CHESAPEAKE UTILITIES CORP

To the Stockholders and the Board of Directors of

Chesapeake Utilities Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation and Subsidiaries (the "Company") as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows for each of the three years in the period ended December 31, 2025, and the related notes and financial statement schedules listed in Item 15(a)2 (collectively referred to as the "consolidated financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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

Basis for Opinions

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the

Chesapeake Utilities Corporation 2025 Form 10-K Page 56 company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

Critical Audit Matters

Critical audit matters are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.

/s/Baker Tilly US, LLP

We have served as the Company's auditor since 2007.

Philadelphia, Pennsylvania

February 25, 2026

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See Note 7 for Supplemental Cash Flow Disclosures.

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Consolidated Statements of Stockholders' Equity

(1)2.0 million shares of preferred stock at $0.01 par value per share have been authorized. No preferred shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity.

(2) Includes 129 thousand,114 thousand and 108 thousand shares at December 31, 2025, 2024 and 2023, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

(3)Includes amounts for shares issued for directors’ compensation.

(4)The shares issued under the SICP are net of shares withheld for employee taxes. For 2025, 2024 and 2023, we withheld 8 thousand,14 thousand and 20 thousand shares, respectively, for taxes.

(5)Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM, as applicable.

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1. ORGANIZATION AND BASIS OF PRESENTATION

Chesapeake Utilities, incorporated in 1947 in Delaware, is a diversified energy company engaged in regulated and unregulated energy businesses.

Our regulated energy businesses consist of: (a) regulated natural gas distribution operations in central and southern Delaware, Maryland’s eastern shore and Florida; (b) regulated natural gas transmission operations on the Delmarva Peninsula, in Pennsylvania, Florida and in Ohio; and (c) regulated electric distribution operations serving customers in northeast and northwest Florida.

Our unregulated energy businesses primarily include: (a) propane operations in the Mid-Atlantic region, Virginia, North Carolina, South Carolina and Florida; (b) our unregulated natural gas transmission/supply operation in central and eastern Ohio; (c) our CHP plant in Florida that generates electricity and steam; (d) our subsidiary, based in Florida, that provides CNG, LNG and RNG transportation and pipeline solutions, primarily to utilities and pipelines throughout the United States; and (e) sustainable energy investments including renewable natural gas related investments.

Our consolidated financial statements include the accounts of Chesapeake Utilities and its wholly-owned subsidiaries. We do not have any ownership interest in investments accounted for using the equity method or any interest in a variable interest entity. All intercompany accounts and transactions have been eliminated in consolidation. We have assessed and, if applicable, reported on subsequent events through the date of issuance of these consolidated financial statements. Where necessary to improve comparability, prior period amounts have been reclassified to conform to current period presentation.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

Preparing the consolidated financial statements to conform with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments about various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates. As additional information becomes available, or actual amounts are determined, recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property within the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2025 and 2024 is provided in the following table:

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Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2025 and 2024, the non-refundable contributions totaled $7.8 million and $5.9 million, respectively.

AFUDC

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. For the years ended December 31, 2025, 2024 and 2023, AFUDC was not material.

Leases

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets. At December 31, 2025 and 2024, the asset balances related to our leases amounted to approximately $10 million. The liability balances related to our leases amounted to approximately $10 million and $11 million, respectively, at December 31, 2025 and 2024. Total operating lease expenses and total cash paid in connection with our leases were not material for the years ended December 31, 2025 and 2024.

Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

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We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related.

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, 2025, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $3.5 million and $2.8 million at December 31, 2025 and 2024, respectively.

Impairment of Long-lived Assets

We periodically evaluate whether events or circumstances have occurred, which indicate that long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2025, 2024 and 2023, we reported $15.9 million, $15.8 million and $11.9 million, respectively, of depreciation and accretion in operations expenses.

The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2025, 2024 and 2023:

(1) Average beginning in 2024 includes the impact of the depreciation study that was approved by the Maryland PSC.

(2) Includes the impact of FCG beginning in 2024.

(3)Average beginning in 2023 includes the impact of the depreciation study that was approved by the Florida PSC in connection with the natural gas base rate proceeding.

(4)2024 rate excludes the impact of cumulative adjustments related to a change in useful lives of certain assets. Such adjustments were not material to the Company's results of operations for the year ended December 31, 2024.

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For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:

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Regulated Operations

We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in our consolidated statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.

We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980 continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.

Revenue Recognition

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates.

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class.

All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms. These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded withinone year.

We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis.

Our unregulated propane distribution businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses.

Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly.

Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers.

Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.

For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.

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Natural Gas, Electric and Propane Costs

Natural gas, electric and propane costs include the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable commodity cost of natural gas, electricity and propane, costs of pipeline capacity needed to transport and store natural gas, transmission costs for electricity, costs to gather and process natural gas, costs to transport propane to/from our storage facilities or our mobile CNG equipment to customer locations, and steam and electricity generation costs. Depreciation expense is not included in natural gas, electric and propane costs.

Operations and Maintenance Expenses

Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses.

Cash and Cash Equivalents

Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity ofthree months or less when purchased are considered cash equivalents.

Accounts Receivable and Allowance for Credit Losses

Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and impacts from general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.

Our estimate for expected credit losses has been developed by analyzing our portfolio of financial assets that present potential credit exposure risk. These assets consist solely of our trade receivables from customers and contract assets. The estimate is based on five years of historical collections experience, a review of current economic and operating conditions in our service territories, and an examination of economic indicators which provide a reasonable and supportable basis of potential future activity. Those indicators include metrics which we believe provide insight into the future collectability of our trade receivables such as unemployment rates and economic growth statistics in our service territories.

When determining estimated credit losses, we analyze the balance of our trade receivables based on the underlying line of business. This includes an examination of trade receivables from our energy distribution, energy transmission, energy delivery services and propane operations businesses. Our energy distribution business consists of all our regulated distribution utility (natural gas and electric) operations on the Delmarva Peninsula and in Florida. These business units have the ability to recover their costs through the rate-making process, which can include consideration for amounts historically written off to be included in rate base. Therefore, they possess a mechanism to recover credit losses which we believe reduces their exposure to credit risk. Our energy transmission and energy delivery services business units consist of our natural gas pipelines and our mobile CNG delivery operations. The majority of customers served by these business units are regulated distribution utilities who also have the ability to recover their costs. We believe this cost recovery mechanism significantly reduces the amount of credit risk associated with these customers. Our propane operations are unregulated and do not have the same ability to recover their costs as our regulated operations. However, historically our propane operations have not had material write offs relative to the amount of revenues generated.

Our estimate of expected credit losses reflects our anticipated losses associated with our trade receivables as a result of non-payment from our customers beginning the day the trade receivable is established. We believe the risk of loss associated with trade receivables classified as current presents the least amount of credit exposure risk and therefore, we assign a lower estimate to our current trade receivables. As our trade receivables age outside of their expected due date, our estimate increases. Our allowance for credit losses relative to the balance of our trade receivables has historically been immaterial as a result of on time payment activity from our customers.

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The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2025:

Inventories

We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2025, 2024 or 2023.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. There were no goodwill impairments recognized during the years ended December 31, 2025, 2024 and 2023. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

Other deferred charges include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings.

Asset Removal Cost

As authorized by the appropriate regulatory body (state PSC or FERC), we accrue future asset removal costs associated with utility property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When we retire depreciable utility plant and equipment, we charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with our asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.

See Note 17, Rates and Other Regulatory Activities, for information related to FCG's RSAM that was approved as part of its rate case effective as of May 1, 2023.

Pension and Other Postretirement Plans

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.

The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high-quality corporate

Chesapeake Utilities Corporation 2025 Form 10-K Page 70 bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.

The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on plan assets.

We estimate the health care cost trend rates used in determining our postretirement expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.

The mortality assumption used for our pension and postretirement plans is reviewed periodically and is based on the actuarial table that best reflects the expected mortality of the plan participants.

Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency

Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded when it is more likely than not that such income tax benefits will be realized. Valuation allowances may be recorded if it is determined that some deferred tax assets will not be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.

We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities.

Financial Instruments

We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being initially recorded in accumulated other comprehensive income (loss) and reclassified to earnings when the associated hedged transaction settles. The ineffective portion of the gain or loss of a hedge is immediately recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging, it is recorded at fair value with all gains or losses being recorded directly in earnings.

Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and normal sales” treatment under ASC Topic 815 and are accounted for on an accrual basis.

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. We designate and account for the interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges.

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Recently Adopted Accounting Standards

FASB

Segment Reporting (ASC 280) - In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures, which modifies required disclosures about a public entity’s reportable segments and addresses requests from investors for more detailed information about a reportable segment’s expenses and a more comprehensive reconciliation of each segment's reported profit or loss. We adopted ASU 2023-07 for our annual financial statements beginning January 1, 2024 and our interim financial statements beginning January 1, 2025. ASU 2023-07 only impacts disclosures, and as a result, did not have an impact on our financial position or results of operations.

Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 became effective for our annual financial statements beginning January 1, 2025. ASU 2023-09 only impacts disclosures, and as a result, did not have an impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

FASB

Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-03 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

Internal-Use Software (ASC 350) - In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software. This update, among other changes, eliminates the project stages used in the historical guidance and instead, focuses on a principles-based approach that utilizes management's commitment to the project and the probability of project completion. ASU 2025-06 will be effective for our interim and annual financial statements beginning January 1, 2028. We do not expect ASU 2025-06 to have a material impact on our financial position or results of operation.

Derivatives and Hedging (ASC 815) - In November 2025, the FASB issued ASU 2025-09, Hedge Accounting Improvements. This update aims to align hedge accounting more closely with an entity's risk management activities. The update focuses on reducing complexity and expands the eligibility of highly effective economic hedges. ASU 2025-09 will be effective for our interim and annual financial statements beginning January 1, 2027. We do not expect this ASU to have a material impact on our financial position or results of operation.

Interim Reporting (ASC 270) - In December 2025, the FASB issued ASU 2025-11, Narrow-Scope Improvements. The update clarifies the scope and content requirements for interim financial reporting. It will not fundamentally change existing interim disclosure requirements but improves the navigability of the guidance. ASU 2025-11 will be effective for our interim and annual financial statements beginning January 1, 2028. ASU 2025-11 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

SEC

Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks, and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed that sought review of the final ruling in multiple courts of appeals. In March 2025, the SEC withdrew its defense of the final rule. We will continue to monitor any further developments related to the stay and review process.

Federal Statute Updates

In July 2025, H.R. 1 (referred to as the "One Big Beautiful Bill Act") was signed into law. The comprehensive legislative package contains, among other topics, significant tax law changes and regulatory compliance updates, with various effective dates, including provisions related to limitations of interest expense deductions and the reinstatement of bonus depreciation for non-regulated qualified property. These provisions of the One Big Beautiful Bill Act had a positive impact on our income tax provision beginning in the third quarter of 2025, and we continue to evaluate the anticipated impacts to our financial position, results of operations, and/or cash flows on a go-forward basis.

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3. EARNINGS PER SHARE

The following table presents the calculation of our basic and diluted earnings per share:

(1) Weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 14 for additional details on the acquisition and related equity offering.

4. ACQUISITIONS

Acquisition of Florida City Gas

On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement that were settled during the first quarter of 2024, pursuant to the stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment.

The purchase price of the acquisition was funded with $366.4 million of net proceeds from the issuance of 4.4 million shares of our common stock, the issuance of approximately $550.0 million principal amount of uncollateralized senior notes, and borrowings under the Company's Revolver. See Note 12, Long-Term Debt, and Note 14, Stockholders' Equity, for additional details on these financing activities.

The excess of the purchase price for FCG over the fair value of the assets acquired and liabilities assumed was reflected as goodwill within the Regulated Energy segment. Goodwill resulting from the acquisition was largely attributable to expansion opportunities provided within our existing regulated operations in Florida, including planned customer growth and growth in rate base through continued investment in our utility infrastructure, as well as natural gas transmission infrastructure supporting the distribution operations. The goodwill recognized in connection with the acquisition of FCG is deductible for income tax purposes.

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The components of the purchase price allocation are as follows:

Direct transaction and transition-related costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction and transition-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges included $4.1 million related to fees and expenses associated with the Bridge Facility, which was terminated without any funds drawn, for the year ended December 31, 2023. Other transaction costs of $15.9 million related primarily to the debt and equity financings executed in connection with the acquisition, were deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate, as of December 31, 2023.

For the year ended December 31, 2025, the Company’s consolidated results include $170.4 million of operating revenue and net income of $5.2 million attributable to FCG which includes $1.2 million of transaction and transition-related expenses. For the year ended December 31, 2024, the Company’s consolidated results include $140.3 million of operating revenue and net income of $13.5 million attributable to FCG which includes $4.0 million of the transaction and transition-related expenses described above. In 2025, the Company filed a traditional depreciation filing with the FPSC related to the remaining excess depreciation reserve. See Note 17, Rates and Other Regulatory Activities, for additional information.

5. REVENUER ECOGNITION

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following tables display revenue by major source based on product and service typefor the years ended December 31, 2025, 2024 and 2023:

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(1)In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for rate-making and other purposes and are reflected on a consolidated basis for all periods presented consistent with the final rate order. See Note 17, Rates and Other Regulatory Activities, for additional information.

(2) Total operating revenues for the year ended December 31, 2025, include other revenue (revenues from sources other than contracts with customers) of $0.8 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization and late fees for the Maryland natural gas distribution businesses.

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(1)In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for rate-making and other purposes and are reflected on a consolidated basis for all periods presented consistent with the final rate order. See Note 17, Rates and Other Regulatory Activities, for additional information.

(2)Total operating revenues for the year ended December 31, 2024, include other revenue (revenues from sources other than contracts with customers) of $1.6 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization and late fees for the Maryland natural gas distribution businesses.

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(1) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions, and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

(2)In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for rate-making and other purposes and are reflected on a consolidated basis for all periods presented consistent with the final rate order. See Note 17, Rates and Other Regulatory Activities, for additional information.

(3)Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide.

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Revenues for Eastern Shore are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to the FERC-approved maximum rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers receive service only when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Aspire Energy Express is engaged in natural gas intrastate transmission in the State of Ohio. We currently serve the Guernsey Power Station and our performance obligation is satisfied over time as the natural gas is transported to the plant. We recognize revenue based on rates approved by the Ohio PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Eight Flags' CHP plant, which is located on land leased from a customer, produces three sources of energy: electricity, steam and heated water. This customer purchases the steam (unfired and fired) and heated water, which are used in the customer’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.

For our propane distribution operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane distribution customers with meters, we satisfy our performance obligation over time. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane distribution metered customers, we accrue unbilled revenues for propane that is estimated to have been consumed, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Marlin Gas Services provides mobile CNG and pipeline solutions primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. Marlin Gas Services continues to actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to also serve LNG and RNG market needs. Marlin Gas Services' performance obligations are comprised of the compression of natural gas, mobilization of CNG equipment, utilization of equipment and on-site CNG support. Our performance obligations for the compression of natural gas, utilization of mobile CNG equipment and for the on-site CNG staff support are satisfied over time when the natural gas is compressed, equipment is utilized or as our staff provide support services to our customers. Our performance obligation for the mobilization of CNG equipment is satisfied at a point-in-time when the equipment is delivered to the customer project location. We recognize revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

Chesapeake Utilities Corporation 2025 Form 10-K Page 78

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2025 and 2024 were as follows:

Our trade receivables are included in trade and other receivables in the consolidated balance sheets. Our non-current contract assets are included in receivables and other deferred charges in the consolidated balance sheets and relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2025 and 2024, the amount of contract liabilities recognized in revenue were not material.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2025 are expected to be recognized as follows:

6. SEGMENT INFORMATION

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker, our President and Chief Executive Officer, in order to make decisions about resources and to assess performance.

Our operations are entirely domestic and are comprised of two reportable segments:

•Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas related investments. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services.

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The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to the Company, as well as certain corporate costs not allocated to other operations.

The following tables present information about our reportable segments:

(1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.

(2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

(3) Other segment items for each reportable segment include: Regulated Energy- Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated Energy - Other taxes.

(1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.

(2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

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(3)Other segment items for each reportable segment include: Regulated Energy - Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated Energy - Other taxes.

(4)Regulated capital expenditures in 2023 include our acquisition of FCG for $922.8 million. See Note 4 for additional details.

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2025, 2024, and 2023 were as follows:

Non-cash investing and financing activities during the years ended December 31, 2025, 2024, and 2023 were as follows:

8. DERIVATIVE INSTRUMENTS

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. Occasionally, we may enter into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of December 31, 2025 and 2024, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of December 31, 2025, the volume of our open commodity derivative contracts were as follows:

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2025 through September 2028) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the

Chesapeake Utilities Corporation 2025 Form 10-K Page 81 contracted prices. We designated and accounted for the propane swaps as cash flow hedges. The change in the fair value of the swap agreements is initially recorded as a component of accumulated other comprehensive income (loss) and later recognized in our consolidated statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.6 million of unrealized loss related to our propane derivatives from accumulated other comprehensive income (loss) to earnings during the next 12-month period.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In September 2022, we entered into an interest rate swap with a notional amount of $50.0 million with pricing of 3.98 percent. This swap expired in September 2025. In August 2024, we entered into an additional interest rate swap through August 2029, at a notional amount of $50.0 million and pricing of 3.97 percent. Our interest rate swaps are cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate.

We designate and account for interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are initially recorded as a component of accumulated other comprehensive income (loss). As the interest rate swap settles, the realized gain or loss is recorded in the income statement and is recognized as a component of interest charges.

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp included within other current assets on the consolidated balance sheets which had a balance of $2.4 million and $1.9 million as of December 31, 2025 and December 31, 2024, respectively.

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2025 and 2024 are as follows:

(1)There were no current derivative assets at December 31, 2025. Derivative assets, at fair value included $0.6 million in current assets in the consolidated balance sheets at December 31, 2024, with the remainder of the balance classified as long-term.

(1)Derivative liabilities, at fair value included $0.8 million in current liabilities in the consolidated balance sheet at December 31, 2025, with the remaining balance classified as long-term. There were no current derivative liabilities at December 31, 2024.

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The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows:

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are as follows:

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Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2025 and 2024, respectively:

The changes in the fair value of our Level 3 investments for the years ended December 31, 2025 and 2024 were not material. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

At December 31, 2025 and 2024, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable, other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its near-term maturities and because interest rates approximate current market rates (Level 2 measurement).

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At December 31, 2025, long-term debt, which includes the current maturities but excludes debt issuance cost, had both a carrying value and fair value of $1.5 billion. At December 31, 2024, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.3 billion, compared to the estimated fair value of $1.2 billion. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 2 measurement.

See Note 15, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

10. GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2025 and 2024 was as follows:

(1)Adjustments in the Unregulated Energy segment relate to the sale of certain assets in our propane distribution business during 2025.

There were no goodwill impairments recognized during the three-year period ended December 31, 2025.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2025 and 2024 were as follows:

(1)Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found.

The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted averageof 15 years. Amortization expense of intangible assets for the years ended December 31, 2025, 2024 and 2023 was $1.8 million, $1.9 million and $1.8 million, respectively. Amortization expense of intangible assets is expected to be $1.6 million for 2026, $1.5 million for 2027, $1.3 million for 2028 through 2030.

11. INCOME TAXES

We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our federal and state corporate income tax returns for tax years after 2022 are subject to examination.

For federal income tax purposes, we have investment tax credits of $9.0 million, which begin to expire in 2044. For state income tax purposes, we have NOL carryforwards in various states of $192.1 million and $99.3 million as of December 31, 2025 and 2024, respectively, almost all of which will expire in 2040. We have not recorded a valuation allowance to reduce the future benefit of the investment tax credits or NOL carryforwards because we believe they will be fully utilized prior to expiration.

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Tax Law Changes

On December 22, 2017, the TCJA was signed into law. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 17, Rates and Other Regulatory Activities, for further discussion of TCJA’s impact on our regulated businesses.

See Note 2, Summary of Significant Accounting Policies, for more information on tax law updates.

The following tables provide: (a) the components of income tax expense in 2025, 2024, and 2023; (b) the reconciliation between the statutory federal income tax rate and the Company's effective income tax rate for 2025, 2024, and 2023; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2025 and 2024.

.

The Company has elected to retrospectively adopt the guidance in ASU No. 2023-09, Income Taxes (Topic 740): Improvements to Income Taxes Disclosures, or ASU 2023-09. The following table is a reconciliation of the U.S. federal statutory rate of 21.0 percent to the Company's effective rate for the year ended December 31, 2025, and as previously disclosed for the years ended December 31,2024 and 2023 in accordance with the guidance in ASU No. 2023-09:

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Cash payments of U.S. federal and state income taxes, net of refunds, were as follows:

12. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

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Terms of the Senior Notes

All of our outstanding Senior Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

Senior Notes

In August 2025, we entered into a Note Purchase Agreement for the issuance of Senior Notes in the aggregate principal amount of $200.0 million with an initial funding of $150.0 million in August 2025 and an additional $50.0 million in September 2025. These Senior Notes have an average interest rate of 5.04 percent consisting of $60.0 million of 4.88 percent notes due in August 2028, $50.0 million of 5.02 percent notes due in September 2030, and $90.0 million of 5.16 percent notes due in August 2031. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. The outstanding principal balance of the Senior Notes will be due on their respective maturity dates with interest payments payable semiannually beginning in 2026 until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes.

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On November 1, 2024, we issued 5.20 percent Senior Notes due in November 2029 in the aggregate principal amount of $100.0 million. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have semi-annual interest payments due on May 1 and November 1 of each year beginning in 2025.

On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes (net of annual payments on the 6.73 percent notes which begin in 2029) will be due on their respective maturity dates with interest payments payable semiannually until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes.

Annual maturities and principal repayments of long-term debt are as follows:

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, however neither of such lenders have any obligation to purchase debt thereunder. We amended these agreements with Prudential and MetLife in February 2026 and June 2025, respectively, to expand the total borrowing capacity and extend the term of the agreements. As of the February 2026 amendment, a total of $343.3 million of borrowing capacity was available under these agreements with terms that extend through February 2029 and June 2030, respectively.

13. SHORT-TERM BORROWINGS

As of December 31, 2025, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At December 31, 2025 and 2024, we had $158.0 million and $196.5 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.73 percent and 5.06 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2025.

In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche and $200.0 million available under the five-year tranche which expires in August 2029. In August 2025, we exercised an option under the Revolver to extend the 364-day tranche through August 2026. All other terms and conditions of the agreement remain unchanged. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be subject to a pricing grid, including the commitment fee and the interest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. The 364-day tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion.

We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 8, Derivative Instruments.

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2025, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, 2025 was $287.2 million. As of December 31, 2025, we had issued $4.8 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

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14. STOCKHOLDERS'EQUITY

Common Stock Issuances

In November 2023, in connection with our acquisition of FCG, we completed an overnight offering resulting in the issuance of 4.4 million shares of our common stock at a price per share of $82.72 (net of underwriter discounts and commissions). We received net proceeds of $366.4 million which were used to partially finance the acquisition.

We maintain effective shelf registration statements with the SEC for the issuance of common stock in various types of equity offerings, including pursuant to our DRIP and ATM program. Depending on our capital needs and subject to market conditions, we may issue additional shares under the direct stock purchase component of the DRIP in addition to other possible debt and equity offerings. In November 2024, we established a new ATM program under which we may sell shares of our common stock up to an aggregate offering price of $100.0 million. This current ATM program is active through November 2027. For the years ended December 31, 2025 and 2024, we received net proceeds of $123.2 million and $72.5 million, respectively, associated with shares issued under the DRIP and our ATM program.

Accumulated Other Comprehensive Income (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contract cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2025 and 2024. All amounts in the following tables are presented net of tax.

Deferred gains or losses for our commodity contract and interest rate swap cash flow hedges are recognized in earnings upon settlement and are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details. Amortization of the net loss related to the defined benefit pension plan and postretirement plans is included in the computation of net periodic costs (benefits). See Note 15, Employee Benefit Plans, for additional details.

15. EMPLOYEE BENEFIT PLANS

We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year. The changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs are recorded as a component of other comprehensive income (loss) or a regulatory asset.

Chesapeake Utilities Corporation 2025 Form 10-K Page 90

Defined Benefit Pension Plans

At December 31, 2025 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake Supplemental Executive Retirement Plan ("SERP").

The FPU Pension Plan, a qualified plan, covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. The FPU Pension Plan was frozen with respect to additional years of service and compensation, effective December 31, 2009.

The Chesapeake SERP, a nonqualified plan, is comprised oftwo sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. The second sub-plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit.

The funded position for all plans at both December 31, 2025 and 2024, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedules set forth the funded status at December 31, 2025 and 2024 and the net periodic cost (benefit) for the years ended December 31, 2025, 2024 and 2023 for the FPU Pension Plan and the Chesapeake SERP:

Chesapeake Utilities Corporation 2025 Form 10-K Page 91

Our funding policy provides that payments to the trust of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the allocation of assets of the FPU Pension Plan, by investment type, at December 31, 2025, 2024 and 2023:

The investment policy of the FPU Pension Plan was traditionally designed to provide the capital assets necessary to meet the financial obligations of the plan. As of December 31, 2025, the plan was overfunded at approximately 110 percent. As the Company evaluates options for a termination of the FPU Pension Plan and related settlement of the plan's obligations, the investment strategy was adjusted in January 2026 to emphasize capital preservation and liability matching. The portfolio has been transitioned toward a liability-driven approach with increased allocation to long-term, high-quality fixed income securities and cash equivalents, and the elimination of equities (as detailed below). The following target allocation of asset classes, which was approved and implemented in January 2026, is intended to minimize funded status volatility and to align the plan's assets with anticipated annuity purchase requirements and termination related liquidity needs.

Chesapeake Utilities Corporation 2025 Form 10-K Page 92

At December 31, 2025 and 2024, the assets of the FPU Pension Plan (prior to the previously mentioned change in asset allocation strategy) were comprised of the following investments:

(1)Includes funds that invest primarily in United States common stocks.

(2) Includes funds that invest primarily in foreign equities and emerging markets equities.

(3) Includes funds that invest in fixed income securities.

(4) Includes investment in a group annuity product issued by an insurance company.

(5)All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

At December 31, 2025 and 2024, our pension plan investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees. Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy and are presented in the table above to reconcile to total pension plan assets.

The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2025 and 2024 were not material.

Other Postretirement Benefits Plans

We sponsortwo unfunded defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. The total obligations of these plans, as well as the net periodic benefit costs, were not material as of and for the years ended December 31, 2025 and 2024, respectively.

Amounts Not Yet Reflected in Periodic Benefit Cost

As of December 31, 2025, there was $7.6 million not yet reflected in net periodic postretirement benefit costs and included in the Company's consolidated balance sheets as accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $5.8 million and $1.1 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $2.2 million recorded in accumulated other comprehensive income (loss) and $4.7 million recorded as a regulatory asset at December 31, 2025.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset the portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations.

Chesapeake Utilities Corporation 2025 Form 10-K Page 93

Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2025, considering the expected lives of each of the plans. In determining the average expected return on plan assets for the FPU Pension Plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the FPU Pension Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable.

The health care inflation rate for 2025 used to calculate the benefit obligation is 5 percent for medical and 6 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5 percent for both medical and prescription drugs for the FPU Medical Plan.

Estimated Future Benefit Payments

In 2026, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.2 million are expected for the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan combined.

The schedule below shows the estimated future benefit payments for the FPU Pension Plan (estimated payments related to the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan are not material) assuming continuation of the plan. A termination of the plan and related settlement of its obligations would accelerate the timing of payments estimated below.

(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

Retirement Savings Plan

We sponsor a 401(k) Retirement Savings Plan which is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum ofsix percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested aftertwo years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate ofthree percent, and the automatic deferral rate will increase byone percent per year up to a maximum often percent. All contributions and matched funds can be invested among the mutual funds available for investment.

Employer contributions to our Retirement Savings Plan totaled $9.1 million, $8.4 million, and $6.6 million for the years ended December 31, 2025, 2024 and 2023, respectively. As of December 31, 2025, there were 788,495 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan.

Non-Qualified Deferred Compensation Plan

Members of our BOD and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up tosix percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of deferred compensation to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier or later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years.

Chesapeake Utilities Corporation 2025 Form 10-K Page 94

All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of cash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. Deferred stock compensation may not be diversified. The participants are credited with dividends on their deferred common stock units in the same amount that is received by all other stockholders. Such dividends are reinvested into additional deferred common stock units. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheets, had a fair value of $17.2 million and $14.4 million at December 31, 2025 and 2024, respectively. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

Deferrals of officer base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares and directors' stock retainers are made in the form of deferred common stock units and are paid out in shares of our common stock, on a one-for-one basis, except that cash is paid in lieu of fractional shares. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheets and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Non-Qualified Deferred Compensation Plan totaled $12.6 million and $9.8 million at December 31, 2025 and 2024, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheets.

16. SHARE-BASED COMPENSATION PLANS

Our key employees and non-employee directors have been granted share-based awards through our SICP, which has awards outstanding under the current 2023 plan and the previous 2013 plan. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted, and the number of shares expected to be issued at the end of the service period. We have 488,457 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2025, 2024 and 2023:

Officers and Key Employees

Our Compensation Committee is authorized to grant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals and subject to SEC transfer restrictions once awarded. Our President and CEO has the right to issue awards of shares of our common stock, to other officers and key employees of the Company, contingent upon various performance goals and subject to SEC transfer restrictions.

We currently have several outstanding multi-year performance awards under various plans, which are based upon the successful achievement of long-term goals, growth and financial results and comprise both market-based and performance-based conditions and targets. The fair value per share, tied to a performance-based condition or target, is equal to the market price per share on the grant date. For the market-based conditions, we used a Monte Carlo valuation to estimate the fair value of each share granted.

Chesapeake Utilities Corporation 2025 Form 10-K Page 95

The table below presents the summary of the stock activity for awards to all officers and key employees:

During the year ended December 31, 2025, we granted awards of 100 thousand shares of common stock to officers and key employees under the SICP, including awards granted in February 2025. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2027.

The aggregate intrinsic value of the SICP awards granted was $36.2 million, $30.8 million, and $22.5 million at December 31, 2025, 2024 and 2023, respectively. At December 31, 2025, there was $7.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2027.

In March 2025, 2024 and 2023, upon the election by certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in March 2025, 2024 and 2023 for the performance periods ended December 31, 2024, 2023, and 2022. We paid the balance of such awarded shares to each such executive officer and remitted the cash equivalent of the withheld shares to the appropriate taxing authorities. The below table presents the number of shares withheld and amounts remitted:

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year or less.

Our directors receive an annual retainer of shares of common stock under the SICP for services rendered through the subsequent Annual Meeting of Stockholders. Accordingly, our directors that served on the Board as of May 2025 and 2024 each received approximately 1 thousand shares of common stock for the two periods, with a weighted average fair value of $134.05 and $110.53 per share, respectively.

At December 31, 2025, there was $0.3 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May 2026.

Chesapeake Utilities Corporation 2025 Form 10-K Page 96

17. RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively.

Delaware

In September 2023, the Delaware Division submitted the Energy Efficiency Rider application for natural gas with the Delaware PSC after obtaining an affirmative recommendation from the Delaware Energy Efficiency Advisory Council (“EEAC”). The application is the first in the state and applies to a portfolio of four programs in which customers can participate (and allow for recovery), including Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and a Standard Offer Program. In April 2024, all programs, with the exception of the Standard Offer Program, were approved by the PSC and rates became effective May 1, 2024.

Delaware Natural Gas Rate Case: In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. In connection with the application, we sought approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective in October 2024. A settlement among the Company, PSC staff and the Delaware Division of the Public Advocate was reached and approved by the Delaware PSC in June 2025 providing an annual revenue increase of $6.1 million, as well as dividing the rate case into two phases. Rates set to recover the approved components of the increase were effective in March 2025. In October 2025, a settlement was reached for Phase II of the rate case addressing tariff-related changes including rate design and approved by the Delaware Public Service Commission with rates effective as of October 15, 2025.

Maryland

Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we sought approval of the following: (i) permanent rate relief of approximately $6.9 million with a ROE of 11.5 percent; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. In August 2024, the Maryland natural gas distribution businesses, the Maryland OPC and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million increase in annual base rates was approved, and the Company filed the Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The hearing was held in March 2025, during which Phase II was approved, including an additional $0.9 million in revenue requirement for a total cumulative increase of $3.5 million. A final order was issued in April 2025 and included approval of the consolidation of the operations and the assets of CUC-Maryland Division, Sandpiper Energy, and Elkton Gas into one entity, which was renamed and operates as Chesapeake Utilities of Maryland, Inc.

Maryland Natural Gas Depreciation Study: In January 2024, our Maryland natural gas distribution businesses filed a joint petition for approval of their proposed unified depreciation rates with the Maryland PSC. A settlement agreement between the Company, PSC staff and the OPC was reached and the final order approving the settlement agreement went into effect in July 2024, with new depreciation rates effective as of January 1, 2023. The approved depreciation resulted in an annual reduction in depreciation expense of approximately $1.2 million.

Florida

Wildlight Expansion: In August 2022, Peninsula Pipeline and FPU filed a joint petition with the Florida PSC for approval of its Transportation Service Agreement associated with the Wildlight planned community located in Nassau County, Florida. The petition was approved by the Florida PSC in November 2022. The project enables us to meet the significant growing demand for service in Yulee, Florida, and to construct the project during the build-out of the community and charge the reservation rate as each phase of the project goes into service. Construction of the pipeline facilities will occur in two separate phases. Phase one consists of three extensions with associated facilities, and a gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. The various phases of the project commenced in the first quarter of 2023, and construction was completed in 2025.

Chesapeake Utilities Corporation 2025 Form 10-K Page 97

FCG Natural Gas Rate Case: In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Florida PSC also approved FCG's proposed RSAM with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. The Florida OPC filed a notice of appeal with the Florida Supreme Court in July 2023, which is pending. The Florida OPC filed their initial brief in January 2024 with answer briefs filed in April 2024. Oral arguments in the case were held in December 2024. The Florida Supreme Court has yet to rule on the case.

The RSAM was recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM was calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve month regulatory base net operating income, which primarily included the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items was adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. For the years ended December 31, 2024 and 2023, the Company recorded decreases to asset removal costs and depreciation expense of $15.5 million and $5.1 million, respectively, as a result of the RSAM adjustment. At December 31, 2024, the RSAM reserve had been completely utilized.

FCG Depreciation Study: In February 2025, FCG filed a depreciation study with the Florida PSC. The application requested approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. The outcome of the application was subject to review and approval by the Florida PSC. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets, with the revised depreciation rates effective as of January 1, 2025.

Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which requires electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operation’s initial SPP plan was filed and approved in 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs of $20.4 million for both capital and operating expenses. Our Florida electric distribution operations filed an updated SPP plan in January 2025 which was approved in June 2025, with modifications by the Florida PSC.

GUARD: In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a ten-year program to enhance the safety, reliability, and accessibility of portions of our natural gas distribution system. We identified various categories of projects to be included in GUARD, which include the relocation of mains and service lines located in rear easements and other difficult to access areas to the front of the street, the replacement of problematic distribution mains, service lines, and maintenance and repair equipment and system reliability projects. In August 2023, the Florida PSC approved the GUARD program, which included $205.0 million of capital expenditures projected to be spent over a 10-year period.

FCG SAFE Program: In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the Florida PSC approved a replacement of 160 miles of pipe that was used in the 1970s and 1980s and shown through industry research to exhibit premature failure in the form of cracking. The program includes projected capital expenditures of $205.0 million over a 10-year period.

In April 2024, FCG filed a petition with the Florida PSC to more closely align the SAFE Program with FPU's GUARD program. Specifically, the requested modifications will enable FCG to accelerate remediation related to problematic pipes and facilities consisting of obsolete and exposed pipes. These efforts will serve to improve the safety and reliability of service to FCG's customers and the modifications will increase the total projected capital expenditures to $50.0 million in capital expenditures associated with the SAFE Program, which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.

Newberry Expansion: In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 Dt/d of firm service in the Newberry, Florida area. The petition was approved by the Florida PSC in the third quarter of 2023. Peninsula Pipeline will construct a pipeline extension, which will be used by FPU to support the development of a natural gas distribution system to provide gas service to the City of Newberry. A

Chesapeake Utilities Corporation 2025 Form 10-K Page 98 filing to address the acquisition and conversion of existing Company owned propane community gas systems in Newberry was made in November 2023. The Florida PSC approved it in April 2024. Conversions of the community gas systems commenced in the second quarter of 2024 and are projected to be complete in the first quarter of 2026.

East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will provide additional supply to coastal communities on the East Coast of Florida, which are experiencing significant population growth. Peninsula Pipeline proposed several pipeline extensions to support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the second quarter of 2026.

Central Florida Reinforcement Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida which are also experiencing significant population growth. Peninsula Pipeline's extensions support FPU’s distribution system around the Plant City and Lake Mattie areas of Florida with an additional 5,000 Dts/d and 8,700 Dts/d, respectively. The Florida PSC approved the projects in March 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project went into service in July 2025.

Renewable Natural Gas Supply Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition at its July 2024 meeting. In October 2025, the Florida PSC approved amendments to the Transportation Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements. The projects are underway and are estimated to be completed in the second half of 2026.

St. Cloud Project Amendment: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to its Transportation Service Agreement with FPU for a project that will support additional supply to communities in the St. Cloud, Florida area. The project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the second quarter of 2026.

Pioneer Supply Header Pipeline Project: In March 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Firm Transportation Service Agreements with both FCG and FPU for a project that will support greater supply growth of natural gas service in southeast Florida. The project consists of the transfer of a pipeline asset from FCG to Peninsula Pipeline. Peninsula Pipeline will proceed to provide transportation service to both FCG and FPU using the pipeline asset, which supports continued customer growth and system reinforcement of these distribution systems. The Florida PSC approved the petition in July 2024 and the project was completed in September 2024.

Miami Inner Loop Projects: In September 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of the Transportation Service Agreement with FCG for a series of projects that will enhance gas infrastructure in Miami-Dade County. The proposed expansion consists of the development of several pipeline projects to support growth and FCG's distribution system, as well as enhance FCG's access to gas from various points in the Miami-Dade County area. The expansion was approved in February 2025 and interim services began in August 2025 with permanent facilities expected to be in service by the second quarter of 2026.

FPU Electric Rate Case: In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million, were approved with an effective date of November 1, 2024. In March 2025, the Florida PSC approved the permanent rate increase, but the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to resolve all outstanding issues. This settlement which was approved by the Florida PSC in July 2025, provides for a total base rate increase of approximately $8.6 million on an annual basis, with $1.0 million of the increase deferred from the first year's base rate increase and recovered over three years. A step-up rate increase was also approved for up to $0.7 million, upon completion of the purchase and refurbishment of certain substations, which is expected to be completed in December 2026.

Chesapeake Utilities Corporation 2025 Form 10-K Page 99

Florida Mandatory Relocates: In October 2025, FPU and FCG filed a joint petition for approval to establish a recovery surcharge for actual, estimated and projected relocation costs pursuant to the Florida Administrative Code which enables companies to recover the costs associated with relocating or reconstructing facilities that have been required by governmental entities. The projected revenue requirement for 2026 is $0.5 million for FPU and $1.0 million for FCG. The Florida PSC approved the petition in February 2026, with the surcharge effective in March 2026.

Florida City Gas Rate Case: In February 2026, FCG provided notice to the Florida PSC of its intent to file a petition seeking a general rate base increase based on a 2027 projected test year. The rate case filing is expected to be submitted in April 2026 and the outcome of the application will be subject to review and approval by the Florida PSC.

Eastern Shore

Worcester Resiliency Upgrade: In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. In January 2025, the FERC approved the project.

In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025. Construction is underway and the project is expected to be placed into service in mid-2026.

Salisbury Integrity Project: Eastern Shore submitted a Prior Notice Filing under its Blanket Certificate to the FERC in March 2025 requesting to construct, own, operate, and maintain approximately 5.5 miles of 10-inch looping pipeline in Wicomico County, Maryland. The protest period terminated in May 2025 with no protests filed. The project is necessary to comply with pipeline integrity management regulations of the Pipeline and Hazardous Materials Safety Administration ("PHMSA"). The project went into service in October 2025.

Capital Cost Surcharge: In December 2025, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2025. The combined revised surcharge became effective January 1, 2026.

In March 2025, Eastern Shore submitted an annual true-up filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with a PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. There was no impact to the currently effective surcharge as a result of this filing. The FERC issued an order approving the surcharge as filed effective April 1, 2025.

Various Jurisdictional Activity Related to the Joint Customer Information System Project

In July 2022, we filed a joint petition for our natural gas divisions in Maryland (Maryland Division, Sandpiper, and Elkton Gas) for the approval to establish a regulatory asset for non-capitalizable expenses related to the initial development and implementation of our new Customer Information System ("CIS") system. The petition was approved by the Maryland PSC in August 2022. A similar petition for our Florida Regulated Energy businesses was filed during the same time frame, however, the Florida PSC approved capitalization of these expenses in lieu of the establishment of regulatory assets. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. Implementation of the CIS began during the first quarter of 2023 and went into service during the fourth quarter of 2024.

TCJA

In connection with the TCJA, which was signed into law in December 2017, customer rates for our regulated businesses were adjusted as applicable as approved by the regulators. Regulatory liabilities related to accumulated deferred income taxes (“ADIT”) associated with the TCJA amounted to $83.4 million and $84.6 million at December 31, 2025 and 2024, respectively. With the exception of the ADIT balance of $34.2 million attributable to Eastern Shore, such amounts are being amortized in accordance with approvals received from the Delaware, Maryland, and Florida PSCs in 2018 and 2019. The ADIT balance attributable to Eastern Shore will be addressed in its next rate case filing.

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Regulatory Assets and Liabilities

At December 31, 2025 and 2024, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

(1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

(2)Includes amounts being recovered over a three-year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

(3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying gas distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution operations, Fort Meade division and CFG. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 15, Employee Benefit Plans, for additional information.

(5)We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010.

(6) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets.

(7) We have storm reserves in our Florida regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

(8) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(9) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

18. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances.

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MGP Sites

We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida.

As of December 31, 2025 and 2024, we had approximately $3.1 million and $3.2 million, respectively, in environmental liabilities, related to the former MGP sites, and related regulatory assets of $0.2 million and $0.3 million at the respective balance sheet dates for future recovery of environmental costs from customers.

Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware. The remaining clean-up costs are estimated to range from $0.3 million to $0.8 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are not material.

The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east and west Parcels of our West Palm Beach, Florida. These properties were sold to another party in December 2025, and no additional costs associated with remediation of this site are anticipated.

19. OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

In March 2023, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective in April 2023 and expire in March 2026.

FPU natural gas distribution operations and Eight Flags have separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements commenced in November 2020 and expire in October 2030.

FPU natural gas has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency.

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FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this standard, it must provide an Adequate Assurance of Performance which can include an irrevocable letter of credit, a prepayment, a security interest in an asset, or a performance bond or guaranty. As of December 31, 2025, FPU was in compliance with all of the requirements of its supply contracts.

Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to our electric customers. In July 2016, Eight Flags also started selling steam pursuant to a separate 20-year contract, to the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.

The total purchase obligations for natural gas, electric and propane supplies are as follows:

Corporate Guarantees

The BOD has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of December 31, 2025 was $62.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2025 was approximately $41.1 million with the guarantees expiring on various dates through December 2026. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2025 was $4.0 million.

As of December 31, 2025, we have issued letters of credit totaling approximately $4.8 million related to various transportation, transmission, capacity and storage agreements as well as our primary insurance carriers. These letters of credit have various expiration dates through October 2026 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future.

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