Cover and table of contents

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

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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, 2025

or

☐			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

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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 30, 2025 was approximately $57,054,291,328. As of February 12, 2026, the registrant had 2,224,806,397 shares of Class P common stock outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

KINDER MORGAN, INC. AND SUBSIDIARIES
TABLE OF CONTENTS
						Page Number
			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
			Regulation			17
			Human Capital			22
			Properties and Rights-of-Way			23
			Available Information			23
Item 1A.			Risk Factors			23
Item 1B.			Unresolved Staff Comments			37
Item 1C.			Cybersecurity			37
Item 3.			Legal Proceedings			38
Item 4.			Mine Safety Disclosures			39
			PART II
Item 5.			Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			40
Item 6.			[Reserved]			40
Item 7.			Management’s Discussion and Analysis of Financial Condition and Results of Operations			40
			General			40
			Critical Accounting Estimates			41
			Results of Operations			42
			Overview			42
			Consolidated Earnings Results			46
			Non-GAAP Financial Measures			48
			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
						Page Number
			Off Balance Sheet Arrangements			60
			Contractual Obligations and Commercial Commitments			60
			Cash Flows			61
			Dividends and Stock Buy-back Program			62
			Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries			63
			Recent Accounting Pronouncements			64
Item 7A.			Quantitative and Qualitative Disclosures About Market Risk			64
			Energy Commodity Market Risk			64
			Interest Rate Risk			65
			Foreign Currency Risk			65
Item 8.			Financial Statements and Supplementary Data			66
			Index to Financial Statements			66
Item 9.			Changes in and Disagreements with Accountants on Accounting and Financial Disclosure			119
Item 9A.			Controls and Procedures			120
Item 9B.			Other Information			120
Item 9C.			Disclosure Regarding Foreign Jurisdictions that Prevent Inspections			120
			PART III
Item 10.			Directors, Executive Officers and Corporate Governance			121
Item 11.			Executive Compensation			121
Item 12.			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			121
Item 13.			Certain Relationships and Related Transactions, and Director Independence			121
Item 14.			Principal Accounting Fees and Services			121
			PART IV
Item 15.			Exhibits, Financial Statement Schedules			122
Item 16.			Form 10-K Summary			125
Signatures						126

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

CALNEV			=			Calnev Pipe Line LLC			KMLP			=			Kinder Morgan Louisiana Pipeline LLC
CIG			=			Colorado Interstate Gas Company, L.L.C.			KMLT			=			Kinder Morgan Liquid Terminals, LLC
CPGPL			=			Cheyenne Plains Gas Pipeline Company, L.L.C.			KMP			=			Kinder Morgan Energy Partners, L.P. and its majority-owned and/or controlled subsidiaries
EagleHawk			=			BPX (Eagle Ford) Gathering LLC, formerly known as EagleHawk Field Services
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			SFPP			=			SFPP, L.P.
GCX			=			Gulf Coast Express Pipeline LLC			SLNG			=			Southern LNG Company, L.L.C.
Hiland			=			Hiland Partners, LP			SNG			=			Southern Natural Gas Company, L.L.C.
KinderHawk			=			KinderHawk Field Services LLC			Stagecoach			=			Stagecoach Gas Services LLC
KMBT			=			Kinder Morgan Bulk Terminals, Inc.			TGP			=			Tennessee Gas Pipeline Company, L.L.C.
KMI			=			Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries			WIC			=			Wyoming Interstate Company, L.L.C.
WYCO			=			WYCO Development L.L.C.
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
/d			=			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
IT			=			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;

• 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, 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;

• interruptions of operations at our facilities due to natural disasters, damage by third parties, power shortages, strikes, riots, terrorism (including cyber-attacks), or other causes;

• extraordinary events such as pandemics, acts of war, or terrorist acts, including cybersecurity breaches, and the collateral impacts of such events, including disruptions of supply chains and economic activity;

• 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;

• 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

• 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.

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, 2025, we owned an interest in or operated approximately 78,000 miles of pipelines, 136 terminals, approximately 706 Bcf of working natural gas storage capacity, and RNG generation capacity of approximately 6.9 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels, and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, 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 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 or divestiture
Gas gathering and processing system 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.						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
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
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
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

Asset or project						Description						Activity						Approx. Capital Scope (KMI Share)
Other Construction Projects
Natural Gas Pipelines
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
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
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						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 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
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
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

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
CO**2
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, LNG liquefaction and terminal facilities, and NGL fractionation facilities, and includes both FERC regulated and non-FERC regulated assets.

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 42,000 miles of wholly owned natural gas pipelines and (ii) our equity interests in entities that have approximately 25,000 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, 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		%				11,760						14.56						76
NGPL						37.5		%				9,105						8.40						288
KMLP						100		%				140						3.89						—
Stagecoach						100		%				185						3.22						41
SNG(a)						50		%				6,830						4.39						66
Florida Gas Transmission (Citrus)						50		%				5,375						4.70						—
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		%				10,725						6.41						44
CIG(b)						100		%				4,305						6.00						38
WIC						100		%				850						3.50						—
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		%				6,125						9.30						146 [0.52]
Mier-Monterrey pipeline						100		%				90						0.65						—
KM North Texas pipeline						100		%				80						0.33						—
GCX						34		%				530						2.02						—
PHP						27.74		%				440						2.66						—
South Texas
South Texas system						100		%				1,145						2.07						[1.02]
Webb/Duval gas gathering system						91		%				145						0.20						—
Camino Real						100		%				75						0.15						—
KM Altamont						100		%				1,365						0.21						[0.10]
Red Cedar						49		%				845						0.33						—
Rocky Mountain
Fort Union						50		%				315						1.25						—
Bighorn						51		%				215						1.30						—
KinderHawk						100		%				585						2.40						—
Greenholly Gathering						39.25		%				40						1.15						—
KM Treating						100		%				40						—						—
Hiland Midstream						100		%				2,310						0.89						[0.60]
Hiland Express						100		%				550						0.95						—
Eagle Ford Transmission system						100		%				170						1.42						—
NET Mexico						90		%				140						2.15						—
Dos Caminos						50		%				95						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]						—

(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.

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. As contracts expire, we have additional exposure to the longer term trends in supply and demand for natural gas. As of December 31, 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 12 years.

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.

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.

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 transportation rates 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. 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, 2025:

			Number						Capacity (MMBbl)
Liquids terminals			47						78.7
Bulk terminals			24						—
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, 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 at 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.

CO**2

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, 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, 2025 includes:

Asset						Ownership Interest						Miles of Pipeline						Transport Capacity (Bcf/d) [(MBbl/d)]
CO****2 pipelines
Cortez						53		%				572						1.5
Central Basin						100		%				326						0.7
Bravo(a)						13		%				218						0.3
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		%				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, 2025 included the following:

						Working Interest						KMI Gross Developed Acres
SACROC						97		%				52,029
North McElroy						99		%				11,612
Yates						50		%				9,718
Diamond M						99		%				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, 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, 2025 included:

Asset						Ownership Interest						Production [Storage] Generation Capacity(a)						Product
LNG Indy						100		%				[2 Bcf]						LNG
Indy High BTU						50		%				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
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).

CO2 Segment Contracts

Our CO2 source and transportation business primarily has third-party sales contracts with minimum volume requirements, which as of December 31, 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 RIN sales are affected by the prices we realize from these sales and, over the long term, we tend to receive prices that are driven by the related demand and overall market. However, in the shorter term, 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. 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, and 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 nearly $1.6 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 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.

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 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.”

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 liabilities, 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.

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.

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 GHGs.

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. Certain of our facilities are subject to these reporting requirements, and operational or physical changes to other existing facilities could subject those facilities to these requirements. In recent years, EPA also made regulatory changes requiring many existing oil and natural gas facilities to reduce GHG emissions. However, in 2025, EPA announced its intention to reconsider the endangerment finding, as well as EPA’s mandatory GHG Reporting Program, and on February 12, 2026, the EPA announced that it will issue a final rule rescinding the endangerment finding, thereby eliminating the basis for much of its regulation of GHG emissions. Based on EPA’s recent rulemakings and disclosed objectives, we may experience a reduction in GHG reporting and other regulatory obligations at the federal level over the near 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

costs to install new monitoring equipment or emission controls on the facilities, acquire and surrender allowances for the GHG emissions, replace certain GHG-emitting devices or technologies, pay taxes related to the GHG emissions, and administer and manage a more comprehensive GHG emissions program. While we may be able to include some or all of such increased costs in the rates charged by our pipelines, recovery of costs is uncertain and may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or other regulatory bodies, and the provisions of any final legislation or other regulations.

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 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. PHMSA also requires us to conduct additional assessments to identify risks in what are referred to as Moderate Consequence Areas (MCAs) for gas pipelines.

PHMSA has implemented several rules that have increased our pipeline safety 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 identify the individuals responsible for implementing the specific measures in the CIRP 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

in the final rule include developing and maintaining a cybersecurity plan, designating a cybersecurity officer (CySO), and taking various measures to maintain cybersecurity within the MTS. The regulation contains a phased implementation schedule, with the full cybersecurity plan submission and CySO designation due by July 16, 2027, aiming to strengthen the MTS against cyber threats.

In addition, PHMSA requires reporting of certain events that involve a release from a pipeline or the shutdown of an 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. In 2024, CISA also issued a proposed rulemaking to implement the requirements set forth in the Cyber Incident Reporting for Critical Infrastructure Act of 2022, a law concerning the reporting of cyber incidents and ransomware payments. A final rule is currently projected for the middle 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 11,028 full-time personnel at December 31, 2025, including approximately 867 full-time hourly personnel at certain terminals and pipelines covered by collective bargaining agreements that expire between 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 non-zero employee safety performance targets as follows:

Non-zero employee safety performance targets						2025 Company-wide TRIR(a)
Outperform the annual industry average total recordable incident rate (TRIR)						0.9
Outperform our own three-year TRIR average

(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.