Kinder Morgan KMI Form 10-Q filing Q2 FY2026

Page Number

Glossary 2

Information Regarding Forward-Looking Statements 3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Consolidated Statements of Income - Three and Six Months Ended June 30, 2026 and 2025 4

Consolidated Statements of Comprehensive Income - Three and Six Months Ended June 30, 2026 and 2025 5

Consolidated Balance Sheets - as of June 30, 2026 and December 31, 2025 6

Consolidated Statements of Cash Flows - Six Months Ended June 30, 2026 and 2025 7

Consolidated Statements of Stockholders’ Equity - Three and Six Months Ended June 30, 2026 and 2025 9

Notes to Consolidated Financial Statements 10

Note 1. General 10

Note2. Acquisitions 11

Note 3. Debt 12

Note 4. Stockholders’Equity 13

Note 5. Risk Management 14

Note 6. Revenue Recognition 19

Note 7. Reportable Segments 22

Note 8. Income Taxes 26

Note 9. Litigation and Environmental 26

Note 10. Recent Accounting Pronouncements 30

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

General and Basis of Presentation 31

Results of Operations 31

Overview 31

Consolidated Earnings Results 34

Non-GAAP Financial Measures 37

Segment Earnings Results 39

Liquidity and Capital Resources 47

Summarized Combined Financial Information for Guarantee of Securities of Subsidiaries 51

Item 3. Quantitative and Qualitative Disclosures About Market Risk 52

Item 4. Controls and Procedures 52

PART II. OTHER INFORMATION

Item 1. Legal Proceedings 52

Item 1A. Risk Factors 52

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 52

Item 3. Defaults Upon Senior Securities 52

Item 4. Mine Safety Disclosures 52

Item 5. Other Information 52

Item 6. Exhibits 54

Signature 55

KINDER MORGAN, INC. AND SUBSIDIARIES

GLOSSARY

Company Abbreviations

• KMBT = Kinder Morgan Bulk Terminals, Inc. KMLT = Kinder Morgan Liquid Terminals, LLC
• KMI = Kinder Morgan, Inc. and its majority-owned and/or controlled subsidiaries TGP = Tennessee Gas Pipeline Company, 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 LNG = liquefied natural gas
• Bbl = barrels MBbl = thousand barrels
• BBtu = billion British Thermal Units MMBbl = million barrels
• Bcf = billion cubic feet MMtons = million tons
• CERCLA = Comprehensive Environmental Response, Compensation and Liability Act NGL = natural gas liquids
• NYMEX = New York Mercantile Exchange
• CO2 = carbon dioxide or our CO2 business segment OTC = over-the-counter
• DD&A = depreciation, depletion and amortization RIN = Renewable Identification Number
• EPA = U.S. Environmental Protection Agency RNG = Renewable natural gas
• FASB = Financial Accounting Standards Board ROU = Right-of-Use
• GAAP = U.S. Generally Accepted Accounting Principles U.S. = United States of America
• IT = Information Technology WTI = West Texas Intermediate
• LLC = limited liability company

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

Item 1. Financial Statements.

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

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

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

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

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

KINDER MORGAN, INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(Unaudited)

1. General

Organization

We are one of the largest energy infrastructure companies in North America. We own an interest in or operate approximately 78,000 miles of pipelines, 136 terminals, over 700 Bcf of working natural gas storage capacity, and RNG generation capacity of approximately 6.9 Bcf per year of gross production. Our pipelines transport natural gas, refined petroleum products, crude oil, condensate, CO2, renewable fuels, and other products, and our terminals store and handle various commodities including gasoline, diesel fuel, jet fuel, chemicals, metals, petroleum coke, and ethanol and other renewable fuels and feedstocks.

Basis of Presentation

General

Our accompanying unaudited consolidated financial statements have been prepared under the rules and regulations of the U.S. Securities and Exchange Commission (SEC). These rules and regulations conform to the accounting principles contained in the FASB’s Accounting Standards Codification (ASC), the single source of GAAP. In compliance with such rules and regulations, all significant intercompany items have been eliminated in consolidation.

In our opinion, all adjustments, which are of a normal and recurring nature, considered necessary for a fair statement of our financial position and operating results for the interim periods have been included in the accompanying consolidated financial statements, and certain amounts from prior periods have been reclassified to conform to the current presentation. Interim results are not necessarily indicative of results for a full year; accordingly, you should read these consolidated financial statements in conjunction with our consolidated financial statements and related notes included in our 2025 Form 10-K.

The accompanying unaudited consolidated financial statements include our accounts and the accounts of our subsidiaries over which we have control or are the primary beneficiary. We evaluate our financial interests in business enterprises to determine if they represent variable interest entities where we are the primary beneficiary. If such criteria are met, we consolidate the financial statements of such businesses with those of our own.

Goodwill

In addition to periodically evaluating long-lived assets and goodwill for impairment based on changes in market conditions, we evaluate goodwill for impairment on May 31 of each year. For our May 31, 2026 evaluation, we grouped our businesses into seven reporting units as follows: (i) Natural Gas Pipelines Regulated; (ii) Natural Gas Pipelines Non-Regulated; (iii) CO2; (iv) Products Pipelines (excluding associated terminals); (v) Products Pipelines Terminals (evaluated separately from Products Pipelines for goodwill purposes); (vi) Terminals; and (vii) Energy Transition Ventures.

The fair value estimates used in our goodwill impairment test include Level 3 inputs of the fair value hierarchy. The inputs include valuation estimates, which include assumptions primarily involving management’s judgments and estimates. For all reporting units other than the Energy Transition Ventures reporting unit within our CO2 business segment, we estimated fair value based on a market approach utilizing forecasted earnings before interest, income taxes, DD&A expenses (EBITDA), and the enterprise value to estimated EBITDA multiples of comparable companies for each of our reporting units. The value of each reporting unit was determined from the perspective of a market participant in an orderly transaction between market participants at the measurement date. For the Energy Transition Ventures reporting unit, which had a goodwill balance of $114 million as of June 30, 2026, we estimated fair value based on an income approach, which includes assumptions regarding future cash flows based primarily on production growth assumptions, terminal values, and discount rates.

The results of our May 31, 2026 annual impairment test indicated that for each of our reporting units, the reporting unit’s fair value exceeded the carrying value (by at least 10%). We did not identify any triggers requiring further impairment analysis subsequent to our annual goodwill impairment test. Changes to any one or a combination of the factors described above would result in a change to the reporting unit fair values, which could lead to future impairment charges. Such potential non-cash impairments could have a significant effect on our results of operations.

Earnings per Share (EPS)

The following table sets forth net income allocated to common stockholders and EPS, calculated using the two-class method:

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

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

2. Acquisitions

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

(1) Monument Pipeline System Acquisition

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

(2) Outrigger Energy Acquisition

On February 18, 2025, we completed the acquisition of a natural gas gathering and processing system in North Dakota from Outrigger Energy II LLC for a purchase price of $648 million, including purchase price adjustments for working capital. Other long-term assets within the purchase price allocation consists of customer relationships intangible with a weighted average amortization period of approximately 15 years. The acquisition includes a 0.27 Bcf/d processing facility and a 104-mile, large-diameter, high-pressure rich gas gathering header pipeline with 0.35 Bcf/d of capacity connecting supplies from the Williston Basin area to high-demand markets. The acquired assets are included in our Natural Gas Pipelines business segment.

Pro Forma Information

Pro forma consolidated income statement information that gives effect to the above acquisitions as if they had occurred as of January 1 of each year preceding each transaction is not presented because it would not be materially different from the information presented in our accompanying consolidated statements of income.

3. Debt

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

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

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

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

(d)Excludes our “Debt fair value adjustments” which, as of June 30, 2026 and December 31, 2025, increased our total debt balances by $104 million and $180 million, respectively.

We and substantially all of our wholly owned domestic subsidiaries are parties to a cross guarantee agreement whereby each party to the agreement unconditionally guarantees, jointly and severally, the payment of specified indebtedness of each other party to the agreement. In addition, substantially all of our wholly owned domestic subsidiaries guarantee our obligations under our credit facility pursuant to a guarantee agreement executed in connection with our credit facility.

Credit Facilities and Restrictive Covenants

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

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

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

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

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

As of June 30, 2026, we had no borrowings outstanding under our credit facility, $338 million borrowings outstanding under our commercial paper program, and $10 million in letters of credit. Our availability under our credit facility as of June 30, 2026 was approximately $3.2 billion. For the periods ended June 30, 2026 and 2025, we were in compliance with all required covenants.

Fair Value of Financial Instruments

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

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

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

4. Stockholders’ Equity

Class P Common Stock

Dividends

The following table provides information about our per share dividends:

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

Accumulated Other Comprehensive Income (Loss)

Changes in the components of our “Accumulated other comprehensive income (loss)” not including noncontrolling interests are summarized as follows:

5. Risk Management

Certain of our business activities expose us to risks associated with unfavorable changes in the market price of natural gas, NGL, and crude oil. We also have exposure to interest rate and foreign currency risk as a result of the issuance of our debt obligations. Pursuant to our management’s approved risk management policy, we use derivative contracts to hedge or reduce our exposure to some of these risks.

Energy Commodity Price Risk Management

As of June 30, 2026, we had the following outstanding commodity forward contracts to hedge our forecasted energy commodity purchases and sales:

As of June 30, 2026, the maximum length of time over which we have hedged, for accounting purposes, our exposure to the variability in future cash flows associated with energy commodity price risk is through December 2028.

Interest Rate Risk Management

We utilize interest rate derivatives to hedge our exposure to both changes in the fair value of our fixed rate debt instruments and variability in expected future cash flows attributable to variable interest rate payments. The following table summarizes our outstanding interest rate contracts as of June 30, 2026:

(a)The principal amount of hedged senior notes is included in “Long-term debt” on our accompanying consolidated balance sheets.

Foreign Currency Risk Management

We utilize foreign currency derivatives to hedge our exposure to variability in foreign exchange rates. The following table summarizes our outstanding foreign currency contracts as of June 30, 2026:

(a)These swaps eliminate the foreign currency risk associated with our Euro-denominated debt which matures in March 2027.

Impact of Derivative Contracts on Our Consolidated Financial Statements

The following table summarizes the fair values of our derivative contracts included on our accompanying consolidated balance sheets:

The following two tables summarize the fair value measurements of our derivative contracts based on the three levels established by the ASC. The tables also identify the impact of derivative contracts which we have elected to present on our accompanying consolidated balance sheets on a gross basis that are eligible for netting under master netting agreements.

(a)Any cash collateral paid or received is reflected in this table, but only to the extent that it represents variation margins. Any amount associated with derivative prepayments or initial margins that are not influenced by the derivative asset or liability amounts or those that are determined solely on their volumetric notional amounts are excluded from this table.

(b)Level 1 consists primarily of NYMEX natural gas futures. Level 2 consists primarily of OTC WTI swaps, NGL swaps, and crude oil basis swaps.

The following tables summarize the pre-tax impact of our derivative contracts on our accompanying consolidated statements of income and comprehensive income:

(a)As of June 30, 2026, the cumulative amount of fair value hedging adjustments resulted in a decrease of $152 million in the carrying value of our hedged fixed rate debt balance and is included in “Debt fair value adjustments” on our accompanying consolidated balance sheet.

(a)We expect to reclassify an approximate $6 million gain associated with cash flow hedge price risk management activities included in our accumulated other comprehensive loss balance as of June 30, 2026 into earnings during the next twelve months (when the associated forecasted transactions are also expected to impact earnings); however, actual amounts reclassified into earnings could vary materially as a result of changes in market prices.

(a)The amounts for the three and six months ended June 30, 2026 include approximate losses of $58 million and $89 million, respectively, and the amounts for the three and six months ended June 30, 2025 include approximate losses of $15 million and $16 million, respectively, associated with natural gas, crude, and NGL derivative contract settlements.

Credit Risks

In conjunction with certain derivative contracts, we are required to provide collateral to our counterparties, which may include posting letters of credit or placing cash in margin accounts. As of June 30, 2026 and December 31, 2025, we had no outstanding letters of credit supporting our commodity price risk management program. As of June 30, 2026 and December 31, 2025, we had cash margins of $20 million and $24 million, respectively, posted with our counterparties by us and reported within “Restricted deposits” on our accompanying consolidated balance sheets. The cash margin balance at June 30, 2026 represents the initial margin requirements of $12 million and variation margin requirements of $8 million. We also use industry standard commercial agreements that allow for the netting of exposures associated with transactions executed under a single

commercial agreement. Additionally, we generally utilize master netting agreements to offset credit exposure across multiple commercial agreements with a single counterparty.

We also have agreements with certain counterparties to our derivative contracts that contain provisions requiring the posting of additional collateral upon a decrease in our credit rating. As of June 30, 2026, based on our current mark-to-market positions and posted collateral, we estimate that if our credit rating were downgraded one or two notches, we would not be required to post additional collateral.

6. Revenue Recognition

Disaggregation of Revenues

The following tables present our revenues disaggregated by segment, revenue source, and type of revenue for each revenue source:

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

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

Contract Balances

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

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

Revenue Allocated to Remaining Performance Obligations

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

Based on the practical expedient we elected to apply, the amounts presented in the table above exclude remaining performance obligations for variable consideration related to contracts with index-based pricing or variable volume attributes in which such variable consideration is allocated entirely to a wholly unsatisfied performance obligation.

7. Reportable Segments

Our reportable segments are strategic business units that offer different products and services, have different marketing strategies, and are managed separately. The Company’s chief operating decision maker (CODM) is represented by the Office of the Chairman which consists of our Executive Chairman, Chief Executive Officer, and President. Our CODM evaluates performance principally based on each reportable segment’s earnings before DD&A expenses (EBDA), which excludes general and administrative expenses and corporate charges, interest expense, net, and income tax expense. The CODM uses budgeted Segment EBDA compared to actual results to evaluate performance and allocate certain resources for each segment.

We consider each period’s earnings before all non-cash DD&A expenses to be an important measure of business segment performance for our reporting segments. We account for intersegment sales at market prices, while we account for asset transfers at book value.

Financial information by segment follows:

(a)Includes outside services, pipeline integrity maintenance, materials and supplies, and other operating costs.

(b)Includes miscellaneous operating and non-operating items primarily related to allowance for equity funds used during construction.

(c)Includes non-cash risk management activities amounts for the three and six months ended June 30, 2026 of $60 million and $(15) million, $4 million and $(1) million, $1 million and none, and $19 million and $(2) million, respectively, for our Natural Gas Pipelines, Products Pipelines, Terminals, and CO2 business segments, respectively.

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

(e)Includes non-cash risk management activities amounts for the three and six months ended June 30, 2025 of $89 million and $9 million, none and $(1) million, and $5 million and $4 million, respectively, for our Natural Gas Pipelines, Products Pipelines, and CO2 business segments, respectively.

(f)Corporate includes cash and cash equivalents, restricted deposits, certain prepaid assets and deferred charges, risk management assets related to derivative contracts, corporate headquarters in Houston, Texas, and miscellaneous corporate assets (such as IT, telecommunications equipment, and legacy activity) not allocated to our reportable segments.

8. Income Taxes

Income tax expense included on our accompanying consolidated statements of income is as follows:

The effective tax rate for the three and six months ended June 30, 2026 is higher than the statutory federal rate of 21% primarily due to (i) an increase in deferred tax liability for Texas Margin Tax as a result of the enactment of changes to tax rules and (ii) state income taxes, partially offset by dividend-received deductions from our investments in Florida Gas Pipeline (Citrus), NGPL Holdings LLC, and Products (SE) Pipe Line Company (PPL).

The effective tax rate for the three months ended June 30, 2025 is lower than the statutory federal tax rate of 21% primarily due to (i) a reduction of our deferred tax liability as a result of changes in state income allocations and (ii) dividend-received deductions from our investments in Citrus, NGPL Holdings LLC, and PPL, partially offset by state income taxes.

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

9. Litigation and Environmental

We and our subsidiaries are parties to various legal, regulatory, and other matters arising from the day-to-day operations of our businesses or certain predecessor operations that may result in claims against the Company. Although no assurance can be given, we believe, based on our experiences to date and taking into account accrued liabilities and insurance, that the ultimate resolution of such items will not have a material adverse impact to our financial position, cash flows, or operating results, unless otherwise indicated below. We believe we have numerous and substantial defenses to the matters to which we are a party and intend to vigorously defend the Company. When we determine a loss is probable of occurring and is reasonably estimable, we accrue an undiscounted liability for such contingencies based on our best estimate using information available at that time. If the estimated loss is a range of potential outcomes and there is no better estimate within the range, we accrue the amount at the low end of the range. We disclose the following contingencies where an adverse outcome may be material or, in the judgment of management, we conclude the matter should otherwise be disclosed.

Gulf LNG Facility Disputes

Gulf LNG Energy, LLC and Gulf LNG Pipeline, LLC (GLNG) filed a lawsuit in 2018 against Eni S.p.A. in the Supreme Court of the State of New York to enforce a Guarantee Agreement (Guarantee) entered into by Eni S.p.A. in 2007 in connection with a terminal use agreement entered into by its affiliate, Eni USA Gas Marketing LLC (Eni USA). GLNG sought to enforce the Guarantee after an arbitration tribunal delivered an award which resulted in the termination of the terminal use agreement and payment of compensation by Eni USA to GLNG. In response, Eni S.p.A. filed counterclaims seeking unspecified damages based on the same allegations that had been dismissed with prejudice in previous arbitrations. In 2022, the trial court granted Eni S.p.A.’s motion for summary judgment on GLNG’s claims. GLNG elected not to pursue recourse to the Court of Appeals, thereby concluding GLNG’s efforts to enforce the Guarantee. With respect to the counterclaims asserted by Eni S.p.A., the trial court granted GLNG’s motion for summary judgment and dismissed Eni S.p.A.’s claims with prejudice. All appellate courts denied Eni S.p.A’s subsequent petitions seeking appellate review, thereby concluding this case.

Freeport LNG Winter Storm Litigation

On September 13, 2021, Freeport LNG Marketing, LLC (Freeport) filed a lawsuit against Kinder Morgan Texas Pipeline LLC and Kinder Morgan Tejas Pipeline LLC in the 133rd District Court of Harris County, Texas (Case No. 2021-58787) alleging that defendants breached the parties’ base contract for sale and purchase of natural gas by failing to repurchase natural gas nominated by Freeport between February 10-22, 2021 during Winter Storm Uri. We deny that we were obligated to repurchase natural gas from Freeport given our declaration of force majeure during the storm and our compliance with emergency orders issued by the Railroad Commission of Texas providing heightened priority for the delivery of gas to human needs customers. Freeport alleges that it is owed approximately $104 million, plus attorney fees and interest. On October 24, 2022, the trial court granted our motion for summary judgment on all of Freeport’s claims. On April 15, 2025, the 14th Court of Appeals reversed and remanded the case to the trial court for further proceedings to resolve disputed issues of material fact. We believe we have numerous and substantial defenses and intend to continue to vigorously defend this case.

Pension Plan Litigation

On February 22, 2021, Kinder Morgan Retirement Plan A participants Curtis Pedersen and Beverly Leutloff filed a purported class action lawsuit under the Employee Retirement Income Security Act of 1974 (ERISA). The named plaintiffs were hired initially by the ANR Pipeline Company (ANR) in the late 1970s. Following a series of corporate acquisitions, plaintiffs became participants in pension plans sponsored by the Coastal Corporation (Coastal), El Paso Corporation (El Paso) and our company by virtue of our acquisition of El Paso in 2012 and our assumption of certain of El Paso’s pension plan obligations. The complaint, which was transferred to the U.S. District Court for the Southern District of Texas (Civil Action No. 4:21-3590) and amended to include the Kinder Morgan Retirement Plan B, alleges that the series of foregoing transactions resulted in changes to plaintiffs’ retirement benefits that are now contested on a class-wide basis. The complaint asserts six claims that fall within three primary theories of liability. Claims I, II, and III challenge plan provisions that are alleged to constitute impermissible “backloading” or “cutback” of benefits and seek the same plan modification as to how the plans calculate benefits for former participants in the Coastal plan. Claims IV and V allege that former participants in the ANR plans should be eligible for unreduced benefits at younger ages than the plans currently provide. Claim VI asserts that actuarial assumptions used to calculate reduced early retirement benefits for current or former ANR employees are outdated and therefore unreasonable. On February 8, 2024, the Court certified a class defined as any and all persons who participated in the Kinder Morgan Retirement Plan A or B who are current or former employees of ANR or Coastal, and participated in the El Paso pension plan after El Paso acquired Coastal in 2001, and are members of at least one of three subclasses of individuals who are allegedly due benefits. On July 25, 2024, the Court granted our motion for summary judgment with respect to Claims I and II based on the Court’s determination that the formula used to calculate projected service was neither backloaded nor a violation of ERISA’s anti-cutback rule. The Court granted plaintiffs’ motion for partial summary judgment with respect to Claim III because the Court found that the summary plan description did not include any clarifying examples or illustrations of accrued benefits using the applicable formula. The Court granted plaintiffs’ motion for partial summary judgment as to Claim IV based on its finding that an amendment to the plan in 2007 violated ERISA’s anti-cutback protection by terminating the accrual of early retirement benefits in connection with the sale of ANR. The Court granted plaintiffs’ motion for partial summary judgment as to Claim V based on its finding that the plan administrator used an inconsistent interpretation to calculate benefits for some retirees. The Court dismissed Claim VI without prejudice based on its finding that the claim is moot given the Court’s rulings on Claims IV and V. The Court’s decision on partial summary judgment did not address the extent of potential plan liabilities for past or future benefits or other potential damages or equitable relief. On March 11, 2025, the case was mediated without resolution, after which the parties filed summary judgment motions to address potential remedies for the remaining claims. Plaintiffs seek equitable and other relief including early retirement benefits, monetary damages, or other equitable relief estimated to be in excess of $100 million. We vigorously oppose the form and scope of relief sought by the plaintiffs and believe we have numerous and substantial defenses to support our vigorous defense at the trial or appellate levels if necessary. On April 22, 2025, the case was referred to a Magistrate Judge to conduct all pretrial proceedings including recommended rulings on plaintiffs’ motion for equitable remedies. On February 10, 2026, the Magistrate Judge issued a Memorandum and Recommendation that plaintiffs’ motion for equitable relief should be granted in part and denied in part. The Memorandum and Recommendation rejected or significantly narrowed a number of plaintiffs’ theories of recovery. The presiding U.S. District Court Judge may adopt, modify, or reject the Memorandum and Recommendation. To the extent an adverse judgment or settlement results in an increase in plan liabilities, we may elect as the sponsor of the plans to address them in accordance with applicable ERISA provisions, including provisions that allow for contributions to the plans over multiple years.

Pipeline Integrity and Releases

From time to time, despite our best efforts, our pipelines experience leaks and ruptures. These leaks and ruptures may cause explosions, fire, and damage to the environment, damage to property, and/or personal injury or death. In connection with these

incidents, we may be sued for damages caused by an alleged failure to properly mark the locations of our pipelines and/or to properly maintain our pipelines. Depending upon the facts and circumstances of a particular incident, state and federal regulatory authorities may seek civil and/or criminal fines and penalties.

Environmental Matters

We and our subsidiaries are subject to environmental cleanup and enforcement actions from time to time. In particular, CERCLA generally imposes joint and several liability for cleanup and enforcement costs on current and predecessor owners and operators of a site, among others, without regard to fault or the legality of the original conduct, subject to the right of a liable party to establish a “reasonable basis” for apportionment of costs. Our operations are also subject to local, state, and federal laws and regulations relating to protection of the environment. Although we believe our operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in pipeline, terminal, CO2 field and oil field, and our other operations, and there can be no assurance that we will not incur significant costs and liabilities. Moreover, it is possible that other developments could result in substantial costs and liabilities to us, such as increasingly stringent state environmental laws, regulations and enforcement policies under the terms of authority of those laws, and claims for damages to property or persons resulting from our operations. Although it is not possible to predict the ultimate outcomes, we believe that the resolution of the environmental matters set forth in this note, and other matters to which we and our subsidiaries are a party, will not have a material adverse effect on our financial position, cash flows, or operating results.

We are currently involved in several governmental proceedings involving alleged violations of local, state, and federal environmental and safety regulations. As we receive notices of non-compliance, we attempt to negotiate and settle such matters where appropriate. These alleged violations may result in fines and penalties, but except as disclosed herein we do not believe any such fines and penalties will be material to our financial position, cash flows, or operating results, individually or in the aggregate. We are also currently involved in several governmental proceedings involving groundwater and soil remediation efforts under state or federal administrative orders or related remediation programs. We have accrued for costs associated with the remediation efforts as described below.

In addition, we are involved with and have been identified as a potentially responsible party (PRP) in several federal and state Superfund sites. Environmental liabilities have been established for those sites where our contribution is probable and reasonably estimable. Because costs associated with remedial plans are generally expected to be spread over at least several years, we do not anticipate that our share of the cost of remediation will have a material adverse impact to our financial position, cash flows, or operating results. In addition, we are from time to time involved in civil proceedings relating to damages alleged to have occurred as a result of accidental leaks or spills of refined petroleum products, crude oil, NGL, natural gas, or CO2, including natural resource damage (NRD) claims.

Portland Harbor Superfund Site, Willamette River, Portland, Oregon

On January 6, 2017, the EPA issued a Record of Decision (ROD) that established a final remedy and cleanup plan for an industrialized area on the lower reach of the Willamette River commonly referred to as the Portland Harbor Superfund Site (PHSS). The cost for the final remedy is estimated to be more than $2.8 billion and active cleanup is expected to take more than 10 years to complete. KMLT, KMBT, and some 90 other PRPs identified by the EPA are involved in a non-judicial allocation process to determine each party’s respective share of the cleanup costs related to the final remedy set forth by the ROD. We are participating in the allocation process on behalf of KMLT (in connection with its ownership or operation of two facilities) and KMBT (in connection with its ownership or operation of two facilities). Effective January 31, 2020, KMLT entered into separate Administrative Settlement Agreements and Orders on Consent (ASAOC) to complete remedial design for two distinct areas within the PHSS associated with KMLT’s facilities. The ASAOC obligates KMLT to pay a share of the remedial design costs for cleanup activities related to these two areas as required by the ROD. Our share of responsibility for the PHSS costs will not be determined until the ongoing non-judicial allocation process is concluded or a lawsuit is filed that results in a judicial decision allocating responsibility. At this time, we anticipate the non-judicial allocation process will be complete by December 31, 2026. Until the allocation process is completed, we are unable to reasonably estimate the extent of our liability for the costs related to the design of the proposed remedy and cleanup of the PHSS. In August 2024, we reached an agreement to settle other claims first made in January 2021 asserted by natural resource state and federal trustees relating to natural resource damages at the PHSS.

Lower Passaic River Study Area of the Diamond Alkali Superfund Site, New Jersey

EPEC Polymers, Inc. and EPEC Oil Company Liquidating Trust (collectively EPEC) are identified as PRPs in an administrative action under CERCLA known as the Lower Passaic River Study Area (Site) concerning the lower 17-mile stretch of the Passaic River in New Jersey. On March 4, 2016, the EPA issued a ROD for the lower eight miles of the Site. At

that time the cleanup plan in the ROD was estimated to cost $1.7 billion. The cleanup is expected to take at least six years to complete once it begins. In addition, the EPA and numerous PRPs, including EPEC, engaged in an allocation process for the implementation of the remedy for the lower eight miles of the Site. That process was completed December 28, 2020 and certain PRPs, including EPEC, engaged in discussions with the EPA as a result thereof. On October 4, 2021, the EPA issued a ROD for the upper nine miles of the Site. At that time, the cleanup plan in the ROD was estimated to cost $440 million. No timeline for the cleanup has been established. On December 16, 2022, the United States Department of Justice (DOJ) and the EPA announced a settlement and proposed consent decree with 85 PRPs, including EPEC, to resolve their collective liability at the Site. The total amount of the settlement is $150 million. Also on December 16, 2022, the DOJ on behalf of the EPA filed a Complaint against the 85 PRPs, including EPEC, a Notice of Lodging of Consent Decree, and a Consent Decree in the U.S. District Court for the District of New Jersey in a case captioned USA v. Alden Leeds, et al. On January 17, 2024, the DOJ on behalf of the EPA voluntarily dismissed its Complaint against 3 PRPs, filed an Amended Complaint against 82 PRPs, including EPEC, and a modified Consent Decree in the U.S. District Court. On January 31, 2024, the DOJ on behalf of the EPA filed a Motion to Enter Consent Decree in the U.S. District Court. On January 16, 2025, the U.S. District Court entered the Consent Decree, after which time, the Consent Decree was appealed to the U.S. Court of Appeals for the Third Circuit by two PRPs including Occidental Chemical Corporation (OCC), alleging, inter alia, that the Consent Decree is not procedurally and substantively fair, reasonable, and consistent with the purpose of CERCLA. On February 6, 2026, certain corporate parties who are PRPs and parties to the Consent Decree filed BASF Catalysts LLC, et al. v. Occidental Chemical Corporation (OCC) in U.S. District Court for the District of New Jersey alleging that OCC’s recent attempt to contractually transfer environmental liabilities through a corporate reorganization process violated CERCLA. Plaintiffs seek a declaratory judgment that (1) any purported transfer or allocation of CERCLA liability through the reorganization is precluded by CERCLA, and (2) that the Occidental entity that holds the assets of the former OCC is jointly and severally liable for the former OCC’s CERCLA liabilities. While we are not a party to the most recent lawsuit, the results could potentially impact the amount we and other PRPs ultimately are required to contribute to this CERCLA site.

Louisiana Governmental Coastal Zone Erosion Litigation

On November 8, 2013, the Parish of Plaquemines, Louisiana and others filed petitions in the state district court for Plaquemines Parish against TGP and 17 other energy companies, alleging that the defendants’ operations in Plaquemines Parish violated the State and Local Coastal Resources Management Act of 1978, as amended and Louisiana law and caused substantial damage to the coastal waters and nearby lands. Plaintiffs seek, among other relief, unspecified money damages, attorney fees, interest, and restoration costs. In 2018, the case was removed to the U.S. District Court for the Eastern District of Louisiana and then stayed. We expect the case will remain in federal court. At this time, we are not able to reasonably estimate the extent of our potential liability, if any. We intend to vigorously defend this case.

General

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

Challenge to Federal “Good Neighbor Plan”

On July 14, 2023, we filed a Petition for Review against the EPA and others in the U.S. Court of Appeals for the District of Columbia Circuit (the DC Circuit) seeking review of the EPA’s final action promulgating a federal implementation plan to address certain interstate transport requirements of the Clean Air Act for the 2015 8-hour Ozone National Ambient Air Quality Standards (NAAQS), known as the “Good Neighbor Plan” (the Plan) (Kinder Morgan, Inc., et al. v. EPA, et al. consolidated into Utah, et al. v. EPA, et al.). On October 13, 2023, in combination with other parties, we filed an Emergency Application for Stay of Final Agency Action in the United States Supreme Court (Kinder Morgan, Inc., et al. v. EPA, et al. consolidated into Ohio, et al. v. EPA, et al.), which the court granted on June 27, 2024, ruling that enforcement of the Plan shall be stayed pending the disposition of the case on the merits by the DC Circuit and any subsequent timely appeals.

Subsequently, the EPA filed a Motion for Remand asking the DC Circuit to remand without vacatur the Plan to the EPA for voluntary reconsideration, explaining that the “EPA has identified specific issues with the Rule that make reconsideration appropriate, including issues raised by Petitioners in this litigation.” On April 14, 2025, the DC Circuit held the case in abeyance pending further order of the court and ordered the parties to file periodic status reports until the EPA completes its review of the Plan. On January 27, 2026, the EPA proposed approving eight state implementation plans to address ozone emissions which were originally disapproved by the EPA. If finalized, those states would be removed from the EPA’s federal Good Neighbor Plan and its requirements would not apply to our facilities.

10. Recent Accounting Pronouncements

Accounting Standards Updates (ASU)

ASU No. 2024-03

On November 4, 2024, the FASB issued ASU No. 2024-03, “Income Statement—Reporting Comprehensive Income—Expense Disaggregation Disclosures (Subtopic 220-40).” This ASU improves financial reporting by requiring that public business entities disclose additional information about specific expense categories in the notes to financial statements at interim and annual reporting periods. This ASU will be effective for annual periods beginning after December 15, 2026, for interim reporting periods beginning after December 15, 2027, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s disclosures.

ASU No. 2025-06

On September 18, 2025, the FASB issued ASU No. 2025-06, “Intangibles—Goodwill and Other—Internal-Use Software (Subtopic 350-40): Targeted Improvements to the Accounting for Internal-Use Software.” This ASU modernizes the accounting guidance for the costs to develop software for internal use by removing outdated stage-based cost capitalization rules and replacing them with a probability-based cost-capitalization framework that aligns better with current software development methods. This ASU will be effective for annual periods beginning after December 15, 2027, for interim reporting periods beginning within those annual periods, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s financial statements.

ASU No. 2025-09

On November 25, 2025, the FASB issued ASU No. 2025-09, “Derivatives and Hedging (Topic 815): Hedge Accounting Improvements.” This ASU makes targeted improvements to Topic 815 to better align hedge accounting with the economics of an entity’s risk-management activities. This ASU will be effective for annual periods beginning after December 15, 2026, for interim reporting periods beginning within those annual periods, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s financial statements.

ASU No. 2025-10

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

ASU No. 2026-02

On May 19, 2026, the FASB issued ASU No. 2026-02, “Environmental Credits and Environmental Credit Obligations (Topic 818).” This ASU establishes guidance on the recognition, measurement, presentation, and disclosure of environmental credits and compliance obligations that may be settled by using environmental credits. US GAAP did not previously address how to account for these items. The ASU will be effective for annual periods beginning after December 15, 2027, for interim reporting periods beginning within those annual periods, and early adoption is permitted. Management is currently evaluating this ASU to determine its impact on the Company’s financial statements.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

General and Basis of Presentation

The following discussion and analysis should be read in conjunction with our accompanying interim consolidated financial statements and related notes included elsewhere in this report, and in conjunction with (i) our consolidated financial statements and related notes in our 2025 Form 10-K; (ii) our management’s discussion and analysis of financial condition, and results of operations included in our 2025 Form 10-K; (iii) “Information Regarding Forward-Looking Statements” at the beginning of this report, and in our 2025 Form 10-K; and (iv) “Risk Factors” in Part I, Item 1A in our 2025 Form 10-K.

Acquisition

The following acquisition was made during the 2026 period. See Note 2 “Acquisitions” to our consolidated financial statements for further information on this transaction.

Event Description Business Segment

Monument Pipeline system acquisition $503 million (May 2026) Natural gas pipeline system serving Houston, Texas and the surrounding metropolitan area which includes approximately 225 miles of pipelines and provides transportation and storage services to gas utilities, LNG shippers, and industrial customers. Natural Gas Pipelines (Midstream)

2026 Dividends and Discretionary Capital

We expect to declare dividends of $1.19 per share for 2026, a 2% increase from the 2025 declared dividends of $1.17 per share. We expect to invest $4.1 billion in expansion projects, acquisitions, and contributions to joint ventures during 2026.

The expectations for 2026 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.

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 (EBDA) (as presented in Note 7 “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 (EBITDA), and Net Debt.

GAAP Financial Measures

Our Consolidated Earnings Results for the three and six months ended June 30, 2026 and 2025 present Net income attributable to Kinder Morgan, Inc., as prepared and presented in accordance with GAAP, and Segment EBDA, which is disclosed in Note 7 “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 (i) do not have a cash impact (for example, unsettled commodity hedges and asset impairments), (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 cash 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 associated with Joint Ventures” below). The following table summarizes our Certain Items for the three and six months ended June 30, 2026 and 2025, which are also described in more detail in the footnotes to tables included in “—Segment Earnings Results” below.

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

(b)Includes natural gas inventory hedges of which gains or losses are reflected within non-GAAP financial measures when the associated physical gas is withdrawn from inventory.

(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.

(d)Amounts for the periods ended June 30, 2026 and 2025 include $(1) million and $(2) million for the three-month periods, respectively, and $(1) million for the six-month 2026 period reported within “Earnings from equity investments” on the accompanying consolidated statement of income of “Risk management activities.”

(e)2025 amounts for the three and six-month periods include $(1) million and $1 million, respectively, reported within “Interest, net” on the accompanying consolidated statement of income of “Risk management 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, 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 “—Segment Earnings 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, including the amortization of basis differences related to our joint ventures, income tax expense, and interest. We also include amounts from joint ventures for income taxes and DD&A (see “—Amounts 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.

Amounts associated with Joint Ventures

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 includes the same adjustments (DD&A, including the amortization of basis differences related to joint ventures only, 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 June 30, 2026, by subtracting the following amounts from our debt balance of $32,248 million: (i) cash and cash equivalents of $89 million; (ii) debt fair value adjustments of $104 million; and (iii) the foreign exchange impact on Euro-denominated bonds of $28 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.

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 three and six-month periods ended June 30, 2026 and 2025:

Revenues

Revenues increased $435 million and $1,022 million for the three and six months ended June 30, 2026, respectively, as compared to the respective prior year periods. These increases were primarily due to (i) increases in product sales of $422 million and $388 million, respectively, driven by higher commodity prices and volumes; (ii) increases in services revenues of $138 million and $295 million, respectively, resulting from higher volumes, including expansion projects placed into service, primarily in our Natural Gas Pipelines business segment; and (iii) an increase in the six-month period in natural gas sales of $387 million due to higher volumes and commodity prices. These increases in revenues were partially offset by $49 million and $63 million, respectively, for the impacts of derivative contracts used to hedge commodity sales and a decrease in the three-month period in natural gas sales of $73 million, due to lower commodity prices partially offset by higher volumes. The

increases in sales revenues were partially offset by corresponding increases 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 increased $194 million and $467 million for the three and six months ended June 30, 2026, respectively, as compared to the respective prior year periods. The increases were primarily due to (i) increases of $245 million and $176 million, respectively, in costs of sales for products driven by higher commodity prices and volumes; (ii) increases of $82 million and $103 million, respectively, related to derivative contracts used to hedge commodity purchases; and (iii) an increase in the six-month period of $187 million in costs of sales for natural gas primarily due to higher volumes partially offset by lower commodity prices. The three-month period increase was partially offset by a decrease of $112 million in costs of sales for natural gas due to lower commodity prices partially offset by higher volumes.

Operations and Maintenance

Operations and maintenance increased $33 million for each of the three and six months ended June 30, 2026, respectively, as compared to the respective prior year periods. The increases were primarily driven by greater activity, including labor costs, and inflation.

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. Interest, net decreased $27 million and $48 million for the three and six months ended June 30, 2026, respectively, compared to the respective prior year periods. These decreases were primarily due to higher capitalized interest and lower interest rates associated with our fixed-to-variable interest rate swap agreements. The six-month period decrease was also due to lower average short-term debt balances partially offset by higher interest rates on our long-term debt.

Non-GAAP Financial Measures

Reconciliations from Net Income Attributable to Kinder Morgan, Inc.

(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)Other for each of the periods ended June 30, 2026 and 2025 includes Adjusted net income in excess of distributions for participating securities of less than $1 million.

(d)To avoid duplication, adjustments for income tax expense for the periods ended June 30, 2026 and 2025 exclude $37 million and $(2) million for the three-month periods, respectively, and $11 million and $(37) million for the six-month periods, 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 the three and six-month periods ended June 30, 2025 exclude $(1) million and $1 million, respectively, which amounts are already included within “Certain Items.” See table included in “—Overview—Non-GAAP Financial Measures—Certain Items,” above.

(f)Includes amortization of basis differences related to our joint ventures.

(g)Includes the tax provision on Certain Items recognized by the investees that are taxable entities associated with our Citrus, NGPL Holdings LLC, 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:

Adjusted Net Income Attributable to Kinder Morgan, Inc. increased $202 million and $499 million for the three and six months ended June 30, 2026, respectively, as compared to the respective prior year periods. The increases resulted primarily from favorable earnings across all of our business segments, which were also the primary drivers of the increase in Adjusted EBITDA of $227 million and $609 million, respectively.

General and Administrative and Corporate Charges

General and administrative expenses increased $4 million and $1 million, and corporate charges decreased $4 million and $16 million for the three and six months ended June 30, 2026, respectively, when compared with the respective prior year periods. The combined change for the three-month period was flat and the decrease for the six-month period primarily includes lower pension, legal, and corporate facility costs partially offset by higher benefit-related and labor costs.

Segment Earnings Results

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

(a)Other operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending June 30, 2026 and 2025, Certain Items of (i) $(57) million and $(87) million for the three-month periods, respectively, and $22 million and $(9) million for the six-month periods, respectively, are associated with our Midstream business and (ii) $(2) million for each of the three-month periods and $5 million and none for the six-month periods, respectively, are associated with our East 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)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:

The changes in Natural Gas Pipelines Segment EBDA in the comparable three and six-month periods ended June 30, 2026 and 2025 are explained by the following discussion:

• The $54 million (10%) and $256 million (26%) increases, respectively, in Midstream were primarily driven by (i) increased sales margin resulting from higher volumes and increased demand for our services on our Texas intrastate systems; (ii) higher volumes on KinderHawk Field Services LLC; and (iii) higher performance from acquired assets on our Hiland Midstream assets. The increase in the six-month period was further impacted by increased sales margin primarily due to higher commodity prices due to colder winter weather on our Texas intrastate systems. Overall, Midstream’s revenue changes are partially offset by corresponding changes in costs of sales.

In addition, Midstream includes increased costs of sales associated with risk management activities related to non-cash changes in fair value of unsettled derivative contracts and realized gains and losses on settled natural gas inventory hedge contracts, which we treated as a Certain Item.

• The $16 million (2%) and $51 million (4%) increases, respectively, in East were primarily driven by (i) completed expansion projects; (ii) lower pipeline maintenance costs; and (iii) increased demand for our services primarily due to weather partially offset by lower pricing on short-term firm service contracts driven by a decrease in market volatility.
• The $14 million (6%) and $35 million (7%) increases, respectively, in West resulted primarily from higher park and loan activity due to favorable pricing driven by market volatility, and higher capacity sales partially offset by higher pipeline maintenance costs.

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

(a)Other operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. For the periods ending June 30, 2026 and 2025, Certain Items of (i) $(3) million and none for the three-month periods, respectively, and $1 million for each of the six-month periods are associated with our Southeast Refined Products business and (ii) $(1) million and none for the three-month periods, respectively, are associated with our Crude and Condensate 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)Joint venture throughput is reported at our ownership share.

(d)Volumes include ethanol pipeline volumes.

Below are the changes in Products Pipelines Segment EBDA:

The changes in Products Pipelines Segment EBDA in the comparable three and six-month periods ended June 30, 2026 and 2025 are explained by the following discussion:

• The $40 million (53%) and $54 million (36%) increases, respectively, in Southeast Refined Products were primarily the result of higher butane blending spreads on our Southeast Terminals and favorable commodity prices at our Transmix processing operations.
• The $32 million (29%) six-month increase in Crude and Condensate was driven by (i) higher margin from our Crude and Condensate business resulting primarily from increased spreads; (ii) a turnaround in the first quarter of 2025 at our KM Condensate Processing facility; and (iii) on our Bakken Crude assets, higher gathering rates and retroactive rate increases partially offset by lower gathering volumes.
• The $15 million (5%) six-month increase in West Coast Refined Products was primarily due to lower pipeline maintenance costs and increased butane blending activity on our Pacific Operations.

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

(a)Other operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2026 Certain Items are associated with our Liquids 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 for facilities divested, idled and/or held for sale are excluded for all periods presented.

(d)The ratio of our tankage capacity in service to liquids leasable capacity.

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

Below are the changes in Terminals Segment EBDA:

The changes in Terminals Segment EBDA in the comparable three and six-month periods ended June 30, 2026 and 2025 are explained by the following discussion:

• The $12 million (7%) and $55 million (17%) increases, respectively, in Liquids were driven by contributions from (i) at our Houston Ship Channel facilities, higher rates and ancillaries partially offset by the effects of a customer’s closure of its refinery in 2025; (ii) favorable commodity pricing; and (iii) expansion projects. The increase in the six-month period was also driven by the recognition of payments to be received in connection with the early termination of certain storage agreements in 2026 related to the refinery closure partially offset by higher maintenance costs.
• The $5 million (8%) and $9 million (8%) increases, respectively, in Jones Act tankers were primarily due to higher average charter rates.

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

(a)Other operating expenses include operations and maintenance expenses and taxes, other than income taxes.

(b)See table included in “—Overview—Non-GAAP Financial Measures—Certain Items” above. The 2026 and 2025 Certain Items are associated with our Oil and Gas Producing activities. 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)Net of royalties and outside working interests.

Below are the changes in CO2 Segment EBDA:

The changes in CO2 Segment EBDA in the comparable three and six-month periods ended June 30, 2026 and 2025 are explained by the following discussion:

• The $42 million (40%) and $18 million (8%) increases, respectively, in Oil and Gas Producing activities were driven by higher realized crude oil prices and volumes. The increase in the six-month period was also due to lower power costs primarily resulting from lower prices.

In addition, Oil and Gas Producing activities includes increased revenues for the three-month period and decreased revenues for the six-month period associated with non-cash mark-to-market sales derivative hedge contracts, which we treated as a Certain Item.

• The $16 million (42%) and $19 million (22%) increases, respectively, in Source and Transportation activities were primarily due to higher realized CO2 sales prices.
• The $18 million (257%) and $26 million (108%) increases, respectively, in Energy Transition Ventures includes greater RNG production and RIN sales.

We believe that our existing hedge contracts in place within our CO2 business segment substantially mitigate commodity price exposure in the near-term and to a lesser extent over the following few years. Below is a summary of our CO2 business segment hedges outstanding as of June 30, 2026:

(a)Includes WTI hedges.

Liquidity and Capital Resources

General

As of June 30, 2026, we had $89 million of “Cash and cash equivalents,” an increase of $26 million from December 31, 2025. Additionally, as of June 30, 2026, we had borrowing capacity of approximately $3.2 billion 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 flows from operations, providing a source of funds of $3,451 million and $2,811 million in the first six months of 2026 and 2025, respectively. The period-to-period 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, 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.

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, as detailed below:

(a)Reflects outstanding commercial paper notes.

In March 2026, Moody’s Investor Services upgraded our long-term debt rating from Baa2 with a positive outlook to Baa1 with a stable outlook.

Short-term Liquidity

As of June 30, 2026, 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 $3.2 billion, 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 June 30, 2026, our $2,443 million of short-term debt consisted primarily of commercial paper borrowings and senior notes that mature in the next twelve months. 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 as of December 31, 2025 was $1,226 million.

We had working capital (defined as current assets less current liabilities) deficits of $3,059 million and $1,568 million as of June 30, 2026 and December 31, 2025, respectively. The overall $1,491 million unfavorable change from year-end 2025 was primarily due to (i) an $878 million increase in senior notes that mature in the next twelve months; (ii) a $325 million increase in commercial paper borrowings partly used to fund our Monument Pipeline acquisition; and (iii) a $310 million net unfavorable change in our accounts receivables and payables. Generally, our working capital varies due to factors such as the timing of scheduled debt payments, timing 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 equivalents as a result of excess cash from operations after payments for investing and financing activities.

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 initially and 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 six months ended June 30, 2026, and the amount we expect to spend for the remainder of 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.

(b)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:

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

(b)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.

Off Balance Sheet Arrangements

There have been no material changes in our obligations with respect to other entities that are not consolidated in our financial statements that would affect the disclosures presented as of December 31, 2025 in our 2025 Form 10-K.

Commitments for the purchase of property, plant, and equipment as of June 30, 2026 and December 31, 2025 were $1,499 million and $2,020 million, respectively, decreasing $521 million primarily related to projects advancing in our Natural Gas Pipelines business segment.

Cash Flows

The following table summarizes our net cash flows provided by (used in) operating, investing, and financing activities between 2026 and 2025:

Operating Activities

Net cash provided by operating activities was higher for the comparable six-month periods ended June 30, 2026 and 2025 driven by greater contributions across all of our business segments.

Investing Activities

$316 million more cash used in investing activities in the comparable six-month periods ended June 30, 2026 and 2025 is explained by the following discussion.

• a $373 million increase in capital expenditures primarily driven by expansion projects in our Natural Gas Pipelines business segment, partially offset by decreases in our Products Pipelines and CO2 business segments; and
• a $73 million increase in cash used for contributions to equity investees driven primarily by higher contributions to Southern Natural Gas Company, L.L.C. and Gulf Coast Express Pipeline LLC; partially offset by
• a $145 million reduction in cash used for acquisitions of assets, net of cash acquired, driven by $503 million of net cash used for the acquisition of Monument Pipeline system in the 2026 period, compared with $648 million of net cash used for the Outrigger Energy acquisition in the 2025 period; See Note 2 “Acquisitions” to our consolidated financial statements for further information regarding these two acquisitions.

Financing Activities

$297 million more cash used in financing activities in the comparable six-month periods ended June 30, 2026 and 2025 primarily driven by a reduction in debt raised for acquisitions.

Dividends

We expect to declare dividends of $1.19 per share on our stock for 2026. The table below reflects our 2026 dividends declared:

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.” of our 2025 Form 10-K. All of these matters will be taken into consideration by our board of directors 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.

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, holders of any of the Guaranteed Notes issued by KMI or a Subsidiary Issuer are in the same position with respect to the net assets and income of KMI and the Subsidiary Issuers and 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 10.1 to this report “Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of June 30, 2026.”

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 June 30, 2026 and December 31, 2025, the Obligated Group had $31,462 million and $31,153 million, respectively, of Guaranteed Notes outstanding.

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk.

There have been no material changes in market risk exposures that would affect the quantitative and qualitative disclosures presented as of December 31, 2025, in Part II, Item 7A in our 2025 Form 10-K. For more information on our risk management activities, refer to Item 1, Note 5 “Risk Management” to our consolidated financial statements.

Item 4. Controls and Procedures.

As of June 30, 2026, our management, including our Chief Executive Officer and Chief Financial Officer, has evaluated the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rule 13a-15(b) under the Securities Exchange Act of 1934. There are inherent limitations to the effectiveness of any system of disclosure controls and procedures, including the possibility of human error and the circumvention or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. Based upon and as of the date of the evaluation, our Chief Executive Officer and our Chief Financial Officer concluded that the design and operation of our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed in the reports we file and submit under the Securities Exchange Act of 1934 is recorded, processed, summarized, and reported as and when required, and is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. There has been no change in our internal control over financial reporting during the quarter ended June 30, 2026 that materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Litigation and Environmental” which is incorporated in this item by reference.

Item 1A. Risk Factors.

There have been no material changes in the risk factors disclosed in Part I, Item 1A in our 2025 Form 10-K.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

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 Dodd-Frank Act for the quarter ended June 30, 2026.

Item 5. Other Information.

During the quarter ending June 30, 2026, none of our directors or officers (as defined in Rule 16a-1(f) of the Securities Exchange Act of 1934) adopted, terminated or modified a Rule 10b5-1 trading arrangement or non-Rule 10b5-1 trading arrangement (as such terms are defined in Item 408 of Regulation S-K).

Appointment of Officers

In connection with Kenneth W. Grubb’s previously announced appointment as our Vice President and Chief Operating officer to be effective September 4, 2026, the Compensation Committee of our Board of Directors on July 21, 2026 approved a grant to Mr. Grubb of 61,767 restricted stock units issued pursuant to our 2021 Amended and Restated Stock Incentive Plan.

The restricted stock units will vest in full on July 31, 2029, provided Mr. Grubb is employed by us through such date and applicable performance goals have been met.

Item 6. Exhibits.

Exhibit Number Description

10.1 Cross Guarantee Agreement, dated as of November 26, 2014, among KMI and certain of its subsidiaries, with schedules updated as of June 30, 2026. 10.2 Amended and Restated Revolving Credit Agreement, dated as of May 21, 2026, among Kinder Morgan, Inc., as borrower, Barclays Bank PLC, as administrative agent, and the lenders and issuing banks party thereto. 22.1 Subsidiary guarantors and issuers of guaranteed securities. 31.1 Certification of Chief Executive Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 31.2 Certification of Chief Financial Officer pursuant to Rule 13a-14(a) or 15d-14(a) of the Securities Exchange Act of 1934, as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002. 32.1 Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. 32.2 Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002. (101) Interactive data files (formatted as Inline XBRL). (104) Cover page interactive data file (formatted as Inline XBRL and contained in Exhibit 101).