influenced by negative portrayals of the energy industry as well as opposition to development projects. In addition, events specific to us could result in the deterioration of our reputation with key stakeholders.

We believe that reputational risk cannot be managed in isolation from other forms of risk and that credit, market, operational, insurance, regulatory, and legal risks, among others, must all be managed effectively to safeguard our reputation. Our reputation and public opinion could also be impacted by the actions and activities of other companies operating in the energy industry, particularly other energy infrastructure providers, over which we have no control. In particular, our reputation could be impacted by negative publicity related to pipeline incidents or unpopular expansion projects and due to opposition to development of hydrocarbons and energy infrastructure, particularly projects involving resources that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation and use of hydrocarbons generally) could include increased

energy industry, particularly other energy infrastructure providers, over which we have no control. In particular, our reputation could be impacted by negative publicity related to pipeline incidents or unpopular expansion projects and due to opposition to development of hydrocarbons and energy infrastructure, particularly projects involving resources that are considered to increase GHG emissions and contribute to climate change. Negative impacts from a compromised reputation or changes in public opinion (including with respect to the production, transportation, and use of hydrocarbons generally) could include increased regulatory oversight and costs, difficulty obtaining rights-of-way and delays in obtaining, or challenges to, regulatory approvals with respect to growth projects, blockades, project cancellations, difficulty securing financing, revenue loss, reduction in customer base, and decreased value of our securities and our business. In the past, governmental agencies have responded to environmental justice concerns by imposing greater scrutiny in the permit approval process and enforcement actions that could exacerbate the negative reputational impacts, and they may do so in the future.

Our use of hedging arrangements does not eliminate our exposure to commodity price risks and could result in financial losses or volatility in our income.

We engage in hedging arrangements to reduce our direct exposure to fluctuations in the prices of crude oil, natural gas, and NGL, including differentials between regional markets. These hedging arrangements expose us to risk of financial loss in some circumstances, including when production is less than expected, when the counterparty to the hedging contract defaults on its contract obligations, or when there is a change in the expected differential between the underlying price in the hedging agreement and the actual price received. In addition, these hedging arrangements may limit the benefit we would otherwise receive from increases in prices for crude oil, natural gas, and NGL. Furthermore, our hedging arrangements cannot hedge against any decrease in the volumes of products we handle. See “—Our businesses are dependent on the supply of and demand for the products we handle.”

The markets for instruments we use to hedge our commodity price exposure generally reflect then-prevailing conditions in the underlying commodity markets. As our existing hedges expire, we will seek to replace them. To the extent then-existing underlying market conditions are unfavorable, new hedging arrangements available to us will reflect such unfavorable conditions, limiting our ability to hedge our exposure to commodity prices on terms that are economically favorable to us.

When we engage in hedging transactions (for example, to mitigate our exposure to fluctuations in commodity prices or currency exchange rates or to balance our exposure to fixed and variable interest rates) that we believe are effective economically, these transactions may not be considered effective for accounting purposes. Accordingly, our consolidated financial statements may reflect volatility due to these hedges, even when there is no underlying economic impact at the dates of those consolidated financial statements. In addition, it may not be possible for us to engage in hedging transactions that completely eliminate our exposure to commodity prices; therefore, our consolidated financial statements may reflect a gain or loss arising from an exposure to commodity prices for which we are unable to enter into a completely effective hedge. For more information about our hedging activities, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk” and Note 13 “Risk Management” to our consolidated financial statements.

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.

Our business is dependent upon our operational systems to process a large amount of data and complex transactions. Some of the operational systems we use are owned or operated by independent third-party vendors. The various uses of these systems, networks, and services include, but are not limited to, controlling our pipelines and terminals with industrial control systems, collecting and storing information and data, processing transactions, and handling other processes necessary to manage our business.

In accordance with government mandates, we have implemented and maintain a cybersecurity program—both internal and incorporating industry expertise—designed to protect our IT, OT, and data systems from attacks, however, we can provide no assurance that our cybersecurity program will be completely effective. We have experienced increases in the number of attempts by external parties to access our networks or our company data without authorization. While we have taken additional steps to secure our networks and systems to specifically respond to new and elevated risks associated with remote work, we may nevertheless be more vulnerable to a successful cyber-attack or information security incident when significant numbers of our employees are working remotely. The risk of a disruption or breach of our operational systems, or the compromise of the data processed in connection with our operations, has increased as attempted attacks, including acts of terrorism or cyber sabotage, which may be escalated during periods of heightened geopolitical tensions, have advanced in sophistication and number around the world.

If any of our systems are damaged, fail to function properly, or otherwise become unavailable, we may incur substantial costs to repair or replace them. We may also experience loss or corruption of critical data and interruptions or delays in our ability to perform critical functions, which could adversely affect our business and results of operations. A significant failure, compromise, breach or interruption in our systems, which may result from problems such as ransomware, malware, computer viruses, hacking attempts or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop,

compromise, breach, or interruption in our systems, which may result from problems such as ransomware, malware, computer viruses, hacking attempts, or third-party error or malfeasance, could result in a disruption of our operations, customer dissatisfaction, damage to our reputation and a loss of customers or revenues. Efforts by us and our vendors to develop, implement and maintain security measures, including malware and anti-virus software and controls, may not be successful in preventing these events, and any network and information systems-related events could require us to expend significant remedial resources. In the future, we may be required to expend significant additional resources to continue to enhance our information security measures, to comply with regulations, to develop and implement government-mandated plans, and/or to investigate and remediate information security vulnerabilities.

Attacks, including acts of terrorism or cyber sabotage, or the threat of such attacks, may adversely affect our business or reputation.

The U.S. government has issued public warnings indicating that pipelines and other infrastructure assets might be specific targets of terrorist organizations or “cyber sabotage” events. Potential targets include our pipeline systems, terminals, processing plants, databases, or operating systems. Risk of these attacks may escalate during periods of heightened geopolitical tensions. The occurrence of an attack could cause a substantial decrease in revenues and cash flows, increased costs to respond or other financial loss, significant reporting requirements, damage to our reputation, increased regulation or litigation, or inaccurate information reported from our operations. In the event of such an incident, we may need to retain cybersecurity experts to assist us in stopping, diagnosing, and recovering from the attack. There is no assurance that adequate cyber sabotage and terrorism insurance will be available at rates we believe are reasonable in the near future. The potential for an attack may subject our operations to increased risks and costs, and, depending on their ultimate magnitude, have a material adverse effect on our business, results of operations, financial condition, and/or business reputation.

Development of new technologies could create additional risk, or we may not have sufficient resources to manage our technology.

Custom or new technology (including potential generative artificial intelligence) that is heavily relied upon by us or our counterparties may not be maintained and updated appropriately due to resource restraints, or other factors, which could cause technology failures or give rise to additional operational or security risks. Generative artificial intelligence or other new technology could also create additional regulatory scrutiny and generate uncertainty around intellectual property ownership and/or licensing or use. Technology (including artificial intelligence) is also subject to intentional misuse (by criminals, terrorists, or other bad actors). Technology failures or incidents of misuse could result in significant adverse effects on our operations, results of operations, financial condition, and cash flows.

The acquisition of additional businesses and assets is part of our growth strategy. We may experience difficulties completing acquisitions or integrating new businesses and properties, and we may be unable to achieve the benefits we expect from any future acquisitions.

Part of our business strategy includes acquiring additional businesses and assets. We cannot provide any assurance that we will be able to find complementary acquisition targets or complete such acquisitions, or achieve the desired results from any acquisitions we do complete. Any acquired businesses or assets will be subject to many of the same risks as our existing businesses and may not achieve the levels of performance that we anticipate.

We may not realize anticipated operating advantages and cost savings. Integration of acquired businesses or assets involves a number of risks, including (i) the loss of key customers of the acquired business; (ii) demands on management related to the increase in our size; (iii) the diversion of management’s attention from the management of daily operations; (iv) difficulties in implementing or unanticipated costs of accounting, budgeting, reporting, internal controls, and other systems; and (v) difficulties in the retention and assimilation of necessary employees.

Difficulties in integration may be magnified if we make multiple acquisitions over a relatively short period of time. Because of difficulties in combining and expanding operations, we may not be able to achieve the cost savings and other size-related benefits that we hoped to achieve after these acquisitions, which would harm our financial condition and results of operations.

Hurricanes, earthquakes, flooding, and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition, and results of operations.

Some of our pipelines, terminals, and other assets are located in, and our shipping vessels operate in, areas that are susceptible to hurricanes, earthquakes, flooding, and other natural disasters or could be impacted by subsidence and coastal erosion. These natural disasters could potentially damage or destroy our assets and disrupt the supply of the products we transport. Many climate models indicate that global warming is likely to result in rising sea levels, increased frequency and severity of weather events such as winter storms, hurricanes and tropical storms, extreme precipitation and flooding. These

erosion. These natural disasters could potentially damage or destroy our assets and disrupt the supply of the products we transport. Many climate models indicate that global warming is likely to result in rising sea levels, increased frequency and severity of weather events such as winter storms, hurricanes and tropical storms, extreme precipitation, and flooding. These climate-related changes could result in damage to our physical assets, especially operations located in low-lying areas near coasts and river banks, and facilities situated in hurricane-prone and rain-susceptible regions. Natural disasters can similarly affect the facilities of our customers. The timing, severity and location of these climate change impacts are not known with certainty, and these impacts are expected to manifest themselves over varying time horizons.

Our insurance policies do not cover all losses, costs or liabilities that we may experience, and insurance companies that currently insure companies in the energy industry may cease to do so or substantially increase premiums.

Our insurance program may not cover all operational risks and costs and may not provide sufficient coverage in the event of a claim. We do not maintain insurance coverage against all potential losses and could suffer losses for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. Losses in excess of our insurance coverage could have a material adverse effect on our business, financial condition, and results of operations.

Changes in the insurance markets subsequent to certain hurricanes and other natural disasters have made it more difficult and more expensive to obtain certain types of coverage. The occurrence of an event that is not fully covered by insurance, or failure by one or more of our insurers to honor its coverage commitments for an insured event, could cause us to incur significant losses. Insurance companies may reduce or eliminate the insurance capacity they are willing to offer or may demand significantly higher premiums or deductibles to cover our assets. If significant changes in the number or financial solvency of insurance underwriters for the energy industry occur, we may be unable to obtain and maintain adequate insurance at a reasonable cost. The unavailability of adequate insurance coverage to cover events in which we suffer significant losses could have a material adverse effect on our business, financial condition, and results of operations.

Substantially all of the land on which our pipelines are located is owned by third parties. If we are unable to procure and maintain access to land owned by third parties, our revenue and operating costs, and our ability to complete construction projects, could be adversely affected.

We must obtain and maintain the rights to construct and operate pipelines on other owners’ land, including private landowners, railroads, public utilities, and others. While our interstate natural gas pipelines in the U.S. have federal eminent domain authority, the availability of eminent domain authority for our other pipelines varies from state to state depending upon the type of pipeline—petroleum liquids, natural gas, CO2, or crude oil—and the laws of the particular state. In addition, we must compensate landowners for the use of their property and, in eminent domain actions, such compensation may be determined by a court. If we are unable to obtain rights-of-way on acceptable terms, our ability to complete construction projects on time, on budget, or at all, could be adversely affected. In addition, we are subject to the possibility of increased costs under our rights-of-way or rental agreements with landowners, primarily through renewals of expiring agreements and rental increases. If we were to lose these rights, our operations could be disrupted or we could be required to relocate the affected pipelines, which could cause a substantial decrease in our revenues and cash flows and a substantial increase in our costs.

The future success of our oil and gas development and production operations depends in part upon our ability to develop additional oil and gas reserves that are economically recoverable, which involves risks that may result in a total loss of investment.

The rate of production from oil and natural gas properties declines as reserves are depleted. Without successful development activities, the reserves, revenues, and cash flows of the oil and gas producing assets within our CO2 business segment will decline. We may not be able to develop or acquire additional reserves at an acceptable cost or have necessary financing for these activities in the future. Additionally, if we do not realize production volumes greater than, or equal to, our hedged volumes, we may suffer financial losses not offset by physical transactions.

Developing and operating oil and gas properties involves a high degree of business and financial risk that even a combination of experience, knowledge, and careful evaluation may not be able to overcome. Acquisition and development decisions related to oil and gas properties include subjective judgments and assumptions that, while they may be reasonable, are by their nature speculative. It is impossible to predict with certainty the production potential of a particular property or well. Furthermore, the successful completion of a well does not ensure a profitable return on the investment. A variety of geological, operational and market-related factors may substantially delay or prevent completion of any well or otherwise prevent a property or well from being profitable.

Our business requires the retention and recruitment of a skilled executive team and workforce, and difficulties recruiting and retaining executives and other key personnel could impair our ability to develop and implement our business strategy.

Our success depends in part on the performance of and our ability to attract, retain, and effectively manage the succession of a skilled executive team. We depend on our executive officers to develop and execute our business strategy. If we are not successful in retaining our executive officers, or replacing them, our business, financial condition, or results of operations could be adversely affected. We do not maintain key personnel insurance.

In addition, our business requires the retention and recruitment of a skilled workforce, including engineers, technical personnel, and other professionals. We and our affiliates compete with other companies in the energy industry for this skilled workforce. In addition, many of our current employees are retirement eligible and have significant institutional knowledge that must be transferred to other employees. If we are unable to (i) retain current employees; (ii) successfully complete the knowledge transfer; and/or (iii) recruit new employees of comparable knowledge and experience, our business could be negatively impacted. In addition, we could experience increased costs to retain and recruit these professionals.

Risks Related to Financing Our Business

Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.

As of December 31, ~~2024~~2025, we had approximately $31.8 billion of consolidated debt (excluding debt fair value adjustments). Additionally, we and substantially all of our wholly owned U.S. subsidiaries are parties to a cross guarantee agreement under which each party to the agreement unconditionally guarantees the indebtedness of each other party, which means that we are liable for the debt of each of such subsidiaries. This level of consolidated debt and the cross guarantee agreement could have important consequences, such as (i) limiting our ability to obtain additional financing to fund our working capital, capital expenditures, debt service requirements, or potential growth, or for other purposes; (ii) increasing the cost of our future borrowings; (iii) limiting our ability to use operating cash flow in other areas of our business or to pay dividends because we must dedicate a substantial portion of these funds to make payments on our debt; (iv) placing us at a competitive disadvantage compared to competitors with less debt; and (v) increasing our vulnerability to adverse economic and industry conditions.

Our ability to service our consolidated debt, and our ability to meet our consolidated leverage targets, will depend upon, among other things, our future financial and operating performance, which will be affected by prevailing economic conditions and financial, business, regulatory, and other factors, many of which are beyond our control. If our consolidated cash flow is not sufficient to service our consolidated debt, and any future indebtedness that we incur, we will be forced to take actions such as reducing dividends, reducing or delaying our business activities, acquisitions, investments or capital expenditures, selling assets, or seeking additional equity capital. We may also take such actions to reduce our indebtedness if we determine that our earnings (or consolidated EBITDA, as calculated in accordance with our revolving credit facility) may not be sufficient to meet our consolidated leverage targets or to comply with consolidated leverage ratios required under certain of our debt agreements. We may not be able to effect any of these actions on satisfactory terms or at all. For more information about our debt, see Note 8 “Debt” to our consolidated financial statements.

Our business, financial condition and operating results may be affected adversely by adverse changes in the availability, terms, and cost of capital or a reduction in the availability of credit.

We may need to rely on external financing sources, including commercial borrowings and issuances of debt and equity securities, to fund acquisitions, capital projects or refinancing debt maturities. Adverse changes to the availability, terms and cost of capital, interest rates, or our credit ratings (which would have a corresponding impact on the credit ratings of our subsidiaries that are party to the cross guarantee agreement) could cause our cost of doing business to increase by limiting our access to capital, including our ability to refinance maturities of existing indebtedness on similar terms, which could in turn reduce our cash flows, and could limit our ability to pursue acquisition or expansion opportunities. Our credit ratings may be impacted by our leverage, liquidity, credit profile, and potential transactions. Although the ratings from credit agencies are not recommendations to buy, sell, or hold our securities, our credit ratings will generally affect the market value of our and our subsidiaries’ debt securities and the terms available to us for future issuances of debt securities.

Also, disruptions and volatility in the global financial markets may lead to an increase in interest rates or a contraction in credit availability, impacting our ability to finance our operations and strategy on favorable terms. A significant reduction in the availability of credit could materially and adversely affect our business, financial condition, and results of operations.

Our and our customers’ access to capital could be affected by evolving financial institutions’ policies concerning businesses linked to fossil fuels.

Our and our customers’ access to capital could be affected by financial institutions’ evolving policies concerning businesses linked to fossil fuels. Concerns about the potential effects of climate change have caused some to direct their attention towards sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in such companies. Ultimately, this could make it more difficult for our customers to secure funding for exploration and production activities or for us to secure funding for growth projects, and consequently could both indirectly affect demand for our services and directly affect our ability to fund construction or other capital projects.

Our large amount of debt makes us vulnerable to increases in interest rates to the extent we have variable-rate debt and maturing fixed-rate debt.

As of December 31, ~~2024~~2025, we had approximately $31.8 billion of consolidated debt (excluding debt fair value adjustments), including $1.51 billion of senior notes maturing within the next 12 months, and approximately $3.65 billion of debt subject to variable interest rates, either as short-term or long-term variable-rate debt obligations, or as long-term fixed-rate debt effectively converted to variable rates through the use of interest rate swaps. In ~~response~~The ~~to increasing inflation, the~~ U.S. Federal Reserve raised interest rates over the period from March 2022 to July 2023 ~~before~~in ~~beginning~~response ~~rate~~to ~~reductions~~increasing inflation, then reduced rates beginning in September 2024 ~~due~~as toinflation ~~slowing~~slowed ~~inflation~~and the labor market weakened. ~~There~~ Although rate reductions continued through December 2025, there can be no assurance that the U.S. Federal ~~reserve~~Reserve will continue rate reductions, or will not resume rate increases, or regarding the pace at which any such reductions or increases could occur. If and to the extent that interest rates increase, our costs to refinance maturities of existing indebtedness may also increase, as will the amount of cash required to service variable-rate debt, and our earnings and cash flows could be adversely affected.

For more information about our interest rate risk, see Item 7A. “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Our debt instruments may limit our financial flexibility and increase our financing costs.

The instruments governing our debt contain restrictive covenants that may prevent us from engaging in certain transactions that may be beneficial to us. Some of the agreements governing our debt generally require us to comply with various affirmative and negative covenants, including the maintenance of certain financial ratios and restrictions on (i) incurring additional debt; (ii) entering into mergers, consolidations and sales of assets; (iii) granting liens; and (iv) entering into sale-leaseback transactions. The instruments governing any future debt may contain similar or more limiting restrictions. Our ability to respond to changes in business and economic conditions and to obtain additional financing, if needed, may be restricted.

Risks Related to Regulation

The FERC or state public utility commissions, such as the CPUC, may establish pipeline tariff rates that have a negative impact on us. In addition, the FERC, state public utility commissions, or our customers could initiate proceedings or file complaints challenging the tariff rates charged by our pipelines, which could have an adverse impact on us.

The profitability of our regulated pipelines is influenced by fluctuations in costs and our ability to recover any increases in our costs in the rates charged to our shippers. To the extent that our costs increase in an amount greater than what we are permitted by the FERC or state public utility commissions to recover in our rates, or to the extent that there is a lag before we can file for and obtain rate increases, such events can have a negative impact on our operating results.

Our existing rates may also be challenged by complaint or protest. Regulators and shippers on our pipelines have rights to challenge, and have challenged, the rates we charge under certain circumstances prescribed by applicable regulations. Some shippers on our pipelines have filed complaints with the regulators seeking prospective reductions in the tariff rates and, in the case of a protest to a rate filing, seeking substantial refunds for alleged overcharges during the years in question. Further, the FERC has initiated and may continue to initiate investigations to determine whether our interstate natural gas pipeline rates are just and reasonable. ~~Please~~ ~~read Note 17 “Litigation and Environmental” to our consolidated financial statements for a description of material pending challenges to the rates we charge on our pipelines.~~ We are unable to predict the extent to which these proceedings will result in lower transportation rates on our pipelines, and in the case of a protest, refunds for alleged overcharges. Any successful challenge to our rates could materially adversely affect our future earnings, cash flows, and financial condition.

New or amended laws, policies, regulations and oversight requirements, and compliance complexity resulting from disparities in requirements imposed by federal, state, and local authorities, could adversely impact our earnings, cash flows, and operations.

Our assets and operations are subject to extensive and in some cases overlapping regulation and oversight by federal, state, and local authorities. Changes in the policy priorities of federal, state, and local authorities create a dynamic regulatory landscape—where, for example, federal priorities may ease while state and local requirements become more stringent—resulting in compliance complexity and potential cost increases.

Future administrations, court decisions, or state-level initiatives could reverse or tighten standards or result in enhanced requirements, creating uncertainty and volatility in compliance obligations and costs. For example, with respect to our products pipelines, the FERC resets the ceiling level calculation formula every five years, and the five-year review is typically the

~~New~~subject ~~laws,~~of ~~policies,~~litigation ~~regulations~~between liquids pipelines, ~~rulemaking~~their customers, and ~~oversight,~~industry asgroups. ~~well~~Changes asin ~~changes~~the toindex ~~those~~formula ~~currently~~used into ~~effect,~~calculate ~~could~~ceiling ~~adversely~~levels would impact ~~our~~the ~~earnings,~~revenues ~~cash~~we ~~flows~~receive ~~and~~from ~~operations~~FERC-jurisdictional service.

~~Our~~While ~~assets~~policy ~~and~~shifts ~~operations~~under ~~are~~the ~~subject~~current ~~to extensive regulation and oversight by federal, state and local regulatory authorities~~U. ~~Legislative~~S. ~~changes,~~presidential asadministration ~~well~~have asgenerally ~~regulatory~~emphasized ~~actions~~support ~~taken~~for bydomestic ~~these~~energy ~~authorities,~~production and have ~~the~~reduced ~~potential~~certain toenvironmental ~~adversely affect our profitability. Additional~~ regulatory burdens ~~and~~at ~~uncertainties will be created if and to~~ the ~~extent~~federal ~~that~~level, ~~more~~these ~~stringent~~changes ~~energy~~introduce ~~and~~their ~~environmental~~own ~~and pipeline safety policies are enacted~~uncertainties. In ~~recent~~Deregulatory ~~years,~~actions weat ~~saw an increase in~~ the ~~efforts~~federal oflevel, ~~regulatory~~such ~~authorities~~as ~~to issue new regulations and guidance and to interpret existing laws and regulations in ways that promoted~~ the ~~use~~EPA’s ofrescission ~~renewable energy sources and further protection~~ of ~~the~~its ~~environment,~~previous ~~called~~endangerment ~~upon~~finding ~~companies~~relating to ~~increase~~GHGs ~~monitoring~~announced ~~and~~on ~~emissions~~February ~~reduction~~12, ~~efforts~~2026, ~~and~~are ~~increased~~likely ~~investigations~~to ~~and~~be ~~enforcement~~subject ~~actions~~to ~~for~~legal ~~potential violations of environmental laws~~challenges. ~~For~~ ~~example~~Also, inas ~~December 2023,~~ the ~~EPA~~U.S. ~~finalized~~federal agovernment ~~rule~~has ~~containing~~taken ~~standards~~some ofsteps ~~performance~~to ~~for~~relax ~~methane~~regulatory ~~and~~requirements, ~~volatile~~some ~~organic~~states ~~compound~~have ~~emissions~~adopted ~~from~~new ~~crude~~laws ~~oil~~ and ~~natural~~regulations. ~~gas~~Many ~~sources,~~states ~~including~~have ~~the~~adopted ~~production,~~policies ~~processing,~~related ~~and~~to ~~transmission~~GHG ~~and~~emission ~~storage~~reduction ~~segments~~targets. In ~~addition,~~These aand ~~certain~~other ~~degree~~expansion of ~~regulatory~~U.S. ~~uncertainty~~state islaws ~~created~~and byregulations ~~the~~with ~~recent~~potentially ~~change~~divergent inobligations ~~U.S.~~could ~~presidential~~require ~~administrations. It~~us ~~remains~~to ~~unclear~~incur ~~specifically~~additional ~~what~~expenditures ~~the~~to ~~new~~comply ~~administration~~with ~~may~~disparate doobligations ~~with~~related ~~respect~~ to ~~future~~GHG ~~policies~~emission ~~and~~requirements, ~~regulations~~or ~~that~~other ~~may~~reporting ~~affect~~or ussafety regulations.

~~These~~For ~~types~~example, ofthe ~~rules~~EPA finalized methane and ~~others~~volatile ~~that~~organic ~~are~~compound ~~currently~~emissions ~~proposed~~standards in late 2023 and, ifalthough ~~finalized~~EPA priorities have shifted under the current U.S. presidential administration, ~~would~~several ~~affect~~states ~~our~~continue ~~assets~~to pursue aggressive climate and ~~operations~~emissions-reduction ~~indirectly~~programs, ~~such~~which ascould byrequire ~~increasing~~us ~~the~~to ~~costs~~comply ~~associated~~ with obligations that are more stringent than those imposed by the ~~production~~EPA. The State of ~~natural~~California ~~gas~~has ~~and~~enacted ~~liquids~~legislation ~~that~~requiring weclimate-related ~~transport~~disclosures, orand ~~directly,~~the California Air Resources Board (CARB) has begun implementation of such aslegislation, bywhich ~~increasing~~requires ~~significantly~~that ~~our~~certain ~~capital~~companies ~~and~~doing ~~operating~~business in California submit reporting of GHG emissions. Other U.S. states have announced similar proposed regulations. These types of regulations may expose us to significant additional compliance costs. ~~associated~~In ~~with~~addition, ~~impacted~~some ~~equipment~~customers orand ~~subjecting~~other third parties request disclosures from us related to ~~the~~their ~~potential~~own ~~for~~reporting ~~regulatory~~obligations. ~~penalties~~At ~~associated~~this ~~with~~time, we cannot predict the ~~inability~~costs toof ~~comply~~compliance with, ~~the~~or other potential adverse impacts resulting from, these or similar future rules inthat ~~the~~may ~~timeframe~~be ~~allotted~~adopted.

~~The~~These ~~EPA’s~~and ~~final~~other ~~rule~~initiatives ~~known~~of asregulatory ~~the~~authorities ~~“Good~~may ~~Neighbor~~affect ~~Plan”~~our ~~(the~~assets ~~Plan)~~and ~~was~~operations ~~predicated~~directly ~~on the EPA’s disapproval of numerous state implementation plans,~~ or ~~SIPs~~indirectly, ~~submitted~~such ~~under~~as ~~the~~by ~~interstate~~preventing ~~transport~~or ~~(Good~~delaying ~~Neighbor) provisions of~~ the ~~Clean~~exploration ~~Air Act~~ for ~~the 2015 Ozone NAAQS~~ and ~~became~~production ~~effective on August 4, 2023. The Plan imposes prescriptive emission standards for several sectors, including new and existing reciprocating internal combustion engines~~ of ~~a certain size used in pipeline transportation of~~ natural gas~~. The~~ ~~Plan’s~~and ~~emission~~liquids ~~standards~~that ~~would~~we ~~require~~transport ~~installation~~or ofexpanding ~~more~~regulation ~~stringent air pollution controls on hundreds~~ of existing ~~internal~~infrastructure ~~combustion~~or ~~engines~~new ~~used~~sources bythat ~~our~~are ~~Natural~~not ~~Gas~~currently ~~Pipelines~~regulated. ~~business segment by May 1~~Moreover, ~~2026,~~political ~~except for any compliance schedule extensions granted by the EPA, which would need to be supported by us~~ and ~~approved by the EPA on an engine-by-engine basis. Multiple~~ legal challenges have been filed, including by states seeking review of SIP disapprovals (12 of which have received stays pending review) and by us. On June 27, 2024, the Supreme Court granted a temporary stay of the Plan until a disposition of a review of the Plan by the U.S. Court of Appeals for the D.C. Circuit and any appeal of that decision to ~~the~~existing ~~Supreme Court. See Note 17~~rules, ~~“Litigation~~combined and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. On February 6, 2025, the EPA filed a motion asking the U.S. Court of Appeals for the D.C. Circuit to hold the cases in abeyance for 60 days to allow the Trump Administration time to familiarize themselves with ~~the~~evolving ~~Plan,~~public ~~receive~~expectations ~~briefing~~around ~~from~~environmental ~~the EPA about the cases and the Plan~~stewardship, ~~and~~add ~~decide what action on the Plan, if any, is necessary. If the Plan were~~ to ~~remain in effect in its current form (including full compliance by a revised compliance deadline accounting for~~ the ~~stays,~~risk ~~and assuming failure of all pending challenges to SIP disapprovals and no successful challenge to the Plan), we currently estimate~~ that ~~the~~new ~~Plan~~or ~~would~~reinstated ~~have~~regulations acould ~~material~~materially ~~adverse~~ impact onour usoperations. See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Capital Resources—Capital Expenditures—Impact of Regulation.” We are unable to predict whether pending legal challenges will ultimately result in changes to the Plan or how those changes, if any, would impact us.

~~These~~Regulation affects almost every part of our business. In addition to environmental and ~~other~~pipeline ~~initiatives~~safety matters, we are subject to regulations extending to such matters as (i) federal, state, local and foreign taxation; (ii) rates, operating terms, and conditions of ~~regulatory~~service ~~authorities~~we may ~~affect~~offer to our ~~assets~~customers; (iii) the types of services and ~~operations~~contracts ~~directly~~we ormay ~~indirectly~~offer to our customers; (iv) permitting, certification, and construction of new facilities; (v) the costs of raw materials, such as steel, which may be affected by ~~preventing~~tariffs or(such ~~delaying~~as those discussed under “—Changes in U.S. trade policy and the ~~exploration~~impact ~~for~~of tariffs may have a material adverse effect on our business and ~~production~~results of ~~natural~~operations.”) ~~gas~~or otherwise; (vi) the integrity, safety and ~~liquids~~security ~~that~~(including weagainst ~~transport~~cyber-attacks) orof ~~expanding~~facilities ~~regulation~~and operations; (vii) the acquisition of ~~existing~~other ~~infrastructure~~businesses; (viii) the acquisition, extension, disposition, or ~~new~~abandonment ~~sources~~of ~~that~~services ~~are~~or ~~not~~facilities; ~~currently~~(ix) ~~regulated~~reporting and information posting requirements; (x) the maintenance of accounts and records; and (xi) relationships with affiliated companies involved in various aspects of the natural gas and energy businesses.

~~Regulation~~If ~~affects almost every part of our business. In addition to environmental and pipeline safety matters,~~ we ~~are~~fail ~~subject~~ to ~~regulations~~comply ~~extending~~with toany ~~such~~applicable ~~matters~~laws asor ~~(i) federal~~regulations, ~~state, local~~ and ~~foreign~~orders ~~taxation;~~of ~~(ii)~~such ~~rates~~regulatory ~~(which include reservation~~authorities, ~~commodity,~~we ~~surcharges,~~could ~~fuel~~be ~~and~~subject ~~gas~~to ~~lost~~substantial penalties and ~~unaccounted~~fines ~~for), operating terms~~ and ~~conditions~~potential ofloss ~~service; (iii) the types~~ of ~~services~~government ~~we may offer to our customers; (iv) the~~ contracts. ~~for~~New ~~service~~or ~~entered~~amended ~~into~~laws ~~with~~or ~~our~~regulations, ~~customers;~~or ~~(v)~~different ~~the~~interpretations ~~certification and construction~~ of ~~new~~existing ~~facilities;~~laws ~~(vi)~~or ~~the costs of raw materials~~regulations, ~~such~~including aspolicy ~~steel~~changes, ~~which~~applicable ~~may~~to beour ~~affected~~business bycould ~~tariffs~~have ~~(such~~a asmaterial ~~those~~adverse ~~proposed~~impact byon ~~the~~our ~~new~~earnings, ~~U.S.~~cash ~~presidential~~flow, ~~administration)~~financial ~~or otherwise; (vii) the integrity~~condition, ~~safety~~ and ~~security~~results ~~(including against cyber-attacks)~~ of ~~facilities and~~ operations;. ~~(viii)~~For ~~the~~more ~~acquisition of other businesses; (ix) the acquisition~~information, ~~extension,~~see ~~disposition~~Items or1 ~~abandonment of services or facilities; (x) reporting~~ and ~~information~~2. ~~posting~~“Business ~~requirements; (xi) the maintenance of accounts~~ and ~~records;~~Properties—Narrative ~~and~~Description ~~(xii) relationships with affiliated companies involved in various aspects~~ of ~~the~~Business—Industry ~~natural gas and energy businesses~~Regulation.”

~~If we fail to comply with any applicable statutes~~Environmental, ~~rules~~health, ~~regulations,~~ and ~~orders~~safety oflaws ~~such~~and ~~regulatory~~regulations ~~authorities, we~~ could beexpose ~~subject~~us to ~~substantial~~significant ~~penalties~~costs and ~~fines and potential loss of government contracts~~liabilities. ~~New laws or regulations, or different~~

Our operations are subject to extensive federal, state, and local laws, regulations, and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources, and human health and safety. Such laws and regulations affect many aspects of our past, present, and future operations, and generally require us to obtain and comply with various environmental registrations, licenses, permits, inspections, and other approvals. It is possible that costs associated with complying with the aforementioned laws will change depending on the emphasis regulatory authorities are placing on protection of the environment. Liability under such laws and regulations may be incurred without regard to fault under CERCLA, the Resource Conservation and Recovery Act, the Federal Clean Water Act, the Oil Pollution Act, or analogous state laws, as a result of the presence or release of hydrocarbons or hazardous substances into or through the environment, and these laws may require response actions and remediation and may impose liability for natural resource and other damages. Private parties, including the owners of properties through which our pipelines pass, also may have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with such laws and regulations or for personal injury or property damage. Our insurance may not cover all environmental risks and costs and/or may not provide sufficient coverage in the event an environmental claim is made against us.

~~interpretations~~Failure ofto ~~existing~~comply with these laws orand regulations, including ~~unexpected~~required ~~policy~~permits ~~changes~~and other approvals, ~~applicable~~also may expose us to ~~our~~civil, ~~income~~criminal, ~~operations~~and administrative fines, ~~assets~~penalties, and/or ~~another~~interruptions ~~aspect~~in ofour operations that could harm our business, ~~could~~financial ~~have~~position, results of operations, and prospects. For example, if a ~~material~~leak, ~~adverse~~release, ~~impact~~or onspill of liquid petroleum products, chemicals, or hazardous substances occurs at or from our ~~earnings~~pipelines, ~~cash~~shipping ~~flow~~vessels or storage, ~~financial~~or ~~condition~~other facilities, we may experience significant operational disruptions, and ~~results~~we ofmay ~~operations. For~~have ~~more~~to ~~information~~pay a significant amount to clean up or otherwise respond to the leak, ~~see~~release ~~Items~~or 1spill, ~~and~~pay 2.government ~~“Business~~penalties, ~~and~~address ~~Properties—Narrative~~natural ~~Description~~resource damage, compensate for human exposure or property damage, install costly pollution control equipment, or undertake a combination of ~~Business—Industry~~these ~~Regulation~~and other measures.”

~~Environmental~~We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities and contain hydrocarbons or hazardous substances. While we believe we have utilized operating, ~~health~~handling, and ~~safety~~disposal practices that were consistent with industry practices at the time, hydrocarbons or hazardous substances may have been released at or from properties and equipment owned, operated, or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling, and disposal of hydrocarbons or hazardous substances were not under our control. These properties and any hazardous substances released and wastes disposed at or from them may be subject to U.S. laws such as CERCLA, which impose joint and ~~regulations~~several liability without regard to fault or the legality of the original conduct. Under such laws, we could ~~expose~~be usrequired to ~~significant~~remove ~~costs~~previously disposed wastes, remediate property contamination, or both, including contamination caused by prior owners or operators. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and ~~liabilities~~gas facilities that are currently exempt as being exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

~~Our~~Environmental ~~operations are subject to extensive federal, state~~ and ~~local laws, regulations and potential liabilities arising under or relating to the protection or preservation of the environment, natural resources and human~~ health and safety~~. Such~~ laws and regulations ~~affect~~are ~~many~~subject ~~aspects~~to ofchange. ~~our~~The ~~past,~~long-term ~~present~~trend ~~and~~in ~~future~~environmental ~~operations,~~regulation ~~and~~has ~~generally~~been ~~require us~~ to ~~obtain~~place ~~and~~more ~~comply~~restrictions ~~with various environmental registrations, licenses, permits, inspections~~ and ~~other~~limitations ~~approvals. It~~on isactivities ~~possible~~ that ~~costs~~may ~~associated~~be ~~with~~perceived ~~complying~~to ~~with~~affect the ~~aforementioned laws will change depending on the emphasis regulatory authorities are placing on protection of the~~ environment, ~~and~~wildlife, ~~environmental~~natural ~~justice~~resources, ~~considerations. Liability under such laws~~ and ~~regulations~~human ~~may~~health, beincluding ~~incurred~~ without ~~regard~~limitation, tothe ~~fault~~exploration, ~~under~~development, ~~CERCLA~~storage, ~~the~~and ~~Resource~~transportation ~~Conservation~~of oil and ~~Recovery~~gas. ~~Act~~For example, the Federal Clean ~~Water~~Air Act, ~~the~~and ~~Oil~~other ~~Pollution~~similar ~~Act,~~federal orand ~~analogous~~ state laws, asand aregulations ~~result~~are ofsubject ~~the~~to ~~presence or release of hydrocarbons or hazardous substances into or through the environment~~amendment, ~~and~~which ~~these~~could ~~laws~~result ~~may~~in ~~require~~more ~~response~~stringent ~~actions~~emission ~~and~~control ~~remediation~~requirements ~~and~~obligating ~~may~~us ~~impose~~to ~~liability~~make ~~for~~significant ~~natural~~capital ~~resource~~expenditures ~~and~~at ~~other~~our ~~damages~~facilities. ~~Private~~ ~~parties,~~Several ~~including~~state ~~the~~and ~~owners~~federal ofagencies ~~properties~~have ~~through~~also ~~which~~increased ~~our~~their ~~pipelines~~daily ~~pass,~~and ~~also~~maximum ~~may~~penalty ~~have~~amounts ~~the~~in ~~right~~recent toyears. ~~pursue~~There ~~legal~~can ~~actions~~be tono ~~enforce~~assurance ~~compliance~~ as ~~well as~~ to ~~seek~~the ~~damages~~amount ~~for~~or ~~non-compliance~~timing ~~with~~of ~~such~~future ~~laws~~expenditures ~~and regulations or~~ for ~~personal~~environmental ~~injury~~compliance or ~~property~~remediation, ~~damage. Our insurance may not cover all environmental risks~~ and ~~costs~~actual ~~and/or~~future expenditures may ~~not~~be ~~provide~~different ~~sufficient~~from ~~coverage in~~ the ~~event~~amounts anwe ~~environmental~~currently ~~claim is made against us~~anticipate.

~~Failure~~New toor ~~comply~~revised ~~with these laws and~~ regulations, ~~including~~that ~~required~~result ~~permits~~in ~~and~~increased ~~other~~compliance ~~approvals,~~costs ~~also may expose us to civil, criminal and administrative fines, penalties and/~~or ~~interruptions~~additional inoperating ~~our operations that could harm our business~~restrictions, ~~financial~~particularly ~~position, results of operations and prospects. For example,~~ if athose ~~leak,~~costs ~~release~~are ornot ~~spill~~fully ofrecoverable ~~liquid petroleum products, chemicals or hazardous substances occurs at or~~ from our ~~pipelines~~customers, ~~shipping~~as ~~vessels~~well oras ~~storage~~increased orpenalty ~~other~~amounts ~~facilities,~~for weinadvertent ~~may experience significant operational disruptions~~non-compliance, ~~and~~could ~~we may~~ have ~~to pay~~ a ~~significant~~material ~~amount~~adverse toeffect ~~clean~~on upour ~~or otherwise respond to the leak~~business, ~~release~~financial ~~or spill~~position, ~~pay~~results ~~government~~of ~~penalties~~operations, ~~address~~and ~~natural~~prospects. ~~resource~~For ~~damage,~~more ~~compensate for human exposure or property damage~~information, ~~install~~see ~~costly~~Items ~~pollution~~1 ~~control~~and ~~equipment~~2. or“Business ~~undertake~~and aProperties—Narrative ~~combination~~Description of ~~these~~Business—Environmental ~~and other measures~~Matters.”

We own and/or operate numerous properties and equipment that have been used for many years in connection with our business activities and contain hydrocarbons or hazardous substances. While we believe we have utilized operating, handling and disposal practices that were consistent with industry practices at the time, hydrocarbons or hazardous substances may have been released at or from properties and equipment owned, operated or used by us or our predecessors, or at or from properties where our or our predecessors’ wastes have been taken for disposal. In addition, many of these properties have been owned and/or operated by third parties whose management, handling and disposal of hydrocarbons or hazardous substances were not under our control. These properties and any hazardous substances released and wastes disposed at or from them may be subject to U.S. laws such as CERCLA, which impose joint and several liability without regard to fault or the legality of the original conduct. Under such laws, we could be required to remove previously disposed wastes, remediate property contamination or both, including contamination caused by prior owners or operators. Furthermore, it is possible that some wastes that are currently classified as non-hazardous, which could include wastes currently generated during our pipeline or liquids or bulk terminal operations or wastes from oil and gas facilities that are currently exempt as being exploration and production waste, may in the future be designated as hazardous wastes. Hazardous wastes are subject to more rigorous and costly handling and disposal requirements than non-hazardous wastes. Such changes in the regulations may result in additional capital expenditures or operating expenses for us.

Environmental and health and safety laws and regulations are subject to change. The long-term trend in environmental regulation has been to place more restrictions and limitations on activities that may be perceived to affect the environment, wildlife, natural resources and human health, including without limitation, the exploration, development, storage and transportation of oil and gas. For example, the Federal Clean Air Act and other similar federal and state laws and regulations are subject to amendment, which could result in more stringent emission control requirements obligating us to make significant capital expenditures at our facilities. Several state and federal agencies have also increased their daily and maximum penalty amounts in recent years. There can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate.

New or revised regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, as well as increased penalty amounts for inadvertent non-compliance, could have a material adverse effect on our business, financial position, results of operations and prospects. For more information, see Items 1 and 2. “Business and Properties—Narrative Description of Business—Environmental Matters.”

Increased regulatory requirements relating to the safety and integrity of our pipelines may require us to incur significant capital and operating expenses.

We are subject to extensive laws and regulations related to pipeline safety and integrity at the federal and state levels. There are, for example, regulations issued by PHMSA for pipeline operators in the areas of design, operations, maintenance, integrity management, qualification and training, emergency response, control room management, and public awareness. We expect the costs of compliance with these regulations, including integrity management rules, will continue to be substantial. The majority of compliance costs relate to ~~pipeline integrity management regulations, which include~~ enhanced assessment and repair requirements in HCAs, ~~and~~(pursuant ~~compliance~~to ~~with~~PHMSA’s ~~recently~~integrity ~~issued~~management regulations) ~~which impose additional assessment~~ and ~~repair criteria for gas pipelines in~~ MCAs. Technological advances in in-line inspection tools, identification of additional threats to a pipeline’s integrity, and changes to the amount of pipeline determined to be located in HCAs or MCAs can have a significant impact on integrity testing and repair costs. Repairs or upgrades deemed necessary to address results of integrity assessments and other testing and/or ensure the continued safe and reliable operation of our pipelines and pipeline facilities could cause us to incur significant and unanticipated capital and operating expenditures. Such expenditures will vary depending on the number of repairs determined to be necessary as a result of integrity assessments and other testing. We also anticipate incurring substantial costs associated with PHMSA’s requirements for reconfirming the MAOP of certain gas pipelines.

Further, additional laws and regulations that may be enacted in the future or a new interpretation of existing laws and regulations could significantly increase our compliance expenditures. Pipeline safety regulations or changes to such regulations may require additional leak detection, reporting, the replacement of certain pipeline segments or equipment, addition of monitoring equipment, and more frequent monitoring, inspection or testing of our pipeline facilities. Repair, remediation, and preventative or mitigating actions may require significant capital and operating expenditures. Pipeline safety regulation has increased over time, including recent revised gas and hazardous liquid regulations that we must timely implement, and existing obligations may increase with new proposed rules that are currently under consideration. For example, PHMSA has issued a proposed rulemaking with expansive pipeline leak detection and repair requirements that is proposed to be applicable to gas pipelines, LNG facilities and underground natural gas storage facilities. PHMSA is also working on a final rulemaking regarding requirements for pipelines located in coastal ecological unusually sensitive areas, as well as a final rule that updates requirements for responding to changes in class location for gas pipelines. In addition, PHMSA is working on a number of proposed rulemakings, including those related to (i) updating regulations for LNG facilities; (ii) requirements for idled gas and liquid pipelines; (iii) revising requirements for transportation of CO2 in the liquid phase as well as establishing regulation of the transportation of gaseous CO2; (iv) oil spill response plans; and (v) liquid pipeline repair criteria.

Congress is working on the reauthorization of the Pipeline Safety Act, which is expected to be enacted in 2025 and could further expand PHMSA’s current rulemaking agenda and/or statutory authority in certain areas. There can be no assurance as to the amount or timing of future expenditures for pipeline safety and integrity regulation, and actual future expenditures may be different from the amounts we currently anticipate. Revised or additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not deemed by regulators to be fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and prospects.33

~~Climate-related~~increased ~~risks~~over time, including recent revised gas and ~~related~~hazardous ~~regulation~~liquid ~~could~~regulations ~~result~~that inwe ~~significantly~~must ~~increased~~timely ~~operating~~implement, and ~~capital~~existing ~~costs~~obligations ~~for~~may usincrease with new proposed rules that are currently under consideration. For example, PHMSA has issued a proposed rulemaking with expansive pipeline leak detection and ~~could~~repair ~~reduce~~requirements ~~demand~~that is proposed to be applicable to gas pipelines, LNG facilities and underground natural gas storage facilities. PHMSA is also working on a final rule regarding requirements for ~~our~~pipelines ~~products~~located in coastal ecological unusually sensitive areas and ~~services~~a rulemaking that seeks to update the repair criteria applicable to hazardous liquid and gas pipelines.

~~Various~~Additionally, ~~laws~~Congress ~~and~~is ~~regulations~~working ~~exist~~on ~~or are under development that seek to regulate~~ the ~~emission~~reauthorization of ~~GHGs~~the ~~such~~Pipeline asSafety ~~methane and CO2~~Act, ~~including~~which ~~the~~could ~~EPA~~further ~~programs~~expand ~~to control GHG emissions,~~ PHMSA’s ~~existing~~current ~~leak~~rulemaking ~~detection~~agenda and/or ~~repair~~statutory ~~requirements~~authority ~~and additional requirements proposed by PHMSA~~ in ~~accordance~~certain ~~with~~areas. ~~its~~There ~~Congressional~~can ~~mandate,~~be ~~state~~no ~~actions~~assurance toas ~~develop statewide or regional programs, and regulations by foreign governments that restrict imports. Existing EPA regulations require us~~ to ~~report GHG emissions in~~ the ~~U.S.~~amount ~~from~~or ~~sources~~timing ~~such~~of asfuture ~~our~~expenditures ~~larger~~for ~~natural~~pipeline ~~gas~~safety ~~compressor~~and ~~stations,~~integrity ~~fractionated NGL~~regulation, and ~~production~~actual offuture ~~naturally~~expenditures ~~occurring~~may ~~CO2~~be ~~(for~~different ~~example,~~ from ~~our~~the ~~McElmo~~amounts ~~Dome~~we ~~CO2~~currently ~~field), even when such production is not emitted to the atmosphere~~anticipate. In ~~addition,~~Revised ~~the~~or ~~European~~additional ~~Union~~regulations ~~has~~that ~~approved~~result ain ~~law~~increased tocompliance ~~impose~~costs ~~limits~~or onadditional ~~methane~~operating ~~emissions~~restrictions, ~~applicable~~particularly toif ~~imports~~those ofcosts ~~natural~~are ~~gas~~not ~~and~~deemed ~~crude~~by ~~oil~~regulators ~~beginning in 2030. Proposed approaches~~ to ~~further~~be ~~address~~fully ~~GHG~~recoverable ~~emissions~~from ~~include~~our ~~establishing GHG “cap-and-trade” programs~~customers, ~~increased~~could ~~efficiency~~have ~~standards,~~a ~~participation~~material inadverse ~~international~~effect ~~climate~~on ~~agreements~~our ~~and~~business, ~~incentives~~financial ~~or mandates for pollution reduction~~position, ~~use~~results of ~~renewable energy sources or use of alternative fuels with lower carbon content. For more information about climate change regulation~~operations, ~~see Items 1~~ and 2prospects. ~~“Business and Properties—Narrative Description of Business—Environmental Matters—Climate Change.”~~

~~Adoption~~Changes ofin ~~any~~U.S. ~~such~~trade ~~laws~~policy ~~or regulations could increase our costs to operate~~ and ~~maintain~~the ~~our~~impact ~~facilities,~~of ~~expand~~tariffs ~~existing~~may ~~facilities~~have ora ~~construct~~material ~~new~~adverse ~~facilities. We~~effect ~~could be required to install new emission controls~~ on our ~~facilities,~~business ~~acquire allowances for our GHG emissions, pay taxes related to our GHG emissions~~ and ~~administer~~results ~~and manage a GHG emissions reduction program, and such increased costs could be significant. Recovery~~ of ~~such increased costs from our customers is uncertain in all~~ operations.

Our business and results of operations may be adversely affected by uncertainty and changes in U.S. trade policies, including tariffs, trade agreements, or other trade restrictions imposed by the U.S. or other governments. For example, in 2025, the U.S. government announced multiple tariffs on several foreign jurisdictions and imports into the U.S. Several of these tariff announcements have been followed by announcements of limited exemptions and temporary pauses. These actions have caused substantial uncertainty and volatility in financial markets. Additionally, in response to these actions, certain governments have announced retaliatory measures against the U.S. and/or are in the process of negotiating with the U.S on tariff agreements. While the U.S. government has announced various trade deals, many such agreements are preliminary and may be subject to change. Further, any future disagreement between the U.S. government and other countries over the implementation of trade deals or any failure to obtain required governmental approvals or otherwise reach a final agreement could result in prolonged uncertainty regarding the scope and duration of such trade actions by the U.S. government and other countries.

In August 2025, the U.S. Court of Appeals for the Federal Circuit ruled that many of the tariffs imposed under the Trump Administration exceed presidential authority and therefore are invalid, though the decision has been stayed pending U.S. Supreme Court review. This ruling introduces additional uncertainty as to the scope and durability of existing and future tariff measures.

Our business requires access to steel and other materials to construct and maintain our pipelines. Any imposition of or increase in tariffs on imports of steel or other materials, as well as corresponding price increases for such materials available domestically, could increase our construction costs and our costs to maintain our assets. To the extent that we are unable to pass all or any such cost increases on to our customers, such cost increases could adversely affect our returns on investment. Higher materials costs could also diminish our ability to develop new projects at acceptable returns, particularly during times of economic uncertainty, and limit our ability to pursue growth opportunities.

Tariffs or other trade restrictions may lead to continuing uncertainty and volatility in U.S. and global financial and economic conditions and commodity markets, declining consumer confidence, significant inflation, and diminished expectations for the economy, and ultimately reduced demand for our and our customers’ products and services. Such conditions could have a material adverse impact on our business, results of operations, and cash flows. Also, disruptions and volatility in the financial markets may lead to adverse changes in the availability, terms, and cost of capital. Such adverse changes could increase our costs of capital and limit our access to external financing sources to fund acquisitions, capital projects, or refinancing of debt maturities on similar terms, which could in turn reduce our cash flows and limit our ability to pursue growth opportunities.

Changes in tariffs and trade restrictions can be announced with little or no advance notice. The adoption and expansion of tariffs or other trade restrictions, increasing trade tensions, or other changes in governmental policies related to taxes, tariffs, trade agreements, or policies, are difficult to predict, which makes attendant risks difficult to anticipate and mitigate. If we are unable to navigate further changes in U.S. or international trade policy, it could have a material adverse impact on our business and results of operations.

~~cases~~Climate-related risks and ~~may~~related ~~depend~~regulation ~~on events beyond our control, including the outcome of future rate proceedings before the FERC. Such laws or regulations~~ could ~~also~~result ~~lead~~in tosignificantly ~~reduced~~increased ~~demand~~operating, ~~for hydrocarbon products that are deemed to contribute to emissions of GHGs~~capital, ~~increases~~and inother ~~the~~ costs for ~~such~~us ~~products~~and ~~or restrictions on their use, which in turn~~ could ~~adversely~~reduce ~~affect~~ demand for our products and services. See also “—Business Risks—We are subject to reputational risks and risks relating to public opinion.” and “—Business Risks—Hurricanes, earthquakes, flooding and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse effect on our business, financial condition and results of operations.”

InVarious ~~March~~laws ~~2024,~~and ~~the~~regulations ~~SEC~~exist ~~finalized~~or ~~rules~~are ~~requiring~~under ~~significant~~development ~~new~~that ~~climate-related~~seek ~~disclosure~~to inregulate ~~SEC~~the ~~filings~~emission of GHGs such as methane and CO2, including ~~certain~~the ~~climate-related~~EPA ~~metrics~~programs ~~and~~to control GHG emissions ~~data~~, ~~and~~PHMSA’s ~~third-party~~existing ~~attestation~~leak ~~requirements. In~~detection ~~April~~and ~~2024~~repair requirements, ~~the~~and ~~SEC~~additional ~~voluntarily~~requirements ~~stayed~~proposed ~~the~~by ~~effectiveness~~PHMSA ofin ~~the~~accordance ~~new~~with ~~rules~~its Congressional mandate, ~~pending~~state ~~judicial~~actions ~~review~~to develop statewide or regional programs, and onregulations ~~February~~by ~~11,~~foreign ~~2025,~~governments ~~the~~that ~~Acting~~restrict ~~Chairman~~imports. ofAlthough the ~~SEC~~EPA ~~directed~~recently ~~the~~announced ~~SEC~~its ~~staff~~intention to ~~request~~reconsider ~~that~~certain findings underlying the ~~court~~agency’s ~~not~~regulation ~~schedule~~of ~~the~~GHGs, ~~case~~as ~~for~~well ~~argument~~as tomandatory ~~provide~~GHG ~~time~~reporting ~~for~~requirements, the ~~SEC~~EPA’s tocurrent ~~deliberate~~regulations ~~and~~require ~~determine~~us ~~the~~to ~~appropriate~~report ~~next~~GHG ~~steps~~emissions in the ~~cases~~U. ~~The~~S. ~~State~~from sources such as our larger natural gas compressor stations, fractionated NGL, and production of ~~California~~naturally ~~also~~occurring ~~has~~CO2 ~~enacted~~(for ~~legislation~~example, ~~requiring~~from ~~climate-related~~our ~~disclosures. Other~~McElmo ~~U.S.~~Dome ~~states~~CO2 ~~have~~field), ~~announced~~even ~~similar~~when ~~proposed~~such ~~regulations~~production is not emitted to the atmosphere. ~~These~~ ~~types~~In ofaddition, ~~regulations~~the ~~may~~European ~~expose~~Union ushas approved a law to ~~significant~~impose ~~additional~~limits ~~compliance~~on ~~costs. Some~~methane ~~customers~~emissions ~~and~~applicable ~~other~~to ~~third~~imports ~~parties~~of ~~also~~natural ~~have~~gas ~~begun~~and ~~requesting~~crude ~~disclosures~~oil ~~from~~beginning usin ~~related~~2030. Proposed approaches to ~~their~~further ~~own~~address ~~reporting~~GHG ~~obligations. At~~emissions ~~this~~include ~~time~~establishing GHG “cap-and-trade” programs, weincreased ~~cannot~~efficiency ~~predict~~standards, ~~the~~participation ~~costs~~in ofinternational ~~compliance~~climate ~~with~~agreements, orand ~~other~~incentives ~~potential~~or ~~adverse~~mandates ~~impacts~~for ~~resulting~~pollution ~~from~~reduction, ~~these~~use of renewable energy sources or ~~similar~~use ~~future~~of ~~rules~~alternative ~~that~~fuels ~~may~~with belower ~~adopted~~carbon content. For more information about climate change regulation, see Items 1 and 2. “Business and Properties—Narrative Description of Business—Environmental Matters—Climate Change.”

~~Any~~Adoption of any such laws or regulations could increase our costs to operate and maintain our facilities, expand existing facilities, or construct new facilities. We could be required to install new emission controls on our facilities, acquire allowances for our GHG emissions, pay taxes related to our GHG emissions, and administer and manage a GHG emissions reduction program, and such increased costs could be significant. Recovery of such increased costs from our customers is uncertain in all cases and may depend on events beyond our control, including the ~~foregoing~~outcome of future rate proceedings before the FERC. Such laws or regulations could also lead to reduced demand for hydrocarbon products that are deemed to contribute to emissions of GHGs, increases in the costs for such products or restrictions on their use, which in turn could adversely affect demand for our products and services. See also “—Business Risks—We are subject to reputational risks and risks relating to public opinion.” and “—Business Risks—Hurricanes, earthquakes, flooding, and other natural disasters, as well as subsidence and coastal erosion and climate-related physical risks, could have an adverse ~~effects~~effect on our business, financial ~~position~~condition, and results of operations ~~or cash flows~~.”

Public attention with respect to climate matters has resulted in an overall increase in climate focused activities in recent years by interested stakeholders, including government authorities and private interest groups. These include efforts to implement new laws, regulations, and policies focused on enhanced disclosures related to climate matters. The commitment to such climate focused initiatives has varied over time, including with changes in U.S. presidential administrations and public priorities. At various times, the federal government, states, and groups of states have adopted or proposed climate related laws, regulations, or policies that could subject us to substantial compliance costs. For example, the SEC finalized rules requiring significant new climate-related disclosure in SEC filings, including certain climate-related metrics and GHG emissions data, and third-party attestation requirements. Although the SEC voluntarily stayed the effectiveness of such rules and has advised the U.S. Court of Appeals for the Eighth Circuit that it does not intend to reconsider or defend the rules, such rules or similar rules could be pursued in the future by the SEC or another government authority. See “New or amended laws, policies, regulations and oversight requirements, and compliance complexity resulting from disparities in requirements imposed by federal, state, and local authorities, could adversely impact our earnings, cash flows, and operations.” above for discussion of other state climate disclosure regulations that could subject us to substantial compliance costs.

Any of the foregoing could have adverse effects on our business, financial position, results of operations, or cash flows.

Increased regulation of exploration and production activities, including activity on public lands, could result in reductions or delays in drilling and completing new oil and natural gas wells, as well as reductions in production from existing wells, which could adversely impact the volumes of natural gas transported on our natural gas pipelines and our own oil and gas development and production activities.

We gather, process, or transport crude oil, natural gas, or NGL from several areas, including lands that are federally managed. Policy and regulatory initiatives or legislation by Congress may decrease access to federally managed lands or increase the regulatory burdens associated with using these lands to produce crude oil or natural gas, or both. From 2021 to 2024, the federal government deprioritized onshore leasing and its review of applications for permits to drill. Third-party interest groups and members of the oil and gas industry have initiated litigation challenging decisions to approve or prohibit oil and gas activities on federally managed lands.

In addition, oil and gas development and production activities are subject to increasing regulation at the federal, state and local levels. For example, there have been initiatives at the federal and state levels to regulate or otherwise restrict the use of certain hydraulic fracturing activities, and many states are promulgating stricter requirements related not only to well development but also to compressor stations and other facilities in the oil and gas industry. These activities are subject to laws and regulations regarding the acquisition of permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes. In addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

Adoption of legislation or regulations restricting these activities in our areas of operations could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas or NGL and, in turn, adversely affect our revenues, cash flows and results of operations by decreasing the volumes of these commodities that we handle. These laws and regulations may also adversely affect our own oil and gas development and production activities.

The Jones Act includes restrictions on ownership by non-U.S. citizens of our U.S. point-to-point maritime shipping vessels, and failure to comply with the Jones Act, or changes to or a repeal of the Jones Act, could limit our ability to operate our vessels in the U.S. coastwise trade, result in the forfeiture of our vessels or otherwise adversely impact our earnings, cash flows and operations.

We are subject to the Jones Act, which generally restricts U.S. point-to-point maritime shipping to vessels operating under the U.S. flag, built in the U.S., owned and operated by U.S.-organized companies that are controlled and at least 75% owned by U.S. citizens and crewed by predominately U.S. citizens. Our business would be adversely affected if we fail to comply with the Jones Act provisions on coastwise trade. If we do not comply with any of these requirements, we would be prohibited from operating our vessels in the U.S. coastwise trade and, under certain circumstances, we could be deemed to have undertaken an unapproved transfer to non-U.S. citizens that could result in severe penalties, including permanent loss of U.S. coastwise

~~trading~~In ~~rights~~addition, ~~for~~oil ~~our~~and ~~vessels,~~gas ~~fines~~development orand ~~forfeiture~~production ofactivities ~~vessels~~are subject to increasing regulation at the federal, state, and local levels. ~~Our~~ ~~business~~For ~~could~~example, bethere ~~adversely~~have ~~affected~~been ifinitiatives at the ~~Jones~~federal ~~Act~~and ~~were~~state levels to beregulate ~~modified~~ or ~~repealed~~otherwise sorestrict asthe touse ~~permit~~of ~~foreign~~certain ~~competition~~hydraulic ~~that~~fracturing isactivities, and many states are promulgating stricter requirements related not only to well development but also to compressor stations and other facilities in the oil and gas industry. These activities are subject to laws and regulations regarding the ~~same~~acquisition Uof permits before drilling, restrictions on drilling activities and location, emissions into the environment, water discharges, transportation of hazardous materials, and storage and disposition of wastes.S. ~~government-imposed~~In ~~burdens~~addition, legislation has been enacted that requires well and facility sites to be abandoned and reclaimed to the satisfaction of state authorities.

Adoption of legislation or regulations restricting these activities in our areas of operations could impose operational delays, increased operating costs and additional regulatory burdens on exploration and production operators, which could reduce their production of crude oil, natural gas, or NGL and, in turn, adversely affect our revenues, cash flows, and results of operations by decreasing the volumes of these commodities that we handle. These laws and regulations may also adversely affect our own oil and gas development and production activities.

Risks Related to Ownership of Our Capital Stock

The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.

We disclose in this report and elsewhere the anticipated cash dividends on our common stock. These reflect our current judgment, but as with any estimate, they may be affected by inaccurate assumptions and other risks and uncertainties, many of which are beyond our control. See “Information Regarding Forward-Looking Statements” at the beginning of this report. If our Board elects to pay dividends at the anticipated level and that action would leave us with insufficient cash to take timely advantage of growth opportunities (including through acquisitions), to meet any large unanticipated liquidity requirements, to fund our operations, to maintain our leverage metrics, or otherwise to properly address our business prospects, our business could be harmed.

Conversely, a decision to address such business needs might lead to the payment of dividends below the anticipated levels. As events present themselves or become reasonably foreseeable, our Board which determines our business strategy and our dividends, may decide to address those matters by reducing our anticipated dividends. Alternatively, because nothing in our governing documents or credit agreements prohibits us from borrowing to pay dividends, we could choose to incur debt to enable us to pay our anticipated dividends. This would add to our substantial debt discussed above under “—Risks Related to Financing Our Business—Our substantial debt could adversely affect our financial health and make us more vulnerable to adverse economic conditions.”

Our certificate of incorporation restricts the ownership of our common stock by non-U.S. citizens within the meaning of the Jones Act. These restrictions may affect the liquidity of our common stock and may result in non-U.S. citizens being required to sell their shares at a loss.

The Jones Act requires, among other things, that at least 75% of our common stock be owned at all times by U.S. citizens, as defined under the Jones Act, in order for us to own and operate vessels in the U.S. coastwise trade. As a safeguard to help us maintain our status as a U.S. citizen, our certificate of incorporation provides that, if the number of shares of our common stock owned by non-U.S. citizens exceeds 22%, we have the ability to redeem shares owned by non-U.S. citizens to reduce the percentage of shares owned by non-U.S. citizens to 22%. These redemption provisions may adversely impact the marketability of our common stock, particularly in markets outside of the U.S. Further, those stockholders would not have control over the timing of such redemption and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.

of our common stock, particularly in markets outside of the U.S. Further, those stockholders would not have control over the timing of such redemption and may be subject to redemption at a time when the market price or timing of the redemption is disadvantageous. In addition, the redemption provisions might have the effect of impeding or discouraging a merger, tender offer or proxy contest by a non-U.S. citizen, even if it were favorable to the interests of some or all of our stockholders.

Item 1B. Unresolved Staff Comments.

None.

Item 1C. Cybersecurity.

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.

36We 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 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 ~~2024~~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.

Item 3. Legal Proceedings.

See Note 17 “Litigation and Environmental” to our consolidated financial statements.

Item 4. Mine Safety Disclosures.

Except for one terminal facility that is in temporary idle status with the Mine Safety and Health Administration, we do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Act. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of the Dodd-Frank Act for the year ended December 31, 2024.

Item 4. Mine Safety Disclosures.

We do not own or operate mines for which reporting requirements apply under the mine safety disclosure requirements of the Dodd-Frank Act. We have not received any specified health and safety violations, orders or citations, related assessments or legal actions, mining-related fatalities, or similar events requiring disclosure pursuant to the mine safety disclosure requirements of the Dodd-Frank Act for the year ended December 31, 2025.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Our Class P common stock is listed for trading on the NYSE under the symbol “KMI.”

As of February 12, ~~2025~~2026, we had 98,~~082~~596 holders of record of our Class P common stock, which does not include beneficial owners whose shares are held by a nominee, such as a broker or bank.

For information on our equity compensation plans, see Note 9 “Share-based Compensation and Employee Benefits—Share-based Compensation” to our consolidated financial statements. For information about our expectations regarding dividends, please see Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—General—~~2025~~2026 Dividends and Discretionary Capital.”

Item 6. [Reserved]

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

The following discussion and analysis should be read in conjunction with our consolidated financial statements and the notes thereto. We prepared our consolidated financial statements in accordance with GAAP. Additional sections in this report which should be helpful to the reading of our discussion and analysis include the following: (i) a description of our business strategy found in Items 1 and 2. “Business and Properties—Narrative Description of Business—Business Strategy;” (ii) a description of developments during ~~2024~~2025, found in Items 1 and 2. “Business and Properties—General Development of Business—Recent Developments;” (iii) a description of terms for services and commodities we provide, found in Items 1 and 2.

“Business and Properties—Narrative Description of Business—Business Segments;” (iv) a description of risk factors affecting us and our business, found in Item 1A. “Risk Factors;” and (v) a discussion of forward-looking statements, found in “Information Regarding Forward-Looking Statements” at the beginning of this report.

A comparative discussion of our ~~2023~~2024 to ~~2022~~2023 operating results can be found in Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Results of Operations” included in our Annual Report on Form 10-K for the year ended December 31, ~~2023~~2024 filed with the SEC on February 2013, ~~2024~~2025.

General

~~Acquisitions~~Acquisition and ~~Divestitures~~Divestiture

Following are ~~acquisitions~~an acquisition and ~~divestitures~~a divestiture we made during the ~~2024~~2025 reporting period. See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information on these transactions.

Event	Description	Business Segment
North McElroy Unit acquisition$61 million(June 2024)	We acquired AVAD Energy Partners’ interest in the North McElroy Unit (NMU). NMU is an existing waterflood that currently produces approximately 1,250 Bbl/d of crude oil. Our analysis suggests that NMU could be a candidate for CO2 flooding.	CO2(Oil and Gas Producing activities)
EagleHawk divestiture$382 million(December 2025)	We sold our 25% equity interest in EagleHawk.	Natural Gas Pipelines(Midstream)
CO2 assets divestiture$18 million(June 2024)	We sold 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.	CO2(Oil and Gas Producing activities)
Outrigger Energy acquisition$648 million(February 2025)	Natural gas gathering and processing system in North Dakota from Outrigger Energy II LLC which 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.	Natural Gas Pipelines(Midstream)
Oklahoma assets divestiture$43 million(February 2024)	We sold our Oklahoma midstream assets consisting of our Oklahoma system and Cedar Cove.	Natural Gas Pipelines(Midstream)

~~Additionally,~~2026 onDividends ~~January 13, 2025, we announced that we had entered into an agreement to purchase a natural gas gathering~~ and ~~processing~~Discretionary system in North Dakota from Outrigger Energy II LLC for a cash payment of $640 million. 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. With this transaction, we expect to reduce future capital expenditures needed to accommodate the growth of our existing Bakken Capital

39We expect to declare dividends of $1.19 per share for 2026, a 2% increase from the 2025 declared dividends of $1.17 per share. Excluding our recently divested interest in EagleHawk, we also expect to invest almost $3.3 billion in expansion projects and contributions to joint ventures, or discretionary capital expenditures, during 2026.

~~customers.~~The ~~Initially,~~expectations wefor ~~plan~~2026 todiscussed ~~fund~~above ~~the~~involve ~~transaction~~risks, ~~with~~uncertainties ~~short-term~~and ~~borrowings~~assumptions, and ~~cash~~are onnot ~~hand~~guarantees of performance. ~~Subject~~ Many of the factors that will determine these expectations are beyond our ability to ~~customary~~control ~~closing~~or ~~conditions~~predict, and ~~regulatory~~because ~~approval,~~of ~~this~~these ~~transaction~~uncertainties, it is ~~expected~~advisable not to ~~close~~put inundue ~~the~~reliance ~~first~~on ~~quarter~~any offorward-looking ~~2025~~statement. Please read

~~2025 Dividends and Discretionary Capital~~40

We“Information ~~expect~~Regarding toForward-Looking ~~declare~~Statements” ~~dividends~~at ~~of $1.17 per share for 2025, a 2% increase from~~ the ~~2024~~beginning ~~declared dividends~~ of ~~$1.15~~this ~~per~~report ~~share. We~~and ~~also~~Item ~~expect to invest $2~~1A.~~3 billion~~ in“Risk ~~expansion~~Factors” ~~projects~~for ~~and~~more ~~contributions to joint ventures, or discretionary capital expenditures, during 2025~~information.

The expectations for 2025 discussed above involve risks, uncertainties and assumptions, and are not guarantees of performance. Many of the factors that will determine these expectations are beyond our ability to control or predict, and because of these uncertainties, it is advisable not to put undue reliance on any forward-looking statement. Please read “Information Regarding Forward-Looking Statements” at the beginning of this report and Item 1A. “Risk Factors” for more information.

Critical Accounting Estimates

Critical accounting estimates and assumptions involve material levels of subjectivity and complex ~~judgement~~judgment to account for highly uncertain matters or matters with a high susceptibility to change, and could result in a material impact to our financial statements. Examples of certain areas that require more judgment relative to others when preparing our consolidated financial statements and related disclosures include our use of estimates in determining (i) revenue recognition; (ii) income taxes; (iii) the economic useful lives of our assets and related depreciation and depletion rates; (iv) the fair values used in (a) assignment of the purchase price for a business acquisition, (b) calculations of possible asset and equity investment impairment charges, (c) calculation for the annual goodwill impairment test (or interim tests if triggered), and (d) recording derivative contract assets and liabilities; (v) reserves for environmental claims, legal fees, transportation rate cases, and other litigation liabilities; (vi) provisions for credit losses; and (vii) exposures under contractual indemnifications. We routinely evaluate these estimates, 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, and 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.

For a summary of our significant accounting policies, see Note 2 “Summary of Significant Accounting Policies” to our consolidated financial statements and the following discussion for further information regarding critical accounting estimates and assumptions used in the preparation of our financial statements. For discussion on our hedging activities and related sensitivities to our estimates, see Note 13 “Risk Management” to our consolidated financial statements and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk,” respectively.

Impairments

In addition to our annual ~~testing~~goodwill of impairment ~~for goodwill~~testing, we evaluate ~~impairment of~~ our ~~long-lived~~goodwill, ~~assets when a triggering event occurs. Management applies judgment in determining whether there is an impairment indicator. Fair value calculated for the purpose of testing our~~ long-lived assets, ~~including intangible assets, goodwill~~ and equity method investments, for impairment ~~involves~~whenever ~~the~~events ~~use~~or ofchanges ~~significant~~in ~~estimates~~circumstances ~~and~~indicate ~~assumptions~~that ~~regarding~~their ~~the~~carrying ~~timing and~~ amounts ofmay ~~future~~not ~~cash inflows and outflows, discount rates, market prices and asset lives, among other items. The estimates and assumptions can~~ be ~~affected by a variety of factors, including external factors such as industry and economic trends, and internal factors such as changes in our business strategy and our internal forecasts~~recoverable. An ~~estimate~~Management ofapplies ~~the~~judgment ~~sensitivity to changes~~ in ~~underlying~~assessing ~~assumptions~~whether ofsuch atriggering ~~fair~~events ~~value~~have ~~calculation is not practicable, given the numerous assumptions that can materially affect our estimates~~occurred.

Impairment testing requires estimating fair value, which involves the use of significant estimates and assumptions regarding the timing and amounts of future cash inflows and outflows, commodity prices, discount rates, market multiples, and asset lives, among other items and as applicable. These estimates can be affected by a variety of factors, including external factors such as industry and macroeconomic conditions, and internal factors such as changes in our business strategy and our internal forecasts. We base our fair value estimates on projected financial information which we believe to be reasonable. However, actual results may differ from these projections. An estimate of the sensitivity to changes in underlying assumptions of a fair value calculation is not practicable, given the numerous assumptions that can materially affect our estimates.

Although we did not identify any triggering events during 2025, we may identify factors in the future that require further evaluation, which could lead to future impairment charges that could have a significant effect on our results of operations.

Environmental Matters

With respect to our environmental exposure, we utilize both internal staff and external experts to assist us in identifying environmental issues and in estimating the costs and timing of remediation efforts. Our accrual of environmental liabilities often coincides either with our completion of a feasibility study or our commitment to a formal plan of action, but generally, we recognize and/or adjust our probable environmental liabilities, if necessary or appropriate, following quarterly reviews of potential environmental issues and claims that could impact our assets or operations. In recording and adjusting environmental liabilities, we consider the effect of environmental compliance, pending legal actions against us, and potential third-party liability claims. For more information on environmental matters, see Part I, Items 1 and 2. “Business and Properties—Narrative Description of Business—Environmental Matters.” For more information on our environmental disclosures, see Note 17 “Litigation and Environmental” to our consolidated financial statements.

Legal and Regulatory Matters

Many of our operations are regulated by various U.S. regulatory bodies, and we are subject to legal and regulatory matters as a result of our business operations and transactions. We utilize both internal and external counsel in evaluating our potential exposure to adverse outcomes from orders, judgments, or settlements. Any such liability recorded is revised as better information becomes available. Accordingly, to the extent that actual outcomes differ from our estimates, or additional facts and circumstances cause us to revise our estimates, our earnings will be affected. For more information on regulatory matters, see Part I, Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation.” For more information on legal proceedings, see Note 17 “Litigation and Environmental” to our consolidated financial statements.

and circumstances cause us to revise our estimates, our earnings will be affected. For more information on regulatory matters, see Part I, Items 1 and 2. “Business and Properties—Narrative Description of Business—Industry Regulation.” For more information on legal proceedings, see Note 17 “Litigation and Environmental” to our consolidated financial statements.

Employee Benefit Plans

Our pension and other postretirement benefits (OPEB) obligations and net benefit costs are primarily based on actuarial calculations. A significant assumption we utilize is the discount rate used in calculating our benefit obligations. The selection of assumptions used in the actuarial calculations of our pension and OPEB plans is further discussed in Note 9 “Share-based Compensation and Employee Benefits” to our consolidated financial statements.

Actual results may differ from the assumptions included in these calculations, and as a result, our estimates associated with our pension and OPEB obligations can be, and have been revised in subsequent periods. The income statement impact of the changes in the assumptions on our related benefit obligations are deferred and amortized into income over either the period of expected future service of active participants, or over the expected future lives of inactive plan participants.

The following sensitivity analysis shows the estimated impact of a 1% change in the primary assumptions used in our actuarial calculations associated with our pension and OPEB plans for the year ended December 31, ~~2024~~2025:

	Pension Benefits				OPEB
	Net benefit cost (credit)		Funded status		Net benefit cost (credit)		Funded status(a)
	(In millions)
One percent increase in:
Discount rates	$	(91)	$	118	$	—	$	109
Expected return on plan assets	(1516)		—		(3)		—
Rate of compensation increase	2		(910)		1—		~~(5)~~—
One percent decrease in:
Discount rates	119		(~~137~~136)		—		(1110)
Expected return on plan assets	1516		—		3		—
Rate of compensation increase	(2)		89		~~(1)~~—		5—

(a)Includes amounts deferred as either accumulated other comprehensive income (loss) or as a regulatory asset or liability for certain of our regulated operations.

Income Taxes

We make significant judgments and estimates in determining our provision for income taxes, including our assessment of our income tax positions given the uncertainties involved in the interpretation and application of complex tax laws and regulations in various taxing jurisdictions. Numerous and complex judgments and assumptions are inherent in the estimation of future taxable income when determining a valuation allowance, including factors such as future operating conditions and the apportionment of income by state. For more information, see Note 4 “Income Taxes” to our consolidated financial statements.

Results of Operations

Overview

As described in further detail below, our management evaluates our performance primarily using Net income attributable to Kinder Morgan, Inc. and Segment earnings before DD&A expenses ~~including amortization of excess cost of equity investments~~ (EBDA) (as presented in Note 15 “Reportable Segments”), along with the non-GAAP financial measures of Adjusted Net Income Attributable to Common Stock, in the aggregate and per share, Adjusted Segment EBDA, Adjusted Net Income Attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses, and amortization of basis differences related to our joint ventures (previously known as amortization of excess cost of equity investments) (EBITDA), and Net Debt.

41Effective 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

Income Attributable to Common Stock, in the aggregate and per share, Adjusted Segment EBDA, Adjusted Net Income Attributable to Kinder Morgan, Inc., Adjusted earnings before interest, income taxes, DD&A expenses including amortization of excess cost of equity investments (EBITDA), and Net Debt. Historically, we have disclosed the non-GAAP financial measure of distributable cash flow (DCF), in the aggregate and per share; however, we are not including discussion of DCF in this report due to declining investor interest in DCF as a primary performance measure.42

EBDA. As a result, Segment EBDA for the year ended December 31, 2024 has been adjusted to conform to the current presentation in the following MD&A tables. The adjustments were not material.

GAAP Financial Measures

The Consolidated Earnings Results for the years ended December 31, ~~2024~~2025 and ~~2023~~2024 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 15 “Reportable Segments” pursuant to FASB ASC 280. The composition of Segment EBDA is not addressed nor prescribed by generally accepted accounting principles. Segment EBDA is a useful measure of our operating performance because it measures the operating results of our segments before DD&A and certain expenses that are generally not controllable by our business segment operating managers, such as general and administrative expenses and corporate charges, interest expense, net, and income taxes. Our general and administrative expenses and corporate charges include such items as unallocated employee benefits, insurance, rentals, unallocated litigation, and environmental expenses, and shared corporate services including accounting, IT, human resources, and legal services.

Non-GAAP Financial Measures

Our non-GAAP financial measures described below should not be considered alternatives to GAAP Net income attributable to Kinder Morgan, Inc. or other GAAP measures and have important limitations as analytical tools. Our computations of these non-GAAP financial measures may differ from similarly titled measures used by others. You should not consider these non-GAAP financial measures in isolation or as substitutes for an analysis of our results as reported under GAAP. Management compensates for the limitations of our consolidated non-GAAP financial measures by reviewing our comparable GAAP measures identified in the descriptions of consolidated non-GAAP measures below, understanding the differences between the measures and taking this information into account in its analysis and its decision-making processes.

Certain Items

Certain Items, as adjustments used to calculate our non-GAAP financial measures, are items that are required by GAAP to be reflected in Net income attributable to Kinder Morgan, Inc., but typically ~~either~~ (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), or (ii) by their nature are separately identifiable from our normal business operations and in most cases are likely to occur only sporadically (for example, certain legal settlements, enactment of new tax legislation, and casualty losses), or (iii) align the timing of impacts from natural gas inventory hedges with the future associated physical withdrawals from inventory. (See the tables included in “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.,” “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” and “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below). We also include adjustments related to joint ventures (see “—Amounts ~~from~~associated with Joint Ventures” below). The following table summarizes our Certain Items for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions)
Certain Items
Change in fair value of derivative contracts(a)	$	72	$	(126)
Risk management activities(a)(b)	$	(29)	$	72
(Gain) loss on divestitures and impairment, net(b)	(69)		67
Gain on divestitures(c)	(123)		(69)
Income tax Certain Items(c)	(52)		33
Income tax Certain Items(d)	(2)		(52)
Other(d)	7		45
Other	(3)		7
Total Certain Items(e)	$	(42157)	$	19(42)

(a)~~Gains~~Includes changes in fair value of unsettled derivatives, of which gains or losses are reflected within non-GAAP financial measures when realized.

(b)~~2024~~Includes ~~amount~~natural ~~represents~~gas ~~gains~~inventory ~~of $40 million and $29 million~~hedges, ~~respectively, on divestitures~~ of ~~CO2~~which ~~and~~gains ~~Oklahoma~~or ~~midstream~~losses ~~assets. 2023~~are ~~amount~~reflected ~~represents $67 million included~~ within ~~“Earnings from equity investments” on the accompanying consolidated statement of income for a~~ non-~~cash~~GAAP ~~impairment~~financial ~~related~~measures towhen ~~our~~the ~~investment~~associated inphysical ~~Double~~gas ~~Eagle~~is ~~Pipeline~~withdrawn ~~LLC~~from ~~in our Products Pipelines business segment (see Note 6 “Investments”)~~inventory.

42(c)2025 amount represents a gain on the sale of our equity interest in EagleHawk. 2024 amount represents gains of $40 million and $29 million, respectively, on divestitures of CO2 and Oklahoma midstream assets.

(c)Represents the income tax provision on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related tax provision recognized at the investees by the joint ventures which are also taxable entities.43

(d)~~2023~~Represents ~~amount~~the ~~represents~~income ~~pension~~tax ~~cost~~provision ~~adjustments~~on Certain Items plus discrete income tax items. Includes the impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments and is separate from the related totax ~~settlements~~provision ~~made~~recognized at the investees by ~~our~~the ~~pension~~joint ~~plans~~ventures which are also taxable entities.

(e)~~2024~~2025 and ~~2023~~2024 amounts include ~~the~~$13 ~~following~~million ~~amounts~~and $(5) million, respectively, reported within “Interest, net” on the accompanying consolidated statements of income: ~~$(5) million and $(7) million, respectively,~~ of “~~Change~~Risk inmanagement ~~fair value of derivative contracts~~activities.”

Adjusted Net Income Attributable to Kinder Morgan, Inc.

Adjusted Net Income Attributable to Kinder Morgan, Inc. is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items. Adjusted Net Income Attributable to Kinder Morgan, Inc. is used by us, investors and other external users of our financial statements as a supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. We believe the GAAP measure most directly comparable to Adjusted Net Income Attributable to Kinder Morgan, Inc. is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.” below.

Adjusted Net Income Attributable to Common Stock and Adjusted EPS

Adjusted Net Income Attributable to Common Stock is calculated by adjusting Net income attributable to Kinder Morgan, Inc., the most comparable GAAP measure, for Certain Items, and further for net income allocated to participating securities and adjusted net income in excess of distributions for participating securities. We believe Adjusted Net Income Attributable to Common Stock allows for calculation of adjusted earnings per share (Adjusted EPS) on the most comparable basis with earnings per share, the most comparable GAAP measure to Adjusted EPS. Adjusted EPS is calculated as Adjusted Net Income Attributable to Common Stock divided by our weighted average shares outstanding. Adjusted EPS applies the same two-class method used in arriving at basic earnings per share. Adjusted EPS is used by us, investors, and other external users of our financial statements as a per-share supplemental measure that provides decision-useful information regarding our period-over-period performance and ability to generate earnings that are core to our ongoing operations. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock” below.

Adjusted Segment EBDA

Adjusted Segment EBDA is calculated by adjusting segment earnings before DD&A ~~and amortization of excess cost of equity investments~~, general and administrative expenses and corporate charges, interest expense, and income taxes (Segment EBDA) for Certain Items attributable to the segment. Adjusted Segment EBDA is used by management in its analysis of segment performance and management of our business. We believe Adjusted Segment EBDA is a useful performance metric because it provides management, investors, and other external users of our financial statements additional insight into performance trends across our business segments, our segments’ relative contributions to our consolidated performance, and the ability of our segments to generate earnings on an ongoing basis. Adjusted Segment EBDA is also used as a factor in determining compensation under our annual incentive compensation program for our business segment presidents and other business segment employees. We believe it is useful to investors because it is a measure that management uses to allocate resources to our segments and assess each segment’s performance. See “—~~Non-GAAP Financial Measures—Reconciliation of~~ Segment ~~EBDA~~Earnings ~~to Adjusted Segment EBDA~~Results” below.

Adjusted EBITDA

Adjusted EBITDA is calculated by adjusting Net income attributable to Kinder Morgan, Inc. for Certain Items and further for DD&A, and amortization of ~~excess~~basis ~~cost~~differences ofrelated ~~equity~~to ~~investments~~our joint ventures, income tax expense, and interest. We also include amounts from joint ventures for income taxes and DD&A (see “—Amounts ~~from~~associated with Joint Ventures” below). Adjusted EBITDA is used by management, investors, and other external users, in conjunction with our Net Debt (as described further below), to evaluate our leverage. Management and external users also use Adjusted EBITDA as an important metric to compare the valuations of companies across our industry. Our ratio of Net Debt-to-Adjusted EBITDA is used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the GAAP measure most directly comparable to Adjusted EBITDA is Net income attributable to Kinder Morgan, Inc. See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.

43Amounts associated with Joint Ventures

~~Amounts~~Certain Items and Adjusted EBITDA reflect amounts from ~~Joint~~unconsolidated ~~Ventures~~joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and

Certain Items and Adjusted EBITDA reflect amounts from unconsolidated joint ventures and consolidated joint ventures utilizing the same recognition and measurement methods used to record “Earnings from equity investments” and “Noncontrolling interests,” respectively. The calculation of Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include DD&A and income tax expense) with respect to the joint ventures as those included in the calculation of Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculation of Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2024, by subtracting the following amounts from our debt balance of $31,890 million: (i) cash and cash equivalents of $88 million; (ii) debt fair value adjustments of $102 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $(25) million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.

“Noncontrolling interests,” respectively. The calculation of Adjusted EBITDA related to our unconsolidated and consolidated joint ventures include DD&A, amortization of basis differences, and income tax expense with respect to the joint ventures as those included in the calculation of Adjusted EBITDA for our wholly-owned consolidated subsidiaries; further, we remove the portion of these adjustments attributable to non-controlling interests. (See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA” below.) Although these amounts related to our unconsolidated joint ventures are included in the calculation of Adjusted EBITDA, such inclusion should not be understood to imply that we have control over the operations and resulting revenues, expenses, or cash flows of such unconsolidated joint ventures.

Net Debt

Net Debt is calculated, based on amounts as of December 31, 2025, by subtracting the following amounts from our debt balance of $32,003 million: (i) cash and cash equivalents of $63 million; (ii) debt fair value adjustments of $180 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $44 million for which we have entered into currency swaps to convert that debt to U.S. dollars. Net Debt, on its own and in conjunction with our Adjusted EBITDA as part of a ratio of Net Debt-to-Adjusted EBITDA, is a non-GAAP financial measure that is used by management, investors, and other external users of our financial information to evaluate our leverage. Our ratio of Net Debt-to-Adjusted EBITDA is also used as a supplemental performance target for purposes of our annual incentive compensation program. We believe the most comparable measure to Net Debt is total debt.

Consolidated Earnings Results

The following tables summarize the key components of our consolidated earnings results.

	Year Ended December 31,
	2024		2023		Earningsincrease/(decrease)
	2025		2024		Earningsincrease/(decrease)
	(In millions, except per share amounts and percentages)
Revenues	$	1516,~~100~~937	$	15,~~334~~100	$	~~(234)~~1,837	~~(2)~~12	%
Operating Costs, Expenses and Other
Operating Costs, Expenses, and Other
Costs of sales (exclusive of items shown separately below)	(45,~~337~~529)		(4,~~938~~337)		~~601~~(1,192)		12(27)	%
Operations and maintenance	(23,~~972~~057)		(2,~~807~~972)		(~~165~~85)		(63)	%
DD&A	(2,~~354~~453)		(2,~~250~~354)		(~~104~~99)		(54)	%
General and administrative	(~~712~~744)		(~~668~~712)		(4432)		(74)	%
Taxes, other than income taxes	(~~433~~445)		(~~421~~433)		(12)		(3)	%
Other income, net	9215		1392		79(77)		~~608~~(84)	%
Total Operating Costs, Expenses and Other	(10,716)		(11,071)		355		3	%
Total Operating Costs, Expenses, and Other	(12,213)		(10,716)		(1,497)		(14)	%
Operating Income	4,~~384~~724		4,~~263~~384		~~121~~340		38	%
Other Income (Expense)
Earnings from equity investments	~~890~~896		~~838~~840		5256		67	%
Amortization of excess cost of equity investments	(50)		(66)		16		24	%
Interest, net	(1,801)		(1,844)		43		2	%
Interest, net	(1,844)		(1,797)		(47)		(3)	%
Other, net	173		27		146		541	%
Other, net	27		(37)		64		173	%
Total Other Expense	(732)		(977)		245		25	%
Total Other Expense	(977)		(1,062)		85		8	%
Income Before Income Taxes	3,992		3,407		585		17	%
Income Before Income Taxes	3,407		3,201		206		6	%
Income Tax Expense	(832)		(687)		(145)		(21)	%
Income Tax Expense	(687)		(715)		28		4	%
Net Income	3,160		2,720		440		16	%
Net Income	2,720		2,486		234		9	%
Net Income Attributable to Noncontrolling Interests	(104)		(107)		3		3	%
Net Income Attributable to Noncontrolling Interests	(107)		(95)		(12)		(13)	%
Net Income Attributable to Kinder Morgan, Inc.	$	3,056	$	2,613	$	443	17	%
Net Income Attributable to Kinder Morgan, Inc.	$	2,613	$	2,391	$	222	9	%
Basic and diluted earnings per share	$	1.37	$	1.17	$	0.20	17	%
Basic and diluted earnings per share	$	1.17	$	1.06	$	0.11	10	%
Basic and diluted weighted average shares outstanding	2,223		2,220		3		—	%
Basic and diluted weighted average shares outstanding	2,220		2,234		(14)		(1)	%
Declared dividends per share	$	1.17	$	1.15	$	0.02	2	%
Declared dividends per share	$	1.15	$	1.13	$	0.02	2	%

Our consolidated revenues primarily consist of services and sales revenue. Our services revenues include fees for transportation and other midstream services that we perform. Fluctuations in our consolidated services revenue largely reflect changes in volumes and/or in the rates we charge. Our consolidated sales revenues include sales of natural gas (includes natural gas and RNG), products (includes NGL, crude oil, CO2, and transmix) and other (includes RINs). Our consolidated sales revenue will fluctuate with commodity prices and volumes, and the costs of sales associated with purchases will usually have a commensurate and offsetting impact, except for the CO2 segment, which produces, instead of purchases, the crude oil, CO2, and RINs it sells. Additionally, fluctuations in revenues and costs of sales may be further impacted by gains or losses from derivative contracts that we use to manage our commodity price risk.

Below is a discussion of significant changes in our Consolidated Earnings Results for the comparable years ended ~~2024~~2025 and ~~2023~~2024:

Revenues

Revenues ~~decreased~~increased $~~234~~1,837 million in ~~2024~~2025 compared to ~~2023~~2024. The ~~decrease~~increase was primarily due to (i) aan ~~$398~~increase ~~million decrease~~ in ~~product~~natural gas sales ~~driven~~of by$1,609 ~~lower~~million ~~volumes~~due ~~resulting~~to ~~primarily~~higher ~~from~~commodity ~~contractual~~prices ~~changes~~ and anvolumes ~~asset divestiture~~ and (ii) aan increase in services revenues of $~~326~~507 million ~~decrease~~resulting infrom ~~natural~~higher ~~gas~~volumes, ~~sales~~primarily ~~due~~driven toby ~~lower~~increased ~~commodity~~demand ~~prices~~for ~~partially~~services ~~offset~~and byexpansion projects placed into service, higher ~~volumes. These~~rates, ~~decreases~~and the Outrigger Energy assets acquired in ~~sales~~February ~~revenues~~2025. Revenues were ~~partially~~further ~~offset~~increased by a $4599 million ~~increase~~for inthe ~~other~~impacts ~~sales~~of ~~driven~~derivative bycontracts ~~higher~~used ~~RIN~~to hedge commodity sales. ~~Revenues~~ These increases in revenues were partially offset

4546

~~further reduced~~ by ~~$151~~decreased ~~million~~product ~~for~~sales ~~the impacts~~ of ~~derivative contracts used to hedge commodity sales which includes both realized and unrealized gains and losses from derivatives. Services revenues increased~~ $~~515~~423 million, driven by ~~(i)~~lower ~~higher~~commodity ~~volumes,~~prices ~~including from expansion projects; (ii) our late 2023 acquisition of the STX Midstream assets~~ partially offset by ahigher ~~reduction~~volumes, ~~in revenues related to divested assets;~~ and ~~(iii)~~asset ~~higher~~divestitures ~~rate~~in ~~escalations~~2024. The ~~decrease~~increase in sales revenues had a corresponding ~~decrease~~increase in our costs of sales as described below under “Operating Costs, Expenses, and Other—Costs of sales.”

Operating Costs, Expenses, and Other

Costs of Sales

Costs of sales ~~decreased~~increased $~~601~~1,192 million in ~~2024~~2025 compared to ~~2023~~2024. The ~~decrease~~increase, which ~~includes~~is net of the impact of our divested assets, was primarily due to ~~lower~~higher costs of sales for ~~(i)~~ natural gas of $~~447~~1,481 million primarily due to ~~lower~~higher commodity prices and volumes. The increase was partially offset by ~~higher~~(i) ~~volumes;~~lower ~~and~~costs ~~(ii)~~of sales for products of $~~269~~281 million driven ~~primarily~~ by lower ~~volumes~~commodity prices partially offset by anhigher ~~increase~~volumes and (ii) a decrease of $~~145~~51 million related to derivative contracts used to hedge commodity purchases ~~which includes both realized and unrealized gains and losses from derivatives~~.

Operations and Maintenance

Operations and maintenance increased $~~165~~85 million in ~~2024~~2025 compared to ~~2023~~2024. Increased costs were primarily driven by greater activity levels ~~and inflation~~, including ~~for~~from ~~service~~expansions, ~~integrity~~and inflation, including labor ~~and fuel~~ costs.

~~DD&A~~Other Income, net

~~DD&A~~Other ~~increased~~income, net decreased $~~104~~77 million in ~~2024~~2025 compared to ~~2023~~2024. The ~~increase~~decrease was primarily ~~due~~the toresult ~~our~~of ~~late~~gains ~~2023~~on ~~acquisition of~~ the ~~STX~~divestitures ~~Midstream~~of CO2 assets and ~~an increase in SACROC’s unit~~ of ~~production~~Oklahoma ~~rate~~midstream ~~partially~~assets ~~offset~~in ~~by the impact of our divested assets~~2024.

Other Income (Expense)

Interest, net

In the table above, we report our interest expense as “net,” meaning that we have subtracted interest income and capitalized interest from our total interest expense to arrive at one interest amount. ~~Our~~ ~~interest expense~~Interest, net ~~increased~~decreased $4743 million in ~~2024~~2025 compared to ~~2023~~2024. The ~~increase~~decrease was primarily due to ~~(i)~~lower ~~higher average short-term and long-term debt balances driven by funding our STX Midstream acquisition; and (ii) higher~~ interest rates associated with our fixed-to-variable interest rate swap agreements ~~and our long-term debt;~~ partially offset by ahigher ~~reduction~~average inbalances ~~the~~and ~~notional~~interest ~~balances~~rates ~~associated~~on ~~with~~ our ~~fixed~~long-~~to-variable~~term ~~interest rate swap agreements~~debt.

46Other, net

Other, net increased $146 million in 2025 compared to 2024. The increase was primarily the result of a gain on the sale of our equity interest in EagleHawk in 2025.

Non-GAAP Financial Measures

Reconciliations from Net Income Attributable to Kinder Morgan, Inc.

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions, except per share amounts)
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.
Net income attributable to Kinder Morgan, Inc.	$	23,~~613~~056	$	2,~~391~~613
Certain Items(a)
Change in fair value of derivative contracts	72		(126)
Risk management activities	(29)		72
(Gain) loss on divestitures and impairment, net	(69)		67
Gain on divestitures	(123)		(69)
Income tax Certain Items	(522)		33(52)
Other	7(3)		457
Total Certain Items	(42157)		19(42)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	2,~~571~~899	$	2,~~410~~571
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Common Stock
Net income attributable to Kinder Morgan, Inc.	$	23,~~613~~056	$	2,~~391~~613
Total Certain Items(b)	(42157)		19(42)
Net income allocated to participating securities and other(c)	(1415)		(14)
Adjusted Net Income Attributable to Common Stock	$	2,~~557~~884	$	2,~~396~~557
Adjusted EPS	$	1.1530	$	1.0715
Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted EBITDA
Net income attributable to Kinder Morgan, Inc.	$	23,~~613~~056	$	2,~~391~~613
Total Certain Items(b)	(42157)		19(42)
DD&A	2,~~354~~453		2,~~250~~354
Amortization of excess cost of equity investments	50		66
Income tax expense(d)	834		739
Income tax expense(d)	739		682
Interest, net(e)	1,788		1,849
Interest, net(e)	1,849		1,804
Amounts associated with joint ventures
Amounts from joint ventures
Unconsolidated joint venture DD&A(f)	391		409
Unconsolidated joint venture DD&A	359		323
Remove consolidated joint venture partners’ DD&A	(63)		(62)
Remove consolidated joint venture partners’ DD&A	(62)		(63)
Unconsolidated joint venture income tax expense(g)	89		78
Unconsolidated joint venture income tax expense(f)	78		89
Adjusted EBITDA	$	8,391	$	7,938
Adjusted EBITDA	$	7,938	$	7,561

(a)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(b)See “—Non-GAAP Financial Measures—Reconciliation of Net Income Attributable to Kinder Morgan, Inc. to Adjusted Net Income Attributable to Kinder Morgan, Inc.” for a detailed listing.

(c)Net income allocated to common stock and participating securities is based on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions over earnings to the extent that each security participates in earnings or excess distributions over earnings, as applicable. Other includes Adjusted net income in excess of distributions for participating securities of $1 million ~~and~~for ~~none~~each ~~for~~of ~~2024~~the 2025 and ~~2023,~~2024 ~~respectively~~periods.

(d)To avoid duplication, adjustments for income tax expense for ~~2024~~2025 and ~~2023~~2024 exclude $(522) million and $33(52) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above.

(e)To avoid duplication, adjustments for interest, net for ~~2024~~2025 and ~~2023~~2024 exclude $~~(5)~~13 million and $(75) million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.

(f)Includes ~~the~~amortization ~~tax~~of ~~provision~~basis ondifferences ~~Certain~~related ~~Items~~to ~~recognized by the investees that are taxable entities associated with~~ our ~~Citrus,~~joint ~~NGPL~~ventures ~~Holdings~~which ~~and~~was ~~Products~~previously ~~(SE)~~presented ~~Pipe~~separately ~~Line~~as ~~equity~~amortization ~~investments. The impact~~ of ~~KMI’s~~excess ~~income~~cost ~~tax~~of ~~provision on Certain Items affecting earnings from~~ equity investments ~~is included within “Certain Items” above~~.

47(g)Includes the tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings, and Products (SE) Pipe Line equity investments. The impact of KMI’s income tax provision on Certain Items affecting earnings from equity investments is included within “Certain Items” above.

Below is a discussion of significant changes in our Adjusted Net Income Attributable to Kinder Morgan, Inc. and Adjusted EBITDA:

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	2,~~571~~899	$	2,~~410~~571
Adjusted EBITDA	78,~~938~~391		7,~~561~~938
Change from prior period	Increase/(Decrease)
Adjusted Net Income Attributable to Kinder Morgan, Inc.	$	~~161~~328
Adjusted EBITDA	$	~~377~~453

Adjusted Net Income Attributable to Kinder Morgan, Inc. increased $~~161~~328 million in ~~2024~~2025 compared to ~~2023~~2024. The increase resulted primarily from favorable earnings in our Natural Gas Pipelines, and Terminals ~~and~~business ~~Products~~segments ~~Pipelines~~partially offset by unfavorable earnings in our CO2 business ~~segments~~segment, which were also primary drivers of the increase in Adjusted EBITDA of $~~377~~453 million~~, partially offset by an increase in DD&A expenses~~.

General and Administrative and Corporate Charges

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions)
General and administrative	$	(~~712~~744)	$	(~~668~~712)
Corporate charges	(242)		(9124)
Certain Items(a)	71		457
General and administrative and corporate charges	$	(~~729~~745)	$	(~~714~~729)
Change from prior period	Earnings increase/(decrease)
General and administrative	$	(4432)
Corporate charges	6722
Total	$	23(10)

(a)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.

General and administrative expenses increased $4432 million and corporate charges decreased $6722 million in ~~2024~~2025 compared to ~~2023~~2024. The combined changes primarily include ~~$41 million consisting of~~ higher ~~labor and~~ benefit-related ~~costs, higher legal costs~~ and ~~higher~~labor ~~corporate development~~ costs, partially offset by lower pension costs ~~of $30 million~~. In addition, the combined changes described above include $7 million of costs in 2024 and the impact of increased pension costs of $45 million in 2023 related to settlements made by our pension plans, which we treated as Certain Items.

Reconciliation of Segment EBDA to Adjusted Segment EBDA

	Year Ended December 31,
	2024		2023
	(In millions)
Segment EBDA(a)
Natural Gas Pipelines Segment EBDA	$	5,427	$	5,282
Certain Items(b)
Change in fair value of derivative contracts	75		(122)
Gain on divestiture	(29)		—
Natural Gas Pipelines Adjusted Segment EBDA	$	5,473	$	5,160
Products Pipelines Segment EBDA	$	1,173	$	1,062
Certain Items(b)
Change in fair value of derivative contracts	—		(1)
Loss on impairment	—		67
Products Pipelines Adjusted Segment EBDA	$	1,173	$	1,128
Terminals Segment EBDA	$	1,099	$	1,040
CO2 Segment EBDA	$	692	$	689
Certain Items(b)
Change in fair value of derivative contracts	2		4
Gain on divestitures	(40)		—
CO2 Adjusted Segment EBDA	$	654	$	693

(a)Includes revenues, earnings from equity investments, operating expenses, other income, net, and other, net. Operating expenses include costs of sales, operations and maintenance expenses, and taxes, other than income taxes. See “—Overview—GAAP Financial Measures” above.

(b)See “—Overview—Non-GAAP Financial Measures—Certain Items” above.

Segment Earnings Results

Natural Gas Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions, except operating statistics)
Revenues	$	811,~~942~~009	$	98,~~168~~942
Costs of sales	(24,~~837~~299)		(32,~~258~~837)
Other operating expenses	(1,519)		(1,442)
Other operating expenses(a)	(1,606)		(1,519)
Other income	478		1247
Earnings from equity investments	~~782~~817		~~776~~748
Other, net	12151		2612
Segment EBDA	56,~~427~~080		5,~~282~~393
Certain Items:
Change in fair value of derivative contracts	75		(122)
Risk management activities	(39)		75
Gain on divestiture	(29)		—
Gain on divestitures	(123)		(29)
Certain Items(a)	46		(122)
Other	(4)		—
Adjusted Segment EBDA	$	5,473	$	5,160
Certain Items(b)	(166)		46
Adjusted Segment EBDA	$	5,914	$	5,439
Change from prior period	Increase/(Decrease)
Segment EBDA	$	~~145~~687
Adjusted Segment EBDA	$	~~313~~475
Volumetric data(b)
Volumetric data(c)
Transport volumes (BBtu/d)	44,252		44,132
Natural Gas Transport (BBtu/d)	46,603		44,252
Sales volumes (BBtu/d)	2,576		2,346
Natural Gas Sales (BBtu/d)	3,302		2,627
Gathering volumes (BBtu/d)	3,922		3,710
Gathering (BBtu/d)	4,025		3,862
NGL (MBbl/d)	38		34
NGL Transport (MBbl/d)	38		38

(a)~~See~~Operating ~~table~~expenses ~~included~~include inoperations ~~“—Overview—Non-GAAP Financial Measures—Certain Items” above. 2024~~ and ~~2023~~maintenance ~~Certain~~expenses ~~Items of $46 million~~ and ~~$(122) million~~taxes, ~~respectively,~~other ~~are~~than ~~associated~~income ~~with our Midstream business~~taxes. ~~For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.~~

(b)~~Joint~~See ~~venture~~table ~~throughput~~included isin ~~reported~~“—Overview—Non-GAAP atFinancial ~~our~~Measures—Certain ~~ownership~~Items” ~~share~~above. ~~Volumes~~2025 ~~for~~and ~~acquired~~2024 ~~assets~~Certain ~~are~~Items ~~included~~of ~~for~~(i) ~~all~~$(162) ~~periods~~million ~~presented. However~~and $46 million, ~~EBDA~~respectively, ~~contributions~~are ~~from~~associated ~~acquisitions~~with ~~are~~our ~~included~~Midstream ~~only~~business and (ii) $(4) million for the ~~periods~~2025 ~~subsequent~~period tois ~~their~~associated ~~acquisition~~with our East business. ~~Volumes~~See ~~for~~“—Overview—Non-GAAP ~~assets~~Financial ~~sold~~Measures—Certain ~~are~~Items” ~~excluded~~above. ~~for~~For ~~all~~more ~~periods~~detail ~~presented~~of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)Joint venture throughput is reported at our ownership share. Volumes for acquired assets are included for all periods presented. However, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

Below are the changes in Natural Gas Pipelines Segment EBDA:

	Year Ended December 31,
	2024		2023		increase/(decrease)
	2025		2024		Increase/(Decrease)
	(In millions)
Midstream	$	12,~~799~~278	$	1,~~697~~783	$	~~102~~495
East	2,~~678~~821		2,~~637~~660		41161
West	~~950~~981		~~948~~950		231
Total Natural Gas Pipelines	$	56,~~427~~080	$	5,~~282~~393	$	~~145~~687

The changes in Natural Gas Pipelines Segment EBDA in the comparable years of ~~2024~~2025 and ~~2023~~2024 are explained by the following discussion:

•The $~~102~~495 million (628%) increase in Midstream was ~~favorably~~primarily ~~impacted~~driven by (i) ~~our STX Midstream acquired assets partially offset by our divested assets; (ii) increased demand and rates for our services~~ on our Texas intrastate systems, ~~and~~completed ~~increased~~expansion ~~sales~~projects ~~margin~~and ~~driven~~increased ~~by lower prices on costs of~~ sales ~~and~~margins ~~higher~~resulting ~~volumes,~~from ~~partially offset by~~ higher ~~operating~~commodity ~~expenses;~~prices and ~~(iii)~~volumes ~~higher equity earnings from PHP driven by an expansion project that went into service in November 2023. These increases were~~ partially ~~offset~~reduced by ~~(i)~~decreased ~~lower~~realized ~~sales~~gains ~~margin~~ on ~~our~~sales ~~Altamont assets driven by higher prices on NGL purchases and higher natural gas purchase volumes related to contract re-negotiations~~hedges; (ii) ~~lower~~contributions ~~sales~~from ~~margin~~the onacquired ~~our~~Outrigger ~~South~~Energy ~~Texas~~ assets ~~due~~on toour ~~lower~~Hiland ~~volumes~~Midstream ~~partially offset by higher NGL prices~~assets; and (iii) ~~lower~~higher ~~natural~~gathering ~~gas~~rates ~~sales margin~~ on ~~our~~KinderHawk. ~~Hiland~~Overall, Midstream’s ~~assets~~revenue aschanges aare ~~result~~partially ofoffset ~~lower~~by ~~prices~~corresponding ~~and~~changes ~~a reduction~~ in ~~gathering~~costs ~~revenues~~of ~~from lower volumes partially offset by higher rates~~sales.

In addition, the increase in Midstream ~~was~~includes ~~affected~~a bygain ~~(i)~~on ~~non-cash~~the ~~mark-to-market~~sale ~~derivative~~of ~~contracts~~our ~~used~~equity tointerest ~~hedge~~in ~~forecasted~~EagleHawk ~~commodity~~in ~~sales~~2025 and ~~purchases,~~increased ~~which~~revenues ~~increased~~and decreased costs of sales associated with risk management activities related to non-cash changes in fair value of unsettled derivative contracts and ~~decreased~~realized ~~revenues;~~gains and ~~(ii)~~losses on settled natural gas inventory hedge contracts, partially offset by a gain on sale of our Oklahoma assets in the 2024 period, all of which we treated as Certain Items.

~~Overall~~•The $161 million (6%) increase in East was primarily driven by, ~~Midstream’s~~on ~~revenue~~TGP, ~~changes~~(i) ~~are~~completed expansion projects; (ii) higher services demand due to weather and higher LNG exports and power demand; (iii) higher park and loan demand due to market volatility; and (iv) lower legal costs, partially offset by ~~corresponding~~higher ~~changes~~pipeline inmaintenance costs. The increase was further driven by higher equity earnings from (i) MEP resulting from increased rates; (ii) Citrus primarily driven by projects that went into service; and (iii) NGPL primarily as a result of ~~sales~~higher volumes and rates and expansion projects, partially offset by an expired customer agreement on our Stagecoach assets and lower equity earnings from SNG primarily driven by higher operating and legal costs.

•The $4131 million (23%) increase in ~~East~~West ~~was~~resulted ~~impacted~~primarily byfrom ~~(i) expansion projects on TGP that went into service in July 2024 and November 2023 partly offset by its higher operating costs and an increase in legal reserves; and (ii)~~ increased demand for services on ~~our Stagecoach assets~~CPGPL. These increases were also partially offset by (i) lower equity earnings from MEP driven by lower contracted rates; and (ii) timing of revenue recognition associated with a prepaid customer contract on SLNG.

•The $2 million (—%) increase in West was primarily due to increased demand for services on CPGPL and WIC, and an insurance settlement received by EPNG in the 2024 period. These increases were largely offset by lower gas sales margin and higher operating and maintenance costs on EPNG.

Products Pipelines (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions, except operating statistics)
Revenues	$	2,~~955~~686	$	32,~~066~~955
Costs of sales	(1,~~394~~112)		(1,~~588~~394)
Other operating expenses	(456)		(436)
Other operating expenses(a)	(476)		(456)
Other income (expense)	1		(4)
Other income	1		1
Earnings from equity investments	6658		2357
Other, net	1—		1
Segment EBDA	1,~~173~~157		1,~~062~~164
Certain Items:
Change in fair value of derivative contracts	—		(1)
Risk management activities	1		—
Loss on impairment	—		67
Certain Items(b)	1		—
Certain Items(a)	—		66
Adjusted Segment EBDA	$	1,158	$	1,164
Adjusted Segment EBDA	$	1,173	$	1,128
Change from prior period	Increase/(Decrease)
Segment EBDA	$	~~111~~(7)
Adjusted Segment EBDA	$	45(6)
Volumetric data(b)
Volumetric data(c)
Gasoline(c)	977		980
Gasoline(d)	970		980
Diesel fuel	~~361~~359		~~351~~352
Jet fuel	~~294~~307		~~285~~300
Total refined product volumes	1,~~632~~636		1,~~616~~632
Crude and condensate	~~471~~465		~~483~~471
Total delivery volumes (MBbl/d)	2,~~103~~101		2,~~099~~103

(a)~~See~~Operating ~~table~~expenses ~~included~~include inoperations ~~“—Overview—Non-GAAP Financial Measures—Certain Items” above. 2023 Certain Items of (i) $(1) million is associated with our Southeast Refined Products business~~ and ~~(ii)~~maintenance ~~$67~~expenses ~~million is associated with our Crude~~ and ~~Condensate business. For more detail of significant Certain Items~~taxes, ~~see~~other ~~the~~than ~~discussion~~income ~~of changes in Segment EBDA below~~taxes.

(b)~~Joint~~See ~~venture~~table ~~throughput~~included isin ~~reported~~“—Overview—Non-GAAP atFinancial Measures—Certain Items” above. 2025 Certain Items are associated with our ~~ownership~~Southeast ~~share~~Refined Products business. See “—Overview—Non-GAAP Financial Measures—Certain Items” above. For more detail of significant Certain Items, see the discussion of changes in Segment EBDA below.

(c)~~Volumes~~Joint ~~include~~venture ~~ethanol~~throughput ~~pipeline~~is ~~volumes~~reported at our ownership share.

(d)Volumes include ethanol pipeline volumes.

Below are the changes in Products Pipelines Segment EBDA:

	Year Ended December 31,
	2024		2023		increase/(decrease)
	2025		2024		Increase/(Decrease)
	(In millions)
West Coast Refined Products	$	604	$	519	$	85
Crude and Condensate	$	236	$	280	$	(44)
Crude and Condensate	280		265		15
West Coast Refined Products	628		604		24
Southeast Refined Products	~~289~~293		~~278~~280		1113
Total Products Pipelines	$	1,~~173~~157	$	1,~~062~~164	$	~~111~~(7)

The changes in Products Pipelines Segment EBDA in the comparable years of ~~2024~~2025 and ~~2023~~2024 are explained by the following discussion:

•The $8544 million (16%) ~~increase~~decrease in ~~West~~Crude ~~Coast~~and ~~Refined~~Condensate ~~Products~~was ~~resulted~~driven ~~from~~by ~~higher~~the ~~transportation~~expiration ~~rates~~of ~~and~~legacy ~~volumes~~crude contracts in

~~and~~advance ~~increased~~of ~~renewable~~the ~~diesel~~Double ~~terminal~~H ~~activity~~pipeline conversion to NGL service on our ~~Pacific~~Bakken ~~operations~~Crude assets, lower margin from our Crude and Condensate business resulting primarily from decreased spreads, and a planned ten-year turnaround in the first quarter 2025 at our KM Condensate Processing facility.

•The $1524 million (64%) increase in ~~Crude~~West ~~and~~Coast ~~Condensate~~Refined ~~was~~Products ~~impacted~~resulted byfrom anhigher ~~increase~~rates ofat ~~$67~~our ~~million~~West toCoast ~~equity~~Terminals, ~~earnings~~and ~~for~~Pacific aoperations, ~~non-cash~~partially ~~impairment~~offset inby ~~the~~higher ~~2023~~pipeline ~~period~~maintenance ~~related~~costs toand ~~our~~unfavorable ~~investment~~changes in ~~Double~~product ~~Eagle Pipeline LLC, which we treated as a Certain Item~~gains.

In•The ~~addition,~~$13 ~~Crude~~million ~~and~~(5%) ~~Condensate~~increase ~~was unfavorably impacted by a decrease~~ in ~~equity~~Southeast ~~earnings~~Refined ~~from~~Products ~~Double~~was ~~Eagle~~primarily ~~Pipeline~~driven ~~LLC,~~by ~~excluding~~higher ~~the~~volumes ~~impairment discussed above, due to unfavorable recontracting~~ and, rates on ~~Bakken~~Central ~~Crude~~Florida ~~assets,~~Pipeline ~~lower~~LLC ~~gathering volumes partially offset by higher transportation rates. Our Crude~~ and ~~Condensate business also had~~ lower ~~revenues~~prices ~~with~~on ~~a corresponding decrease in~~ costs of sales, ~~resulting~~at ~~primarily~~our ~~from~~Transmix ~~decreased~~processing ~~sales volumes~~operations.

•The $11 million (4%) increase in Southeast Refined Products was driven by an increase in equity earnings from Products (SE) Pipe Line primarily due to higher rates and higher butane blending sales volumes at our South East Terminals.

Terminals

	Year Ended December 31,
	2024			2023
	2025			2024
	(In millions, except operating statistics)
Revenues	$	2,~~022~~104		$	12,~~917~~022
Costs of sales	(4250)			(3342)
Other operating expenses	(904)			(863)
Other operating expenses(a)	(915)			(904)
Other income	54			25
Earnings from equity investments	8			9
(Loss) earnings from equity investments	(2)			8
Other, net	102			810
Segment EBDA	$	1,~~099~~143		$	1,~~040~~099
Change from prior period	Increase/(Decrease)
Segment EBDA	$	5944
Volumetric data(a)
Volumetric data(b)
Liquids leasable capacity (MMBbl)	78.67			78.76
Liquids utilization %(b)	94.6		%	93.6		%
Liquids utilization %(c)	94.1		%	94.6		%
Bulk transload tonnage (MMtons)	5349.75			53.37

(a)~~Volumes~~Operating ~~for~~expenses ~~facilities~~include ~~divested,~~operations ~~idled,~~ and~~/or~~ ~~held~~maintenance ~~for~~expenses ~~sale~~and ~~are~~taxes, ~~excluded~~other ~~for~~than ~~all~~income ~~periods presented~~taxes.

(b)~~The~~Volumes ~~ratio~~for offacilities ~~our~~divested, ~~tankage~~idled, ~~capacity~~and/or inheld ~~service~~for tosale ~~liquids~~are ~~leasable~~excluded ~~capacity~~for all periods presented.

~~For~~(c)The ~~purposes~~ratio of ~~the following tables and related discussions, the results of operations of~~ our ~~terminals~~tankage ~~held~~capacity ~~for~~in ~~sale~~service orto ~~divested,~~liquids ~~including~~leasable ~~any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping and included within the Other group~~capacity.

For purposes of the following tables and related discussions, in periods in which they may occur, the results of operations of our terminals divested or classified as held for sale, including any associated gain or loss on sale, are reclassified for all periods presented from the historical business grouping and included within the Other group.

Below are the changes in Terminals Segment EBDA:

	Year Ended December 31,
	2024		2023		increase/(decrease)
	2025		2024		Increase/(Decrease)
	(In millions)
Liquids	$	633	$	601	$	32
Jones Act tankers	$	240	$	195	$	45
Jones Act tankers	195		177		18
Liquids	656		633		23
Bulk	~~267~~247		~~256~~267		11(20)
Other	4—		64		(24)
Total Terminals	$	1,~~099~~143	$	1,~~040~~099	$	5944

The changes in Terminals Segment EBDA in the comparable years of ~~2024~~2025 and ~~2023~~2024 are explained by the following discussion:

•The $3245 million (523%) increase in ~~Liquids~~Jones ~~was~~Act ~~primarily~~tankers ~~driven~~was ~~by (i) contributions from expansion projects; (ii) higher throughput and ancillary fees~~ primarily atdue ~~our~~to ~~Houston Ship Channel hub facilities; and (iii)~~ higher ~~rates~~average ~~and~~charter ~~utilization, primarily at our New York Harbor hub facilities, partially offset by higher labor and maintenance expenses~~rates.

•The $1823 million (104%) increase in ~~Jones~~Liquids ~~Act~~was ~~tankers~~driven ~~was~~by ~~primarily~~higher ~~due~~rates toand ~~higher~~ancillary ~~average~~fees ~~charter~~at ~~rates~~our Houston Ship Channel facilities and contributions from expansion projects, partially offset by lower ~~operating~~equity ~~costs~~earnings resulting from an impairment of an equity investment in the 2025 period.

•The $1120 million (47%) ~~increase~~decrease in Bulk was primarily ~~due~~driven toby ~~increased~~the ~~volume~~impact ~~and~~of ~~related~~the ~~handling~~2025 ~~and~~closure ~~ancillary~~of ~~charges~~LyondellBasell’s ~~for~~Houston ~~petroleum~~refinery ~~coke,~~on ~~coal,~~our ~~soda~~petroleum ~~ash~~coke ~~and~~handling ~~fertilizer. These~~operations ~~increases were~~ partially offset by ~~higher~~decreased ~~labor and maintenance expenses and~~ demurrage costs ~~incurred~~ at our International Marine Terminal.

CO2 (including reconciliation of Segment EBDA to Adjusted Segment EBDA)

	Year Ended December 31,
	2024		2023
	2025		2024
	(In millions, except operating statistics)
Revenues	$	1,~~204~~170	$	1,~~209~~204
Costs of sales	(8294)		(7782)
Other operating expenses	(504)		(473)
Other operating expenses(a)	(487)		(504)
Other income	40—		—40
Earnings from equity investments	3423		3027
Segment EBDA	~~692~~612		~~689~~685
Certain Items:
Change in fair value of derivative contracts	2		4
Risk management activities	(4)		2
Gain of divestitures	(40)		—
Gain on divestitures	—		(40)
Certain Items(a)	(38)		4
Certain Items(b)	(4)		(38)
Adjusted Segment EBDA	$	~~654~~608	$	~~693~~647
Change from prior period	Increase/(Decrease)
Segment EBDA	$	3(73)
Adjusted Segment EBDA	$	(39)
Volumetric data(b)
Volumetric data(c)
SACROC oil production	1918.0170		2019.2201
Yates oil production	65.1395		6.6313
Other	1.0211		1.0817
Total oil production, net (MBbl/d)(c)	26.16		27.93
Total oil production, net (MBbl/d)(d)	25.76		26.31
NGL sales volumes, net (MBbl/d)(c)	8.57		8.97
NGL sales volumes, net (MBbl/d)(d)	8.97		8.56
CO2 sales volumes, net (Bcf/d)	0.~~322~~297		0.~~336~~322
RNG sales volumes (BBtu/d)	911		69
Realized weighted average oil price ($ per Bbl)	$	6867.4651	$	6768.4246
Realized weighted average NGL price ($ per Bbl)	$	3032.8343	$	30.8483

(a)~~See~~Operating ~~table~~expenses ~~included~~include inoperations ~~“—Overview—Non-GAAP Financial Measures—Certain Items” above. 2024~~ and ~~2023~~maintenance ~~Certain~~expenses ~~Items are associated with our Oil~~ and ~~Gas Producing activities. For more detail of significant Certain Items~~taxes, ~~see~~other ~~the~~than ~~discussion~~income ~~of changes in Segment EBDA below~~taxes.

(b)~~Volumes~~See ~~for~~table ~~acquired~~included ~~assets~~in ~~are~~“—Overview—Non-GAAP ~~included~~Financial ~~for~~Measures—Certain ~~all~~Items” ~~periods~~above. ~~presented,~~2025 ~~however,~~and ~~EBDA~~2024 ~~contributions~~Certain ~~from~~Items ~~acquisitions~~ are ~~included~~associated ~~only~~with ~~for~~our ~~the~~Oil ~~periods~~and ~~subsequent~~Gas toProducing ~~their~~activities. ~~acquisition~~See “—Overview—Non-GAAP Financial Measures—Certain Items” above. ~~Volumes~~ ~~for~~For ~~assets~~more ~~sold~~detail ~~are~~of ~~excluded~~significant ~~for~~Certain ~~all~~Items, ~~periods~~see ~~presented~~the discussion of changes in Segment EBDA below.

(c)~~Net~~Volumes offor ~~royalties~~acquired ~~and~~assets ~~outside~~are ~~working~~included ~~interests~~for all periods presented, however, EBDA contributions from acquisitions are included only for the periods subsequent to their acquisition. Volumes for assets sold are excluded for all periods presented.

(d)Net of royalties and outside working interests.

Below are the changes in CO2 Segment EBDA:

	Year Ended December 31,
	2024		2023		increase/(decrease)
	2025		2024		Increase/(Decrease)
	(In millions)
Oil and Gas Producing activities	$	447	$	473	$	(26)
Source and Transportation activities	$	155	$	193	$	(38)
Source and Transportation activities	195		187		8
Oil and Gas Producing activities	414		447		(33)
Subtotal	~~642~~569		~~660~~640		(1871)
Energy Transition Ventures	5043		2945		21(2)
Total CO2	$	~~692~~612	$	~~689~~685	$	3(73)

The changes in CO2 Segment EBDA in the comparable years of ~~2024~~2025 and ~~2023~~2024 are explained by the following discussion:

•The $2638 million (520%) decrease in ~~Oil~~Source and ~~Gas~~Transportation ~~Producing~~ activities ~~resulted~~was ~~primarily~~driven ~~from~~by ~~(i)~~ lower ~~crude~~realized ~~oil~~CO2 ~~volumes;~~sales ~~(ii)~~prices ~~our divested assets;~~ and ~~(iii)~~volumes ~~higher power costs. These decreases were~~ partially offset by, on our ~~acquired~~Wink ~~assets~~pipeline, ~~and~~ higher ~~realized crude oil prices~~volumes.

In•The ~~addition,~~$33 million (7%) decrease in Oil and Gas Producing activities was ~~favorably~~driven ~~impacted~~ by ~~(i)~~ a $40 million gain on sale of oil and gas producing fields; ~~and~~in ~~(ii)~~the 2024 period and non-cash mark-to-market derivative hedge contracts, which increased revenues, all of which we treated as Certain Items.

~~•The~~In $8addition, ~~million~~Oil ~~(4%) increase in Source~~ and ~~Transportation~~Gas Producing activities ~~was~~had ~~primarily~~favorable contributions due to (i) higher ~~volumes~~realized inNGL ~~2024,~~prices ~~resulting~~and ~~from~~volumes; a(ii) ~~refinery~~lower ~~outage~~power incosts; ~~2023 on our Wink pipeline,~~ and ~~lower~~(iii) ~~integrity~~assets ~~maintenance~~acquired ~~costs~~ in June 2024~~. These~~, ~~increases were~~ partially offset by lower ~~CO2~~crude ~~sales~~oil volumes and ~~realized~~assets ~~prices~~divested in June 2024.

•The $212 million (724%) ~~increase~~decrease in Energy Transition Ventures activities was primarily due to ~~higher~~lower RIN sales ~~margin~~prices ~~resulting~~and ~~from~~higher ~~increased~~operating ~~volumes~~and ~~partially~~maintenance costs offset by higher ~~operating~~RIN ~~expenses~~sales volumes generated from our RNG business.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price sensitivities in the near-term and to lesser extent over the following few years from price exposure. Below is a summary of our CO2 business segment hedges outstanding as of December 31, ~~2024~~2025.

	2025		2026		2027		2028
	2026		2027		2028
Crude Oil(a)
Price ($ per Bbl)	$	6664.6134	$	6564.9413	$	6564.7151	$	~~64.55~~
Volume (MBbl/d)	2021.9060		1312.4020		84.1000		~~3.70~~
NGL
Price ($ per Bbl)	$	4842.9860
Volume (MBbl/d)	32.1356

(a)Includes WTI.

Liquidity and Capital Resources

General

As of December 31, ~~2024~~2025, we had $8863 million of “Cash and cash equivalents,” ana ~~increase~~decrease of $525 million from December 31, ~~2023~~2024. Additionally, as of December 31, ~~2024~~2025, we had borrowing capacity of approximately $3.1,477 ~~billion~~million under our credit facility (discussed below in “—Short-term Liquidity”). As discussed further below, we believe our cash flows from operating activities, cash position, and remaining borrowing capacity on our credit facility is more than adequate to allow us to manage our day-to-day cash requirements and anticipated obligations.

We have consistently generated substantial cash flow from operations, providing a source of funds of $5,~~635~~917 million and $65,~~491~~635 million in ~~2024~~2025 and ~~2023~~2024, respectively. The year-to-year ~~decrease~~increase is discussed below in “—Cash Flows—Operating Activities.” We primarily rely on cash provided by operations to fund our operations as well as our debt service, sustaining capital expenditures, dividend payments, and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time,

capital expenditures, dividend payments and our growth capital expenditures; however, we may access the debt capital markets from time to time to refinance our maturing long-term debt and finance incremental investments, if any. From time to time, short-term borrowings are used to fund working capital and finance incremental capital investments, if any. Incremental capital investments initially funded through short-term borrowings may periodically be replaced with long-term financing and/or paid down using retained cash from operations. In aggregate, we repaid $1,500 million and issued $1,850 million of senior notes in 2025.

Our ~~Board~~board of directors declared a quarterly dividend of $0.~~2875~~2925 per share for the fourth quarter of ~~2024~~2025, consistent with previous quarters in ~~2024~~2025. The total of the dividends declared for ~~2024~~2025 of $1.1517 represents a 2% increase over total dividends declared for ~~2023~~2024.

WeFor ~~use~~additional ~~interest~~information ~~rate~~about ~~swap agreements to convert a portion of the underlying cash flows related to~~ our ~~long-term~~outstanding ~~fixed-rate debt securities (~~senior notes) ~~into~~and ~~variable~~debt-~~rate~~related ~~debt~~transactions in ~~order to achieve our desired mix of fixed and variable rate debt. As of December 31~~2025, ~~2024~~see ~~and~~Note ~~2023, $3,621 million (11%) and $~~8~~,253~~ ~~million~~“Debt” ~~(26%),~~to ~~respectively, of the principal amount of~~ our ~~debt~~consolidated ~~balances~~financial ~~were~~statements. ~~subject~~For toinformation ~~variable~~about ~~interest~~our ~~rates—either as short-term or long-term variable-rate debt obligations or as fixed-rate debt converted to variable rates through the use of~~ interest rate ~~swaps. The amounts at December 31~~risk, ~~2024~~see ~~and~~Note ~~2023~~13 ~~include~~“Risk ~~$3,250 million~~Management—Interest ~~and~~Rate ~~$6,200 million,~~Risk ~~respectively,~~Management” ofto ~~interest~~our ~~rate~~consolidated ~~swap~~financial ~~agreements~~statements and ~~$331~~Item ~~million and $1,989 million, respectively, of commercial paper notes~~7A. ~~The~~ ~~interest~~“Quantitative ~~rate~~and ~~swap~~Qualitative ~~agreements~~Disclosures asAbout ofMarket ~~December 31,~~Risk—Interest ~~2024~~Rate ~~are net of $1,500 million of variable-to-fixed interest rate swap agreements which expire December 2025~~Risk.”

On February 1, 2024, we issued, in a registered offering, two series of senior notes consisting of $1,250 million aggregate principal amount of 5.00% senior notes due 2029 and $1,000 million aggregate principal amount of 5.40% senior notes due 2034 for combined net proceeds of $2,230 million, which were used to repay short-term borrowings, to fund maturing debt and for general corporate purposes.

On July 31, 2024, we issued, in a registered offering, two series of senior notes consisting of $500 million aggregate principal amount of 5.10% senior notes due 2029 and $750 million aggregate principal amount of 5.95% senior notes due 2054 and received combined net proceeds of $1,235 million, which were used to repay short-term borrowings, to fund maturing debt and for general corporate purposes.

During the year ended December 31, 2024, upon maturity, we repaid our 4.15% senior notes, our 4.30% senior notes and our 4.25% senior notes.

For additional information about our outstanding senior notes and debt-related transactions in 2024, see Note 8 “Debt” to our consolidated financial statements. For information about our interest rate risk, see Note 13 “Risk Management—Interest Rate Risk Management” to our consolidated financial statements and Item 7A. “Quantitative and Qualitative Disclosures About Market Risk—Interest Rate Risk.”

Short-term Liquidity

As of December 31, ~~2024~~2025, our principal sources of short-term liquidity are (i) cash from operations; and (ii) our $3.5 billion credit facility with an available capacity of approximately $3.1,477 ~~billion~~million and an associated $3.5 billion commercial paper program. The loan commitments under our credit facility can be used for working capital and other general corporate purposes and as a backup to our commercial paper program. Commercial paper borrowings and letters of credit reduce borrowings allowed under our credit facility. We provide for liquidity by maintaining a sizable amount of excess borrowing capacity under our credit facility and, as previously discussed, have consistently generated strong cash flows from operations.

As of December 31, ~~2024~~2025, our $21,~~009~~226 million of short-term debt consisted primarily of senior notes that mature in the next twelve months ~~and commercial paper borrowings~~. We intend to fund our debt as it becomes due, primarily through credit facility borrowings, commercial paper borrowings, cash flows from operations, and/or issuing new long-term debt. Our short-term debt ~~balance~~ as of December 31, ~~2023~~2024 was $42,~~049~~009 million.

We had working capital (defined as current assets less current liabilities) deficits of $21,~~580~~568 million and $42,~~679~~580 million as of December 31, ~~2024~~2025 and ~~2023~~2024, respectively. The overall $21,~~099~~012 million favorable change from year-end ~~2023~~2024 was primarily due to (i) a $~~1,658~~425 million decrease in ~~commercial~~current ~~paper~~maturities ~~borrowings~~of ~~resulting~~senior ~~from~~notes; ~~refinancing~~(ii) a ~~portion~~$318 million ofdecrease ~~our~~in ~~short-term~~commercial paper borrowings ~~into~~partly ~~long-term~~due ~~debt~~to ~~with~~repayments ~~the~~made ~~issuance~~using ofproceeds ~~senior~~received ~~notes~~from our Eaglehawk divestiture in ~~2024~~2025; (iiiii) a $~~400~~195 million ~~decrease~~net infavorable ~~long-term~~change ~~debt maturing~~ in ~~the~~our ~~next~~accounts ~~twelve~~receivables ~~months~~and payables; and (~~iii~~iv) a $~~113~~140 million ~~increase~~favorable change in ~~restricted~~fair ~~deposits~~value ~~primarily~~of ~~associated with~~ our short-term derivative ~~collateral~~contract ~~requirements~~assets and liabilities. Generally, ~~partially~~our ~~offset~~working bycapital avaries ~~$111~~due ~~million~~to ~~net~~factors ~~unfavorable~~such ~~change~~as the timing of scheduled debt payments, timing differences in ~~our~~the ~~accounts~~collection and payment of receivables and payables~~. Generally~~, the change in fair value of our ~~working~~derivative ~~capital~~contracts, ~~varies~~and ~~due~~changes toin ~~factors~~our ~~such~~cash and cash equivalents as ~~the~~a ~~timing~~result of ~~scheduled~~excess ~~debt~~cash from operations after payments, ~~timing~~for investing and financing activities (discussed below in “—Long-term Financing” and “—Capital Expenditures”).

57We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances, or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.

differences in the collection and payment of receivables and payables, the change in fair value of our derivative contracts and changes in our cash and cash equivalent balances as a result of excess cash from operations after payments for investing and financing activities (discussed below in “—Long-term Financing” and “—Capital Expenditures”).

We employ a centralized cash management program for our U.S.-based bank accounts that concentrates the cash assets of our wholly owned subsidiaries in joint accounts for the purpose of providing financial flexibility and lowering the cost of borrowing. These programs provide that funds in excess of the daily needs of our wholly owned subsidiaries are concentrated, consolidated or otherwise made available for use by other entities within the consolidated group. We place no material restrictions on the ability to move cash between entities, payment of intercompany balances or the ability to upstream dividends to KMI other than restrictions that may be contained in agreements governing the indebtedness of those entities.

Credit Ratings and Capital Market Liquidity

We believe that our capital structure will continue to allow us to achieve our business objectives. We expect that our short-term liquidity needs will be met primarily through retained cash from operations or short-term borrowings. Generally, we anticipate re-financing maturing long-term debt obligations in the debt capital markets and are therefore subject to certain market conditions which could result in higher costs or negatively affect our and/or our subsidiaries’ credit ratings. A decrease in our credit ratings could negatively impact our borrowing costs and could limit our access to capital.

~~The following table represents our debt ratings as of December 31, 2024.~~57

Rating agency

Short-term rating

Long-term rating

Outlook

Standard and Poor’s(a)

A-2

BBB

Stable

Moody’s Investor Services

Prime-2

Baa2

Stable

Fitch Ratings, Inc.

BBB

Stable

The following table represents our debt ratings as of December 31, 2025.

(a)On February 12, 2025, Standard and Poor’s upgraded our outlook to positive.

Rating agency

Short-term rating

Long-term rating

Outlook

Standard and Poor’s(a)

A-2

BBB

Positive

Moody’s Investor Services

Prime-2

Baa2

Positive

Fitch Ratings, Inc.

BBB+

Stable

(a)On January 13, 2026, Standard and Poor’s upgraded our long-term rating to BBB+.

Long-term Financing

Our equity consists of Class P common stock with a par value of $0.01 per share. We do not expect to need to access the equity capital markets to fund our discretionary capital investments for the foreseeable future. See also “—Dividends and Stock Buy-back Program” below for additional discussion related to our dividends and stock buy-back program.

From time to time, we issue long-term debt securities, often referred to as senior notes. Our senior notes issued to date, other than those issued by certain of our subsidiaries, generally have very similar terms, except for interest rates, maturity dates, and prepayment premiums. All of our fixed rate senior notes provide that the notes may be redeemed at any time at a price equal to 100% of the principal amount of the notes plus accrued interest to the redemption date, and, in most cases, plus a make-whole premium. In addition, from time to time, our subsidiaries issue long-term debt securities. We use interest rate swap agreements to convert a portion of the underlying cash flows related to our long-term fixed-rate debt securities (senior notes) into variable-rate debt in order to achieve our desired mix of fixed and variable rate debt. We and almost all of our direct and indirect wholly owned domestic subsidiaries are parties to a cross guaranty wherein each party guarantees each other party’s debt. See “—Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries.” As of December 31, ~~2024~~2025 and ~~2023~~2024, the aggregate principal amount outstanding of our various long-term debt obligations (excluding current maturities) was $2930,~~779~~597 million and $2729,~~880~~779 million, respectively.

Capital Expenditures

We account for our capital expenditures in accordance with GAAP. Additionally, we distinguish between capital expenditures as follows:


Type of Expenditure						Physical Determination of Expenditure
Sustaining capital expenditures						•Investments to maintain the operational integrity and extend the useful life of our assets
Expansion capital expenditures (discretionary capital expenditures)						•Investments to expand throughput or capacity from that which existed immediately prior to the making or acquisition of additions or improvements

Budgeting of maintenance capital expenditures, which we refer to as sustaining capital expenditures, is done annually on a bottom-up basis. For each of our assets, we budget for and make those sustaining capital expenditures that are necessary to maintain safe and efficient operations, meet customer needs and comply with our operating policies and applicable law. We may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion, and amortization over the remaining useful lives of the impacted or resulting assets.

may budget for and make additional sustaining capital expenditures that we expect to produce economic benefits such as increasing efficiency and/or lowering future expenses. Budgeting and approval of expansion capital expenditures generally occurs periodically throughout the year on a project-by-project basis in response to specific investment opportunities identified by our business segments from which we generally expect to receive sufficient returns to justify the expenditures. Assets comprising expansion capital projects could result in additional sustaining capital expenditures over time. The need for sustaining capital expenditures in respect of newly constructed assets tends to be minimal but tends to increase over time as such assets age and experience wear and tear. Regardless of whether assets result from sustaining or expansion capital expenditures, once completed, the addition of such assets to our depreciable asset base will impact our calculation of depreciation, depletion and amortization over the remaining useful lives of the impacted or resulting assets.

Generally, the determination of whether a capital expenditure is classified as sustaining or as expansion capital expenditures is made on a project level. The classification of our capital expenditures as expansion capital expenditures or as sustaining capital expenditures is made consistent with our accounting policies and is generally a straightforward process, but in certain circumstances can be a matter of management judgment and discretion.

~~Our capital expenditures for the year ended December 31, 2024, and the amount we expect to spend for 2025 to sustain our assets and expand our business are as follows:~~58

	2024		Expected 2025
	(In millions)
Capital expenditures:
Sustaining capital expenditures	$	1,009	$	938
Expansion capital expenditures	1,708		2,182
Accrued capital expenditures, contractor retainage and other	(88)		—
Capital expenditures	$	2,629	$	3,120
Add:
Sustaining capital expenditures of unconsolidated joint ventures(a)	$	189	$	184
Investments in unconsolidated joint ventures(b)	178		166
Less: Consolidated joint venture partners’ sustaining capital expenditures	(10)		(10)
Less: Consolidated joint venture partners’ expansion capital expenditures	(24)		(8)
Less: Insurance reimbursement related to a sustaining capital expenditure	(23)		—
Acquisition	60		—
Accrued capital expenditures, contractor retainage and other	88		—
Total capital investments	$	3,087	$	3,452

Our capital expenditures for the year ended December 31, 2025, and the amount we expect to spend for 2026 to sustain our assets and expand our business are as follows:

(a)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.


	2025		Expected 2026(a)
	(In millions)
Capital expenditures:
Sustaining capital expenditures	$	951	$	944
Expansion capital expenditures	2,030		2,975
Accrued capital expenditures, contractor retainage, and other	45		—
Capital expenditures	$	3,026	$	3,919
Add:
Sustaining capital expenditures of unconsolidated joint ventures(b)	$	175	$	177
Investments in unconsolidated joint ventures(c)	215		376
Less: Consolidated joint venture partners’ sustaining capital expenditures	(9)		(9)
Less: Consolidated joint venture partners’ expansion capital expenditures	(8)		(6)
Less: Insurance reimbursement related to a sustaining capital expenditure	(14)		—
Acquisition	648		—
Accrued capital expenditures, contractor retainage, and other	(45)		—
Total capital investments	$	3,988	$	4,457

(ba)~~Reflects~~Excludes ~~cash~~capital ~~contributions~~expenditures tofrom ~~unconsolidated~~our ~~joint~~divested ~~ventures. Also~~EagleHawk ~~includes~~assets, ~~contributions~~which towere anincluded ~~unconsolidated~~in ~~joint~~our ~~venture~~preliminary ~~that~~budget ~~are~~but ~~netted~~subsequently ~~within the amount the joint venture declares as a distribution to us~~divested.

59(b)Sustaining capital expenditures by our joint ventures generally do not require cash outlays by us.

(c)Reflects cash contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

Our capital investments consist of the following:

	2024		Expected 2025
	2025		Expected 2026(a)
	(In millions)
Sustaining capital investments
Capital expenditures for property, plant and equipment	$	1,009	$	938
Capital expenditures for property, plant, and equipment	$	951	$	944
Sustaining capital expenditures of unconsolidated joint ventures(a)	189		184
Sustaining capital expenditures of unconsolidated joint ventures(b)	175		177
Less: Consolidated joint venture partners’ sustaining capital expenditures	(109)		(109)
Less: Insurance reimbursement related to a sustaining capital expenditure	(2314)		—
Total sustaining capital investments	1,~~165~~103		1,112
Expansion capital investments
Capital expenditures for property, plant and equipment	1,708		2,182
Capital expenditures for property, plant, and equipment	2,030		2,975
Investments in unconsolidated joint ventures(b)	178		166
Investments in unconsolidated joint ventures(c)	215		376
Less: Consolidated joint venture partners’ expansion capital expenditures	(248)		(86)
Acquisition	60648		—
Total expansion capital investments	12,~~922~~885		23,~~340~~345
Total capital investments	$	3,~~087~~988	$	34,~~452~~457

(a)~~Sustaining~~Excludes capital expenditures byfrom our ~~joint~~divested ~~ventures~~EagleHawk ~~generally~~assets, dowhich ~~not~~were ~~require~~included ~~cash~~in ~~outlays~~our bypreliminary usbudget but subsequently divested.

(b)~~Reflects~~Sustaining ~~cash~~capital ~~contributions~~expenditures toby ~~unconsolidated~~our joint ventures~~. Also~~ ~~includes~~generally ~~contributions~~do tonot anrequire ~~unconsolidated~~cash ~~joint~~outlays ~~venture~~by ~~that are netted within the amount the joint venture declares as a distribution to~~ us.

~~Impact~~(c)Reflects ofcash ~~Regulation~~contributions to unconsolidated joint ventures. Also includes contributions to an unconsolidated joint venture that are netted within the amount the joint venture declares as a distribution to us.

The trend toward increasingly stringent regulations creates uncertainty regarding our capital and operating expenditure requirements over the longer term. For example, the EPA’s final rule known as the “Good Neighbor Plan” (the Plan) became effective on August 4, 2023. As a precursor to the Plan, the EPA disapproved state implementation plans, or SIPs, submitted under the interstate transport (Good Neighbor) provisions of the Clean Air Act for the 2015 Ozone NAAQS. The Plan, which imposes prescriptive emission standards for several sectors, including natural gas pipelines, covers 23 states; however, 12 states were awarded stays pending their respective appeals of the EPA’s disapproval of their SIPs.59

Multiple legal challenges to the Plan have been filed, including by us. See Note 17, “Litigation and Environmental—Environmental Matters—Challenge to Federal “Good Neighbor Plan,” to our consolidated financial statements. We believe that the Plan is deeply flawed and that numerous and substantial bases for challenging the Plan exist, as evidenced by the U.S. Supreme Court ruling on June 27, 2024, staying enforcement of the Plan pending a decision by the U.S. Court of Appeals for the District of Columbia (D.C. Circuit) on its pending review of the Plan and any subsequent appeal to the Supreme Court. In reaching its decision, the Supreme Court found that the parties challenging the Plan are likely to prevail on their argument that the Plan was not reasonably explained, that the EPA failed to supply a satisfactory explanation for its action, and that the EPA ignored an important aspect of the problem it was attempting to solve by promulgating the Plan. The EPA has no legal basis to enforce the Plan in any state while the Supreme Court stay remains in place. In addition, the stays of underlying SIP disapprovals also serve to prevent enforcement of the Plan in those states. The D.C. Circuit returned the consolidated cases to its active docket on January 13, 2025; however, on February 6, 2025, the EPA filed a motion asking the court to hold the cases in abeyance for 60 days to allow the Trump Administration time to familiarize themselves with the Plan, receive briefing from the EPA about the cases and the Plan, and decide what action on the Plan, if any, is necessary.

The Plan would require installation of more stringent air pollution controls on hundreds of existing internal combustion engines used by our Natural Gas Pipelines business segment. If the Plan ultimately were to take effect in its current form (including full compliance by a revised compliance deadline (originally May 1, 2026) accounting for the stays, and assuming failure of all challenges to SIP disapprovals and the Plan), we currently estimate that it would have a material impact on us, including estimated costs necessary to comply with the Plan ranging from $1.5 billion to $1.8 billion (including costs for joint ventures that we operate, net to our interests in such joint ventures), potential shortages of equipment resulting in our inability to comply with the Plan, and operational disruptions. Given the extensive pending litigation, and more recently, the change in U.S. presidential administrations and EPA’s filing with the U.S. Court of Appeals for the District of Columbia Circuit on February 6, 2025, impacts of the Plan are difficult to predict. The outcomes of these numerous lawsuits may significantly decrease or delay our exposure. In addition, we would seek to mitigate the impacts and to recover expenditures through adjustments to our rates on our regulated assets where available.

The cost estimates discussed above are preliminary, based on a number of assumptions and subject to significant variation, including outside of the ranges provided. Costs are assumed based on the average cost incurred historically for a typical retrofit of an average engine. These estimates reflect only the anticipated upgrades that would need to be performed (and in the case of joint ventures, only on assets that we operate) and do not take into account potential complications such as additional maintenance requirements that may be identified during the upgrade process.

Off Balance Sheet Arrangements

We have invested in entities that are not consolidated in our financial statements. For information on our obligations with respect to these investments, as well as our obligations with respect to related letters of credit, see Note 12 “Commitments and Contingent Liabilities” to our consolidated financial statements. Additional information regarding the nature and business purpose of our investments is included in Note 6 “Investments” to our consolidated financial statements.

Contractual Obligations and Commercial Commitments

The table below provides a summary of our material cash requirements.

Payments due by period

Total

Less than 1 year

1-3 years

3-5 years

More than 5 years

(In millions)

Contractual obligations:

Debt borrowings-principal payments(a)

31,~~788~~823

21,~~009~~226

12,~~974~~809

34,~~648~~148

2423,~~157~~640

Interest payments(b)

2120,~~051~~042

1,~~670~~736

3,~~219~~291

2,~~949~~926

1312,~~213~~089

Lease obligations(c)

~~326~~278

7259

8468

4846

~~122~~105

Pension and OPEB plans(d)

~~311~~243

6475

2928

2624

~~192~~116

Transportation, volume and storage agreements(e)

~~622~~1,390

~~164~~189

~~224~~294

~~110~~239

~~124~~668

Other obligations(f)

~~254~~272

5671

6461

3243

~~102~~97

Total

54,~~352~~048

43,~~035~~356

56,~~594~~551

67,~~813~~426

3736,~~910~~715

Other commercial commitments:

Standby letters of credit(g)

~~132~~89

8386

493

Capital expenditures(h)

~~809~~2,020

~~691~~1,305

~~115~~214

3501

(a)See Note 8 “Debt” to our consolidated financial statements.

(b)Interest payment obligations exclude adjustments for interest rate swap agreements and assume no change in variable interest rates from those in effect at December 31, ~~2024~~2025.

(c)Represents commitments pursuant to the terms of operating lease agreements as of December 31, ~~2024~~2025.

(d)Represents the amount by which the benefit obligations exceeded the fair value of plan assets at year-end for pension and OPEB plans whose accumulated postretirement benefit obligations exceeded the fair value of plan assets. The payments by period include expected pension contributions in ~~2025~~2026 and estimated benefit payments for underfunded plans in all years.

(e)Primarily represents transportation agreements of $~~277~~935 million, and storage agreements for capacity of $~~230~~395 million ~~and NGL volume agreements of $68 million~~.

(f)Primarily includes (i) rights-of-way obligations; and (ii) environmental liabilities related to sites that we own or have a contractual or legal obligation with a regulatory agency or property owner upon which we will perform remediation activities. These environmental liabilities are included within “Other current liabilities” and “Other long-term liabilities and deferred credits” in our consolidated balance sheet as of December 31, ~~2024~~2025.

(g)~~The~~Represents $~~132 million in letters of credit outstanding as of December 31, 2024 consisted of the following (i) $~~51 million under ~~six~~five letters of credit for insurance purposes; ~~(ii) a $46 million letter of credit supporting our International Marine Terminals Partnership Plaquemines Bond;~~ and ~~(iii)~~ a combined $3538 million in thirty-~~two~~one letters of credit supporting environmental and other obligations of us and our subsidiaries.

(h)Represents commitments for the purchase of plant, property and equipment as of December 31, ~~2024~~2025.

6160

Cash Flows

The following table summarizes our net cash flows provided by (used in) operating, investing, and financing activities between ~~2024~~2025 and ~~2023~~2024.

	Year Ended December 31,
	2024		2023		Changes
	2025		2024		Changes
	(In millions)
Net Cash Provided by (Used in)
Operating Activities	$	5,~~635~~917	$	65,~~491~~635	$	~~(856)~~282
Investing Activities	(23,~~629~~179)		(42,~~175~~629)		~~1,546~~(550)
Financing Activities	(2,~~887~~843)		(32,~~014~~887)		~~127~~44
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(1)		—		(1)
Effect of Exchange Rate Changes on Cash, Cash Equivalents, and Restricted Deposits	—		(1)		1
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	$	118	$	(698)	$	816
Net (Decrease) Increase in Cash, Cash Equivalents, and Restricted Deposits	$	(105)	$	118	$	(223)

Operating Activities

~~$856~~Net ~~million less~~ cash provided by operating activities inwas higher for the comparable years of ~~2024~~2025 and ~~2023~~2024 isdriven ~~explained~~by greater contributions from our Natural Gas Pipelines business segment, partially offset by unfavorable changes due to the ~~following~~timing ~~discussion~~of trade collections in account receivable.

•an $843 million decrease in cash related to a prepayment received of certain fixed reservation charges under long-term transportation and terminaling contracts in 2023. See Note 14 “Revenue Recognition” to our consolidated financial statements for further information regarding this prepayment; and

•a $359 million decrease in cash associated with net changes in working capital items and other non-current assets and liabilities, excluding the customer prepayment discussed above. The decrease was primarily driven by (i) the decrease in the weighted-average cost of gas in underground storage inventory in 2023; and (ii) a decrease in cash margin deposits posted by our counterparties as collateral; partially offset by

•a $346 million increase in cash after adjusting the $234 million increase in net income by the combined effects of the period-to-period net changes in non-cash items. See “—Results of Operations” for a discussion of items impacting net income.

Investing Activities

$~~1,546~~550 million ~~less~~more cash used in investing activities in the comparable years of ~~2024~~2025 and ~~2023~~2024 is explained by the following discussion.

•a $~~1,780~~648 million ~~decrease~~ in ~~expenditures for the acquisition of assets and investments, net of~~ cash ~~acquired, primarily driven by $1,829 million of net cash~~ used for the Outrigger Energy acquisition ofin ~~STX~~the ~~Midstream~~2025 inperiod; ~~2023.~~ See Note 3 “Acquisitions and Divestitures” to our consolidated financial statements for further information regarding this acquisition; and

•a $91397 million ~~decrease~~increase in ~~cash~~capital ~~used~~expenditures ~~for~~primarily ~~contributions~~driven toby ~~equity~~expansion ~~investees~~projects ~~driven~~in ~~primarily~~our byNatural ~~lower~~Gas ~~contributions~~Pipelines ~~to PHP~~ and ~~Greenholly~~Products ~~Gathering~~Pipelines ~~Pipeline~~business ~~LLC~~segments, partially offset by ~~higher~~a ~~contributions~~decrease ~~to SNG~~ in ~~the~~our ~~2024~~Terminals ~~period~~and ~~compared~~CO2 tobusiness ~~the 2023 period~~segments; partially offset by

•a $~~312~~382 million ~~increase~~ in ~~capital~~cash ~~expenditures~~received ~~primarily~~from ~~driven~~the bysale ~~expansion~~of ~~projects~~our equity interest in EagleHawk. See Note 3 “Acquisitions and Divestitures” to our ~~Natural~~consolidated ~~Gas~~financial ~~Pipelines~~statements ~~business~~for ~~segment.~~further information regarding this divestiture; and

•a $153 million increase in distributions from equity investments in excess of cumulative earnings primarily due to SNG’s distribution of debt refinancing proceeds that reimbursed prior capital contributions we made to retire debt in a previous period.

Financing Activities

~~$127~~Net ~~million less~~ cash used in financing activities inwas relatively flat for the comparable years of ~~2024~~2025 and ~~2023 is explained by the following discussion~~2024.

~~•a $515 million decrease in cash used for share repurchases under our share buy-back program; partially offset by~~61

•a $363 million net increase in cash used related to debt activity as a result of net debt reduction in 2024 compared to net issuances in 2023.

Dividends and Stock Buy-back Program

The table below reflects the declaration of dividends of $1.1517 per share for ~~2024~~2025:

Three months ended

Total quarterly dividend per share for the period

Date of declaration

Date of record

Date of dividend

March 31, 2024

$0.2875

April 17, 2024

April 30, 2024

May 15, 2024

March 31, 2025

$0.2925

April 16, 2025

April 30, 2025

May 15, 2025

June 30, 2024

0.2875

July 17, 2024

July 31, 2024

August 15, 2024

June 30, 2025

0.2925

July 16, 2025

July 31, 2025

August 15, 2025

September 30, 2024

0.2875

October 16, 2024

October 31, 2024

November 15, 2024

September 30, 2025

0.2925

October 22, 2025

November 3, 2025

November 17, 2025

December 31, 2024

0.2875

January 22, 2025

February 3, 2025

February 18, 2025

December 31, 2025

0.2925

January 21, 2026

February 2, 2026

February 17, 2026

We expect to continue to return additional value to our shareholders in ~~2025~~2026 through our previously announced dividend increase. We plan to increase our dividend by 2% to $1.1719 per common share in ~~2025~~2026. We have a board-approved share buy-back program that authorizes share repurchase of up to $3 billion that began in December 2017. Since December 2017, in total, we have repurchased approximately 86 million shares of our Class P common stock under the program at an average price of $17.09 per share for $1,472 million, leaving a remaining capacity of approximately $1.5 billion. For information on our stock buy-back program, see Note 10 “Stockholders’ Equity” to our consolidated financial statements.

The actual amount of dividends to be paid on our capital stock will depend on many factors, including our financial condition and results of operations, liquidity requirements, business prospects, capital requirements, legal, regulatory and contractual constraints, tax laws, Delaware laws, and other factors. See Item 1A. “Risk Factors—Risks Related to Ownership of Our Capital Stock—The guidance we provide for our anticipated dividends is based on estimates. Circumstances may arise that lead to conflicts between using funds to pay anticipated dividends or to invest in our business.” All of these matters will be taken into consideration by our Board when declaring dividends.

Our dividends are not cumulative. Consequently, if dividends on our stock are not paid at the intended levels, our stockholders are not entitled to receive those payments in the future. Our dividends generally will be paid on or about the 15th day of each February, May, August and November.

6362

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries

KMI and certain subsidiaries (Subsidiary Issuers) are issuers of certain debt securities. KMI and substantially all of KMI’s wholly owned domestic subsidiaries (Subsidiary Guarantors), are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. Accordingly, with the exception of certain subsidiaries identified as subsidiary non-guarantors (Subsidiary Non-Guarantors), the parent issuer, Subsidiary Issuers and Subsidiary Guarantors (the “Obligated Group”) are all guarantors of each series of our guaranteed debt (Guaranteed Notes). As a result of the cross guarantee agreement, a holder of any of the Guaranteed Notes issued by KMI or a Subsidiary Issuer is in the same position with respect to the net assets, and income of KMI and the Subsidiary Issuers and Guarantors. The only amounts that are not available to the holders of each of the Guaranteed Notes to satisfy the repayment of such securities are the net assets, and income of the Subsidiary Non-Guarantors.

In lieu of providing separate financial statements for the Obligated Group, we have presented the accompanying supplemental summarized combined income statement and balance sheet information for the Obligated Group based on Rule 13-01 of the SEC’s Regulation S-X. Also, see Exhibit 10.119 to this report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of December 31, ~~2024~~2025.”

All significant intercompany items among the Obligated Group have been eliminated in the supplemental summarized combined financial information. The Obligated Group’s investment balances in Subsidiary Non-Guarantors have been excluded from the supplemental summarized combined financial information. Significant intercompany balances and activity for the Obligated Group with other related parties, including Subsidiary Non-Guarantors (referred to as “affiliates”), are presented separately in the accompanying supplemental summarized combined financial information.

Excluding fair value adjustments, as of December 31, ~~2024~~2025 and ~~2023~~2024, the Obligated Group had $31,~~052~~153 million and $31,~~167~~052 million, respectively, of Guaranteed Notes outstanding.

Summarized combined balance sheet and income statement information for the Obligated Group follows:

	December 31,
Summarized Combined Balance Sheet Information	~~2024~~2025		~~2023~~2024
	(In millions)
Current assets	$	2,~~216~~460	$	2,~~246~~216
Current assets - affiliates	~~735~~779		~~760~~735
Noncurrent assets	6364,~~267~~470		6263,~~877~~267
Noncurrent assets - affiliates	~~813~~782		~~903~~813
Total Assets	$	6768,~~031~~491	$	6667,~~786~~031
Current liabilities	$	4,~~737~~015	$	64,~~907~~737
Current liabilities - affiliates	~~758~~766		~~734~~758
Noncurrent liabilities	3435,~~052~~589		3134,~~681~~052
Noncurrent liabilities - affiliates	1,~~561~~807		1,~~306~~561
Total Liabilities	4142,~~108~~177		4041,~~628~~108
Kinder Morgan, Inc.’s stockholders’ equity	2526,~~923~~314		2625,~~158~~923
Total Liabilities and Stockholders’ Equity	$	6768,~~031~~491	$	6667,~~786~~031

Summarized Combined Income Statement Information

Year Ended December 31, ~~2024~~2025

(In millions)

Revenues

1315,~~678~~523

Operating income

34,~~827~~172

Net income

2,~~131~~587

6463

Recent Accounting Pronouncements

Please refer to Note 18 “Recent Accounting Pronouncements” to our consolidated financial statements for information concerning recent accounting pronouncements.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

Generally, our market risk sensitive instruments and positions have been determined to be “other than trading.” Our exposure to market risk as discussed below includes forward-looking statements and represents an estimate of possible changes in fair value or future earnings that would occur assuming hypothetical future movements in energy commodity prices or interest rates. Our views on market risk are not necessarily indicative of actual results that may occur and do not represent the maximum possible gains and losses that may occur, since actual gains and losses will differ from those estimated based on actual fluctuations in energy commodity prices or interest rates and the timing of transactions.

Energy Commodity Market Risk

We enter into certain energy commodity derivative contracts in order to reduce risks encountered in the ordinary course of business associated with unfavorable changes in the market price of crude oil, natural gas, and NGL. The derivative contracts that we use include exchange-traded and OTC commodity financial instruments, including, but not limited to, futures and options contracts, fixed price swaps, and basis swaps. We may categorize such use of energy commodity derivative contracts as cash flow hedges because the derivative contract is used to hedge the anticipated future cash flow of a transaction that is expected to occur but whose value is uncertain.

Our hedging strategy involves entering into a financial position intended to offset our physical position, or anticipated position, in order to minimize the risk of financial loss from an adverse price change. For example, as sellers of crude oil, natural gas, and NGL, we often enter into fixed price swaps and/or futures contracts to guarantee or lock-in the sale price of our crude oil or the margin from the sale and purchase of our natural gas at the time of market delivery, thereby in whole or in part offsetting any change in prices, either positive or negative. Using derivative contracts for this purpose helps provide increased certainty with regard to operating cash flows, which helps us to undertake further capital improvement projects, attain budget results, and meet dividend targets.

Our policies require that derivative contracts are only entered into with carefully selected major financial institutions or similar counterparties based upon their credit ratings and other factors, and we maintain strict dollar and term limits that correspond to our counterparties’ credit ratings. While it is our policy to enter into derivative transactions principally with investment grade counterparties and actively monitor their credit ratings, it is nevertheless possible that losses will result from counterparty credit risk in the future.

We measure the risk of price changes in the derivative instrument portfolios utilizing a sensitivity analysis model. The sensitivity analysis applied to each portfolio measures the potential income or loss (i.e., the change in fair value of the derivative instrument portfolio) based upon a hypothetical 10% movement in the underlying quoted market prices. In addition to these variables, the fair value of each portfolio is influenced by fluctuations in the notional amounts of the instruments and the discount rates used to determine the present values. Because we enter into derivative contracts largely for the purpose of mitigating the risks that accompany certain of our business activities, both in the sensitivity analysis model and in reality, the change in the market value of the derivative contracts’ portfolio is offset largely by changes in the value of the underlying physical transactions. A hypothetical 10% movement in the underlying commodity prices would have the following effect on the associated derivative contracts’ estimated fair value:

As of December 31,

Commodity derivative

~~2024~~2025

~~2023~~2024

(In millions)

Crude oil

~~120~~87

~~127~~120

Natural gas

7638

2876

NGL

Total

~~200~~128

~~159~~200

Our sensitivity analysis represents an estimate of the reasonably possible gains and losses that would be recognized on the crude oil, natural gas, and NGL portfolios of derivative contracts assuming hypothetical movements in future market rates and is

6564

is not necessarily indicative of actual results that may occur. It does not represent the maximum possible loss or any expected loss that may occur, since actual future gains and losses will differ from those estimated. Actual gains and losses may differ from estimates due to actual fluctuations in market rates, operating exposures and the timing thereof, as well as changes in our portfolio of derivatives during the year.

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed-rate debt and variable-rate debt. Fixed-to-variable interest rate swap agreements are entered into for the purpose of converting a portion of the underlying cash flows related to long-term fixed-rate debt securities into variable-rate debt in order to achieve our desired mix of fixed and variable-rate debt. Variable-to-fixed interest rate swap agreements are entered into primarily for the purpose of managing our exposure to changes in interest rates on our debt balances that are subject to variable interest rates and adjusting, on a short-term basis, our mix of fixed-rate debt and variable-rate debt based on changes in market conditions. The market risk inherent in our debt instruments and positions is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed-rate debt, changes in interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable-rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows. Generally, there is not an obligation to prepay fixed-rate debt prior to maturity and, as a result, changes in fair value should not have a significant impact on the fixed-rate debt. We are generally subject to interest rate risk upon refinancing maturing debt. Below are our debt balances, including debt fair value adjustments, and sensitivity to interest rates:

December 31, 2024

December 31, 2023

December 31, 2025

December 31, 2024

Carryingvalue

Estimatedfair value(a)

Carryingvalue

Estimatedfair value(a)

(In millions)

Fixed rate debt(b)

31,~~519~~990

3031,~~423~~953

3031,~~063~~519

2930,~~317~~423

Variable rate debt

~~371~~13

~~2,053~~371

Notional principal amount of variable-to-fixed interest rate swap agreements

~~(1,500)~~—

—(1,500)

Notional principal amount of fixed-to-variable interest rate swap agreements

43,~~750~~500

64,~~200~~750

Debt balances subject to variable interest rates(c)

3,~~621~~513

83,~~253~~621

(a)Fair values were determined using Level 2 inputs.

(b)A hypothetical 10% change in the average interest rates applicable to such debt as of December 31, ~~2024~~2025 and ~~2023~~2024, would result in changes of approximately $1,~~416~~329 million and $1,~~889~~416 million, respectively, in the estimated fair values of these instruments.

(c)A hypothetical 10% change in the weighted average interest rate on all of our borrowings (approximately 56 and 58 basis points in ~~both~~2025 ~~2024~~ and ~~2023~~2024, respectively) when applied to our outstanding balance of variable rate debt as of December 31, ~~2024~~2025 and ~~2023~~2024, including adjustments for the notional swap amounts described in the table above, would result in changes of approximately $2120 million and $4821 million, respectively.

We monitor our mix of fixed-rate and variable-rate debt obligations in light of changing market conditions, and we may alter that mix from time to time by, for example, refinancing outstanding balances of variable rate debt with fixed rate debt (or vice versa) or by entering into interest rate swap agreements or other interest rate hedging agreements. As of December 31, 2024, including debt converted to variable rates through the use of interest rate swaps but excluding our debt fair value adjustments, approximately 11% of our debt balances were subject to variable interest rates.

For more information on our interest rate risk management and on our interest rate swap agreements, see Note 13 “Risk Management” to our consolidated financial statements.

Foreign Currency Risk

As of December 31, ~~2024~~2025, we had a notional principal amount of $543 million of cross-currency swap agreements that effectively convert all of our fixed-rate Euro denominated debt, including annual interest payments and the payment of principal at maturity, to U.S. dollar denominated debt at fixed rates. These swaps eliminate the foreign currency risk associated with our foreign currency denominated debt.

6765

Item 8. Financial Statements and Supplementary Data.

KINDER MORGAN, INC. AND SUBSIDIARIES

INDEX TO FINANCIAL STATEMENTS

			PageNumber
Report of Independent Registered Public Accounting Firm		(PCAOB ID: 238)	6967
Consolidated Statements of Income for the years ended December 31, 2024, 2023 and 2022			71
Consolidated Statements of Income for the years ended December 31, 2025, 2024, and 2023			69
Consolidated Statements of Comprehensive Income for the years ended December 31, 2024, 2023 and 2022			72
Consolidated Statements of Comprehensive Income for the years ended December 31, 2025, 2024, and 2023			70
Consolidated Balance Sheets as of December 31, 2024 and 2023			73
Consolidated Balance Sheets as of December 31, 2025 and 2024			71
Consolidated Statements of Cash Flows for the years ended December 31, 2024, 2023 and 2022			74
Consolidated Statements of Cash Flows for the years ended December 31, 2025, 2024, and 2023			72
Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2024, 2023 and 2022			76
Consolidated Statements of Stockholders’ Equity as of and for the years ended December 31, 2025, 2024, and 2023			74
Notes to Consolidated Financial Statements			7775
Note 1.	General		7775
Note 2.	Summary of Significant Accounting Policies		7775
Note 3.	Acquisitions and Divestitures		8684
Note 4.	Income Taxes		8986
Note 5.	Property, Plant, and Equipment, net		9289
Note 6.	Investments		9390
Note 7.	Goodwill		9491
Note 8.	Debt		9491
Note 9.	Share-based Compensation and Employee Benefits		9895
Note 10.	Stockholders’ Equity		~~104~~101
Note 11.	Related Party Transactions		~~106~~102
Note 12.	Commitments and Contingent Liabilities		~~106~~103
Note 13.	Risk Management		~~107~~104
Note 14.	Revenue Recognition		~~112~~108
Note 15.	Reportable Segments		~~115~~110
Note 16.	Leases		~~120~~114
Note 17.	Litigation and Environmental		~~121~~115
Note 18.	Recent Accounting Pronouncements		~~125~~119

6866

Report of Independent Registered Public Accounting Firm

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

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Kinder Morgan, Inc. and its subsidiaries (the “Company”) as of December 31, ~~2024~~2025 and ~~2023~~2024, and the related consolidated statements of income, of comprehensive income, of stockholders’ equity and of cash flows for each of the three years in the period ended December 31, ~~2024~~2025, including the related notes (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2024~~2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

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

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

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

Definition and Limitations of Internal Control over Financial Reporting

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

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

6967

Critical Audit Matters

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

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

As described in Notes 2 and 7 to the consolidated financial statements, the Company’s consolidated goodwill balance was $20.1 billion as of December 31, ~~2024~~2025, of which $20.0 billion relates to the Natural Gas Pipelines Regulated, Natural Gas Pipelines Non-Regulated, CO2, Products Pipelines, Products Pipelines Terminals, and Terminals reporting units (collectively, “the reporting units”). Management evaluates goodwill for impairment on May 31 of each year, or more frequently to the extent events occur or conditions change between annual tests that would indicate a risk of possible impairment at the interim period. Management estimated the fair value of the reporting units based on a market approach utilizing forecasted earnings before interest, income taxes, depreciation, depletion, and amortization expenses, ~~including amortization of excess cost of equity investments~~ (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each reporting unit.

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

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

/s/ PricewaterhouseCoopers LLP

Houston, Texas

February 13, ~~2025~~2026

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

7068

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME

(In millions, except per share amounts)

	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
Revenues
Services	$	89,~~916~~490	$	8,~~371~~916	$	8,~~145~~371
Commodity sales	57,~~957~~255		65,~~786~~957		106,~~897~~786
Other	~~227~~192		~~177~~227		~~158~~177
Total Revenues	1516,~~100~~937		15,~~334~~100		1915,~~200~~334
Operating Costs, Expenses and Other
Operating Costs, Expenses, and Other
Costs of sales (exclusive of items shown separately below)	45,~~337~~529		4,~~938~~337		94,~~255~~938
Operations and maintenance	23,~~972~~057		2,~~807~~972		2,~~655~~807
Depreciation, depletion and amortization	2,354		2,250		2,186
Depreciation, depletion, and amortization	2,453		2,354		2,250
General and administrative	~~712~~744		~~668~~712		~~637~~668
Taxes, other than income taxes	~~433~~445		~~421~~433		~~441~~421
Other income, net	(9215)		(1392)		(3913)
Total Operating Costs, Expenses and Other	10,716		11,071		15,135
Total Operating Costs, Expenses, and Other	12,213		10,716		11,071
Operating Income	4,~~384~~724		4,~~263~~384		4,~~065~~263
Other Income (Expense)
Earnings from equity investments	~~890~~896		~~838~~840		~~803~~772
Amortization of excess cost of equity investments	(50)		(66)		(75)
Interest, net	(1,801)		(1,844)		(1,797)
Interest, net	(1,844)		(1,797)		(1,513)
Other, net (Note 3)	173		27		(37)
Other, net	27		(37)		55
Total Other Expense	(732)		(977)		(1,062)
Total Other Expense	(977)		(1,062)		(730)
Income Before Income Taxes	3,992		3,407		3,201
Income Before Income Taxes	3,407		3,201		3,335
Income Tax Expense	(832)		(687)		(715)
Income Tax Expense	(687)		(715)		(710)
Net Income	3,160		2,720		2,486
Net Income	2,720		2,486		2,625
Net Income Attributable to Noncontrolling Interests	(104)		(107)		(95)
Net Income Attributable to Noncontrolling Interests	(107)		(95)		(77)
Net Income Attributable to Kinder Morgan, Inc.	$	3,056	$	2,613	$	2,391
Net Income Attributable to Kinder Morgan, Inc.	$	2,613	$	2,391	$	2,548
Class P Common Stock
Basic and Diluted Earnings Per Share	$	1.1737	$	1.0617	$	1.1206
Basic and Diluted Weighted Average Shares Outstanding	2,~~220~~223		2,~~234~~220		2,~~258~~234

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

7169

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(In millions)

	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
Net income	$	23,~~720~~160	$	2,~~486~~720	$	2,~~625~~486
Other comprehensive income, net of tax
Net unrealized (loss) gain from derivative instruments (net of taxes of $8, $(47), and $92, respectively)	(29)		155		(312)
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 loss (gain) to net income (net of taxes of $(12), $12, and $(95), respectively)	40		(35)		320
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 $(33), $(20), and $(1), respectively)	111		65		1
Benefit plan adjustments (net of taxes of $(12), $(33), and $(20), respectively)	40		111		65
Total other comprehensive income	~~122~~140		~~185~~122		9185
Comprehensive income	23,~~842~~300		2,~~671~~842		2,~~634~~671
Comprehensive income attributable to noncontrolling interests	(~~107~~104)		(95107)		(7795)
Comprehensive income attributable to KMI	$	23,~~735~~196	$	2,~~576~~735	$	2,~~557~~576

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

7270

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(In millions, except share and per share amounts)

	December 31,
	2024		2023
	2025		2024
ASSETS
Current assets
Cash and cash equivalents	$	8863	$	8388
Restricted deposits	~~126~~46		13126
Accounts receivable	1,~~506~~714		1,~~588~~506
Inventories	~~555~~574		~~525~~555
Other current assets	~~246~~357		~~333~~246
Total current assets	2,~~521~~754		2,~~542~~521
Property, plant and equipment, net	38,013		37,297
Property, plant, and equipment, net	39,331		38,013
Investments	7,~~845~~532		7,~~874~~845
Goodwill	20,084		20,~~121~~084
Other intangibles, net	1,~~760~~730		1,~~957~~760
Deferred charges and other assets	1,~~184~~317		1,~~229~~184
Total Assets	$	7172,~~407~~748	$	71,~~020~~407
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities
Current portion of debt	$	21,~~009~~226	$	42,~~049~~009
Accounts payable	1,~~395~~408		1,~~366~~395
Accrued interest	~~543~~534		~~513~~543
Accrued taxes	~~276~~256		~~272~~276
Other current liabilities	~~878~~898		~~1,021~~878
Total current liabilities	54,~~101~~322		75,~~221~~101
Long-term liabilities and deferred credits
Long-term debt
Outstanding	2930,~~779~~597		2729,~~880~~779
Debt fair value adjustments	~~102~~180		~~187~~102
Total long-term debt	2930,~~881~~777		2829,~~067~~881
Deferred income taxes	2,~~070~~891		12,~~388~~070
Other long-term liabilities and deferred credits	2,~~488~~309		2,~~615~~488
Total long-term liabilities and deferred credits	3435,~~439~~977		3234,~~070~~439
Total Liabilities	3940,~~540~~299		39,~~291~~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, 2,221,647,775 and 2,219,729,644 shares, respectively, issued and outstanding	22		22
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,~~237~~276		41,~~190~~237
Accumulated deficit	(10,~~633~~181)		(10,~~689~~633)
Accumulated other comprehensive loss	(95)		(217)
Accumulated other comprehensive income (loss)	45		(95)
Total Kinder Morgan, Inc.’s stockholders’ equity	3031,~~531~~162		30,~~306~~531
Noncontrolling interests	1,~~336~~287		1,~~423~~336
Total Stockholders’ Equity	3132,~~867~~449		31,~~729~~867
Total Liabilities and Stockholders’ Equity	$	7172,~~407~~748	$	71,~~020~~407

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

7371

KINDER MORGAN, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
Cash Flows From Operating Activities
Net income	$	23,~~720~~160	$	2,~~486~~720	$	2,~~625~~486
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation, depletion and amortization	2,354		2,250		2,186
Depreciation, depletion, and amortization	2,453		2,354		2,250
Deferred income taxes	~~647~~780		~~710~~647		~~692~~710
Amortization of excess cost of equity investments	50		66		75
Change in fair value of derivative contracts	(23)		72		(126)
Change in fair value of derivative contracts	72		(126)		56
Gain on divestitures, net	(6)		(74)		(15)
Gain on divestitures, net	(74)		(15)		(32)
Gain on sale of interest in equity investment (Note 3)	(123)		—		—
Earnings from equity investments	(~~890~~896)		(~~838~~840)		(~~803~~772)
Distributions of equity investment earnings	~~823~~805		~~755~~823		~~725~~755
Pension contributions net of noncash pension benefit expenses	9(10)		779		~~(50)~~77
Changes in components of working capital, net of the effects of acquisitions and dispositions
Accounts receivable	52(192)		~~301~~52		~~(220)~~301
Inventories	(1221)		~~188~~(12)		~~(183)~~188
Other current assets	(469)		~~108~~(46)		~~(51)~~108
Accounts payable	~~(5)~~96		(~~201~~5)		~~161~~(201)
Accrued interest, net of interest rate swaps	43(13)		~~(13)~~43		50(13)
Accrued taxes	5(15)		25		~~(5)~~2
Other current liabilities	~~(52)~~41		(6048)		11(79)
Change in deferred revenues (Note 14)	(58)		870		(24)
Change in deferred revenues	5		(58)		870
Rate reparations, refunds and other litigation reserve adjustments	24		(19)		(190)
Other, net	(115)		(7)		(50)
Other, net	(27)		(50)		(56)
Net Cash Provided by Operating Activities	5,917		5,635		6,491
Net Cash Provided by Operating Activities	5,635		6,491		4,967
Cash Flows From Investing Activities
Acquisitions of assets and investments, net of cash acquired (Note 3)	(62648)		(~~1,842~~62)		(~~487~~1,842)
Capital expenditures	(23,~~629~~026)		(2,~~317~~629)		(12,~~621~~317)
Contributions to investments	(121)		(212)		(229)
Proceeds from sale of investment (Note 3)	382		—		—
Distributions from equity investments in excess of cumulative earnings	177		228		156
Contributions to investments	(178)		(121)		(212)
Other, net	6		(32)		6
Distributions from equity investments in excess of cumulative earnings	330		177		228
Net Cash Used in Investing Activities	(2,629)		(4,175)		(2,175)
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,~~441~~017		710,~~590~~441		97,~~058~~590
Payments of debt	(10,~~557~~054)		(710,~~356~~557)		(97,~~735~~356)
Debt issue costs	(3320)		(2033)		(2520)
Dividends (Note 10)	(2,~~557~~604)		(2,~~529~~557)		(2,~~504~~529)
Repurchases of shares (Note 10)	~~(7)~~—		(~~522~~7)		(~~368~~522)
Proceeds from sale of noncontrolling interests (Note 3)	—		—		557
Contributions from noncontrolling interests	—		—		3
Contributions from noncontrolling interests	—		3		2
Distributions to noncontrolling interests	(153)		(154)		(151)
Distributions to noncontrolling interests	(154)		(151)		(116)
Other, net	(29)		(20)		(29)
Other, net	(20)		(29)		(14)
Net Cash Used in Financing Activities	(2,843)		(2,887)		(3,014)
Net Cash Used in Financing Activities	(2,887)		(3,014)		(3,145)
Effect of Exchange Rate Changes on Cash, Cash Equivalents, and Restricted Deposits	—		(1)		—
Effect of Exchange Rate Changes on Cash, Cash Equivalents and Restricted Deposits	(1)		—		—
Net (Decrease) Increase in Cash, Cash Equivalents, and Restricted Deposits	(105)		118		(698)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	118		(698)		(353)
Cash, Cash Equivalents, and Restricted Deposits, beginning of period	214		96		794
Cash, Cash Equivalents and Restricted Deposits, beginning of period	96		794		1,147
Cash, Cash Equivalents, and Restricted Deposits, end of period	$	109	$	214	$	96
Cash, Cash Equivalents and Restricted Deposits, end of period	$	214	$	96	$	794

7472

KINDER MORGAN, INC. AND SUBSIDIARIES (continued)
CONSOLIDATED STATEMENTS OF CASH FLOWS
(In millions)
	Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
Cash and Cash Equivalents, beginning of period	$	83	$	745	$	1,140
Restricted Deposits, beginning of period	13		49		7
Cash, Cash Equivalents and Restricted Deposits, beginning of period	96		794		1,147
Cash and Cash Equivalents, end of period	88		83		745
Restricted Deposits, end of period	126		13		49
Cash, Cash Equivalents and Restricted Deposits, end of period	214		96		794
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Deposits	$	118	$	(698)	$	(353)
Noncash Investing and Financing Activities
Net increase in property, plant and equipment from both accruals and contractor retainage	$	50	$	120	$	72
Net increase in property, plant, and equipment from both accruals and contractor retainage			$	50	$	120
ROU assets and operating lease obligations recognized (Note 16)	36$	25	5636		2256
Assets contributed to equity investment	—		16—		—16
Supplemental Disclosures of Cash Flow Information
Cash paid during the period for interest (net of capitalized interest)	1,~~816~~811		1,~~844~~816		1,~~460~~844
Cash paid during the period for income taxes, net	33		11		13

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

7573

KINDER MORGAN, INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In millions)

	Common stock		Additionalpaid-incapital			Accumulateddeficit		Accumulatedothercomprehensiveloss		Stockholders’equityattributableto KMI		Non-controllinginterests		Total
		Issued shares			Par value
Balance at December 31, 2021		2,267	$	23		$	41,806	$	(10,595)	$	(411)	$	30,823	$	1,098	$	31,921
Balance at January 1, 2023		2,248	$	22		$	41,673	$	(10,551)	$	(402)	$	30,742	$	1,372	$	32,114
Impact of adoption of ASU 2020-06 (Note 10)						(11)						(11)				(11)
Balance at January 1, 2022		2,267	23			41,795		(10,595)		(411)		30,812		1,098		31,910
Repurchases of shares		(21)	(1)			(367)						(368)				(368)
EP Trust I Preferred security conversions						1						1				1
Restricted shares		2				54						54				54
Net income								2,548				2,548		77		2,625
Dividends								(2,504)				(2,504)				(2,504)
Distributions												—		(116)		(116)
Contributions												—		2		2
Impact of change in ownership interest in subsidiary						190						190		311		501
Other comprehensive income										9		9				9
Balance at December 31, 2022		2,248	22			41,673		(10,551)		(402)		30,742		1,372		32,114
Repurchases of shares		(32)				(522)						(522)				(522)
Restricted shares		4				44						44				44
Net income								2,391				2,391		95		2,486
Dividends								(2,529)				(2,529)				(2,529)
Distributions												—		(151)		(151)
Contributions												—		3		3
Acquisition (Note 3)												—		104		104
Other						(5)						(5)				(5)
Other comprehensive income										185		185				185
Balance at December 31, 2023		2,220	22			41,190		(10,689)		(217)		30,306		1,423		31,729
Repurchases of shares		(1)				(7)						(7)				(7)
Restricted shares		3				54						54				54
Net income								2,613				2,613		107		2,720
Dividends								(2,557)				(2,557)				(2,557)
Distributions								—				—		(154)		(154)
Acquisition adjustment (Note 3)												—		(38)		(38)
Other												—		(2)		(2)
Other comprehensive income										122		122				122
Balance at December 31, 2024		2,222	$22	22		$41,237	~~41,237~~	$(10,633)	~~(10,633)~~	$(95)	~~(95)~~	$30,531	~~30,531~~	$1,336	~~1,336~~	$31,867	~~31,867~~
Restricted shares		3				39						39				39
Net income								3,056				3,056		104		3,160
Dividends								(2,604)				(2,604)				(2,604)
Distributions												—		(153)		(153)
Other comprehensive income										140		140				140
Balance at December 31, 2025		2,225	$	22		$	41,276	$	(10,181)	$	45	$	31,162	$	1,287	$	32,449

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

7674

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.			General

We are one of the largest energy infrastructure companies in North America. Unless the context requires otherwise, references to “we,” “us,” “our,” “the Company,” or “KMI” are intended to mean Kinder Morgan, Inc. and its consolidated subsidiaries. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels, and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.


2.			Summary of Significant Accounting Policies

Basis of Presentation

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

Use of Estimates

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

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

Cash Equivalents and Restricted Deposits

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

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

Allowance for Credit Losses

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

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

7775

Our allowance for credit losses as of both December 31, 2024 and 2023 were immaterial and is included in “Other current assets” in our accompanying consolidated balance sheets.

Inventories

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

Property, Plant, and Equipment, net

Capitalization, Depreciation and Depletion and Disposals

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

Asset

Accounting Area

Policy

Straight-line assets

Depreciation rates

•Depreciable lives are based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property, and historical data concerning useful lives of similar assets.

Gains and losses

•A gain or loss on the sale of property, plant, and equipment is calculated as the difference between the cost of the asset disposed of, net of depreciation, and the sale proceeds received or when held for sale, the market value of the asset.•A gain on an asset disposal is recognized in income in the period that the sale is closed.•A loss is recognized when the asset is sold or when classified as held for sale.•Gains and losses are recorded in operating costs, expenses, and other.

Composite assets

Depreciation rates

•A single depreciation rate is applied to the total cost of a functional group of assets that have similar economic characteristics until the net book value of the composite group equals the salvage value.•Interstate natural gas FERC-regulated entities use the depreciation rates approved by the FERC.•A depreciation rate for other composite assets is based on estimated economic lives. This includes age, manufacturing specifications, technological advances, estimated production life of the oil or gas field served by the asset, contract terms for assets on leased or customer property, and historical data concerning useful lives of similar assets.

Gains and losses

•Gains and losses are credited or charged to accumulated depreciation, net of salvage and cost of removal.•Gains or losses on land sales and FERC-approved operating unit sales are recorded in operating costs, expenses, and other.

Oil and gas producing activities(a)

Successful efforts method of accounting

•Costs that are incurred to acquire leasehold and subsequent development costs are capitalized. •Costs that are associated with the drilling of successful exploration wells are capitalized if proved reserves are found. •Costs associated with the drilling of exploratory wells that do not find proved reserves, geological and geophysical costs, and costs of certain non-producing leasehold costs are expensed as incurred. •The capitalized costs of our producing oil and gas properties are depreciated and depleted by the units-of-production method. •Other miscellaneous property, plant, and equipment are depreciated over the estimated useful lives of the asset.

Enhanced recovery techniques

•In some cases, the cost of the CO2 associated with enhanced recovery is capitalized as part of our development costs when it is injected. •The cost of CO2 associated with pressure maintenance operations for reservoir management is expensed when it is injected. •When CO2 is recovered in conjunction with oil production, it is extracted and re-injected, and all of the associated costs are expensed as incurred. •Proved developed reserves are used in computing units of production rates for drilling and development costs, and total proved reserves are used for depletion of leasehold costs.

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

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

Asset Retirement Obligations

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

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

	December 31,
	2024		2023
	2025		2024
	(In millions)
Balance at beginning of period	$	~~231~~248	$	~~204~~231
Accretion expense	1314		1213
Divestitures (Note 3)	~~(33)~~—		—(33)
Acquisitions (Note 3)	43—		1243
New obligations	1023		10
Settlements	(1630)		(716)
Balance at end of period(a)	$	~~248~~255	$	~~231~~248

(a)Balances at both December 31, ~~2024~~2025 and ~~2023~~2024 include $2 million ~~and $3 million, respectively, included~~ 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 ~~supply~~demand ~~and~~for ~~demand~~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-

7977

~~asset is recoverable, we compare the asset’s estimated undiscounted cash flows to its carrying value (step 1). Because the impairment test for long-~~lived ~~assets held in use is based on estimated undiscounted cash flows, there may be instances where an~~ asset or asset group is not considered impaired, even when its fair value may be less than its carrying value, because the asset or asset group is recoverable based on the cash flows to be generated over the estimated life of the asset or asset group. 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 ~~(step 2)~~.

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.

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. Unproved oil and gas properties that are individually significant are periodically assessed for impairment of value, and a loss is recognized at the time of impairment.

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.

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.

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, ~~2024~~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 ~~handling~~gathering and ~~storage~~transportation of petroleum, ~~chemical, and dry-bulk materials,~~ including oil, gasoline, and other refined petroleum products, ~~petroleum~~the ~~coke~~gathering and transportation of natural gas, ~~metals~~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.

80We 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.

ores, the gathering of natural gas and the production and supply of RNG. 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.78

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, ~~2024~~2025 and ~~2023~~2024 and our amortization expense for the years ended December 31, 2025, 2024, ~~2023~~ and ~~2022~~2023:

		December 31,
	2024			2023
	2025			2024
		(In millions)
Gross		$	3,~~543~~580		$	3,543
Accumulated amortization		(1,~~783~~850)			(1,~~586~~783)
Net carrying amount		$	1,~~760~~730		$	1,~~957~~760

	December 31,
	2024		2023		2022
	2025		2024		2023
	(In millions)
Amortization expense	$	~~197~~190	$	~~202~~197	$	~~253~~202

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

	2025		2026		2027		2028		2029
	2026		2027		2028		2029		2030
	(In millions)
Estimated amortization expenses	$	~~193~~184	$	~~191~~188	$	~~191~~187	$	~~190~~186	$	~~189~~186

Revenue Recognition

The majority of our revenues are accounted for under Topic 606, Revenue from Contracts with Customers; ~~however,~~and ~~to a limited extent, some revenues~~ are ~~accounted~~primarily ~~for~~derived ~~under~~from ~~other~~the ~~guidance~~following ~~such as Topic 842, Leases or Topic 815, Derivatives and Hedging Activities.~~activities:

Revenue from Contracts with Customers


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 ~~review our contracts with customers using the following steps to~~ recognize revenue ~~based~~when oncontrol of the ~~transfer~~promised of goods or services is transferred to our customers and in ~~amounts~~an amount that ~~reflect~~reflects the consideration ~~the~~we ~~company~~expect ~~expects~~ to receive for those goods or services. ~~The~~ ~~steps~~Revenues ~~include: (i)~~are ~~identify~~generally ~~the~~invoiced ~~contract;~~on ~~(ii)~~a ~~identify~~monthly ~~the~~basis. ~~performance~~The ~~obligations~~table ofbelow ~~the~~describes ~~contract; (iii) determine~~ the ~~transaction~~general ~~price;~~steps ~~(iv)~~we ~~allocate~~follow ~~the~~for ~~transaction price to the performance obligations in the contract; and then (v) recognize~~ revenue ~~when~~recognition ~~(or~~for ~~as)~~ the ~~performance~~large ~~obligation~~majority isof ~~satisfied~~our contracts. Each of these steps ~~involves~~may involve management judgment and an analysis of the contract’s material terms. ~~and~~Refer ~~conditions~~to Note 14 for further information.

~~Our~~Commodity ~~customer~~Sales ~~sales~~Firm ~~contracts~~Services ~~primarily~~Fee-Based ~~include~~Services ~~sales~~Revenue ofType ~~natural~~Customers ~~gas,~~specify ~~NGL,~~quantities ~~crude~~of ~~oil,~~commodity ~~CO2~~products to be delivered and ~~transmix,~~sold asat ~~described~~specified ~~below~~delivery points. ~~Generally,~~ Customers are generally subject to a fixed take-or-pay reservation fee or are subject to a minimum volume commitment for ~~the~~services. ~~majority~~Customers ofreceive ~~these~~non-firm ~~contracts~~or ~~(i)~~interruptible ~~each~~services, on an “as available” basis. Performance Obligation Each unit of commodity (Bcf, gallon, barrel, etc.) ~~of commodity~~ is a separate performance obligation, ~~as our~~ (promise is to sell multiple distinct units of commodity at a point in time~~; (ii~~). ~~the~~Promise ~~transaction~~to ~~price~~stand-ready ~~principally~~to ~~consists~~provide ofcontinuous ~~variable~~service ~~consideration~~availability, ~~which~~with ~~amount~~limited isexceptions, ~~determinable~~over ~~each month end based on our right to invoice at month end for~~ the ~~value~~contractual ofservice ~~commodity~~period ~~sold to the customer that month; and~~ (~~iii)~~a ~~the~~single ~~transaction price is allocated to each~~ performance obligation). ~~based~~Upon onacceptance ~~the~~of ~~commodity~~a customer’s ~~standalone~~periodic ~~selling~~service ~~price~~request, ~~and~~promise ~~recognized~~to asprovide ~~revenue~~a ~~upon~~series ~~delivery~~ of ~~the~~periodic ~~commodity,~~services ~~which~~over is the ~~point~~contractual inservice ~~time~~period ~~when~~(a ~~the~~single ~~customer obtains control of the commodity and our~~ performance obligation ~~is satisfied~~).

Our customer services contracts are primarily for transportation service, storage service, gathering and processing service, and terminaling, as described below. Generally, for the majority of these contracts (i) our promise is to transfer (or stand ready to transfer) a series of distinct integrated services over a period of time, which is a single performance obligation; (ii) the 79

81Commodity Sales Firm Services Fee-Based Services Transaction Price Variable consideration (typically market-indexed per unit rate), for the value of commodities sold. Fixed consideration, including payment for a minimum fixed fee, even if service is not used or received. Variable consideration (typically fee-based per unit rate), based on invoicing right for units of service transferred. Allocation of Transaction Price Allocated to each performance obligation, based on the commodity’s standalone selling price. Allocated ratably over the contractual service period. Allocated to a single performance obligation of providing services over the contractual service period. Performance Obligation Satisfaction Upon delivery of the commodity. Based on the passage of time, as the service period expires. As each unit of service is transferred to the customer in the specified service period.

transaction price includes fixed and/or variable consideration, which amount is determinable at contract inception and/or at each month end based on our right to invoice at month end for the value of services provided to the customer that month; and (iii) the transaction price is recognized as revenue over the service period specified in the contract (which can be a day, including each day in a series of promised daily services, a month, a year, or other time increment, in

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