CHESAPEAKE UTILITIES CORP 10-Q

Item 1. Financial Statements Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Income (Unaudited) Three Months Ended March 31, 2025 2024 (in millions, except shares and per share data) Operating Revenues Regulated Energy $ 199.6 $ 168.4 Unregulated Energy 106.7 83.1 Other Businesses and Eliminations ( 7.6 ) ( 5.8 ) Total Operating Revenues 298.7 245.7 Operating Expenses Regulated natural gas and electric costs 71.5 49.9 Unregulated propane and natural gas costs 44.8 31.3 Operations 58.0 51.6 Maintenance 5.4 5.9 Depreciation and amortization 22.5 17.0 Other taxes 9.4 9.5 FCG transaction and transition-related expenses 0.3 0.9 Total Operating Expenses 211.9 166.1 Operating Income 86.8 79.6 Other income, net 0.6 0.2 Interest charges 18.1 17.0 Income Before Income Taxes 69.3 62.8 Income taxes 18.4 16.6 Net Income $ 50.9 $ 46.2 Weighted Average Common Shares Outstanding: Basic 22,957 22,250 Diluted 23,041 22,306 Earnings Per Share of Common Stock: Basic $ 2.22 $ 2.07 Diluted $ 2.21 $ 2.07 The accompanying notes are an integral part of these condensed consolidated financial statements. 1 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended March 31, 2025 2024 (in millions) Net Income $ 50.9 $ 46.2 Other Comprehensive Income (Loss), net of tax: Cash Flow Hedges, net of tax: Net gain on commodity contract cash flow hedges, net of tax of $ 0.2 and $ 0.5 , respectively 0.7 1.5 Reclassifications of net (gain) on commodity contract cash flow hedges, net of tax $( 0.2 ) and $( 0.3 ), respectively ( 0.5 ) ( 0.8 ) Net gain (loss) on interest rate swap cash flow hedges, net of tax of $( 0.2 ) and $ 0.1 , respectively ( 0.7 ) 0.4 Reclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $ 0.0 and $ 0.0 , respectively ( 0.1 ) ( 0.1 ) Total Other Comprehensive Income (Loss), net of tax ( 0.6 ) 1.0 Comprehensive Income $ 50.3 $ 47.2 The accompanying notes are an integral part of these condensed consolidated financial statements. 2 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited) Assets March 31, 2025 December 31, 2024 (in millions, except shares and per share data) Property, Plant and Equipment Regulated Energy $ 2,737.1 $ 2,661.8 Unregulated Energy 472.1 463.7 Other Businesses and Eliminations 38.2 29.9 Total property, plant and equipment 3,247.4 3,155.4 Less: Accumulated depreciation and amortization ( 585.8 ) ( 567.6 ) Plus: Construction work in progress 166.6 148.1 Net property, plant and equipment 2,828.2 2,735.9 Current Assets Cash and cash equivalents 0.7 7.9 Trade and other receivables 101.2 80.0 Less: Allowance for credit losses ( 4.2 ) ( 3.3 ) Trade and other receivables, net 97.0 76.7 Accrued revenue 31.4 37.8 Propane inventory, at average cost 9.1 8.9 Other inventory, at average cost 19.0 18.0 Regulatory assets 17.3 23.9 Storage gas prepayments 0.9 3.8 Income taxes receivable 4.9 6.8 Prepaid expenses 15.5 17.3 Derivative assets, at fair value 0.6 0.6 Other current assets 3.2 2.6 Total current assets 199.6 204.3 Deferred Charges and Other Assets Goodwill 507.7 507.7 Other intangible assets, net 14.6 15.0 Investments, at fair value 14.4 14.4 Derivative assets, at fair value 0.1 0.1 Operating lease right-of-use assets 9.7 10.5 Regulatory assets 77.3 77.4 Receivables and other deferred charges 13.0 11.7 Total deferred charges and other assets 636.8 636.8 Total Assets $ 3,664.6 $ 3,577.0 The accompanying notes are an integral part of these condensed consolidated financial statements. 3 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited) Capitalization and Liabilities March 31, 2025 December 31, 2024 (in millions, except shares and per share data) Capitalization Stockholders’ equity Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding $ — $ — Common stock, par value $0.4867 per share (authorized 50,000,000 shares) 11.2 11.1 Additional paid-in capital 852.0 830.5 Retained earnings 586.4 550.3 Accumulated other comprehensive loss ( 2.3 ) ( 1.7 ) Deferred compensation obligation 12.2 9.8 Treasury stock ( 12.2 ) ( 9.8 ) Total stockholders’ equity 1,447.3 1,390.2 Long-term debt, net of current maturities 1,260.0 1,261.7 Total capitalization 2,707.3 2,651.9 Current Liabilities Current portion of long-term debt 25.5 25.5 Short-term borrowing 215.4 196.5 Accounts payable 76.6 78.3 Customer deposits and refunds 42.0 45.7 Accrued interest 16.2 4.8 Dividends payable 14.7 14.7 Accrued compensation 9.5 23.9 Regulatory liabilities 16.4 16.1 Derivative liabilities, at fair value 0.1 — Other accrued liabilities 17.3 13.9 Total current liabilities 433.7 419.4 Deferred Credits and Other Liabilities Deferred income taxes 312.3 296.1 Regulatory liabilities 185.3 184.0 Environmental liabilities 2.3 2.2 Other pension and benefit costs 13.0 13.2 Derivative liabilities, at fair value 0.9 0.1 Operating lease - liabilities 8.4 8.7 Deferred investment tax credits and other liabilities 1.4 1.4 Total deferred credits and other liabilities 523.6 505.7 Environmental and other commitments and contingencies (Notes 6 and 7) Total Capitalization and Liabilities $ 3,664.6 $ 3,577.0 The accompanying notes are an integral part of these condensed consolidated financial statements. 4 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited) Three Months Ended March 31, 2025 2024 (in millions) Operating Activities Net income $ 50.9 $ 46.2 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 22.5 17.0 Depreciation and accretion included in other costs 4.0 4.0 Deferred income taxes 16.5 11.9 Realized loss on commodity contracts and sale of assets ( 1.1 ) ( 1.8 ) Unrealized gain on investments and commodity contracts 0.4 ( 0.8 ) Share-based compensation 2.3 2.1 Changes in assets and liabilities: Accounts receivable and accrued revenue ( 13.9 ) 7.8 Propane inventory, storage gas and other inventory 1.6 4.8 Regulatory assets and liabilities, net 3.6 10.1 Prepaid expenses and other current assets 1.6 2.6 Accounts payable and other accrued liabilities 2.9 ( 10.1 ) Income taxes receivable 1.9 4.6 Customer deposits and refunds ( 3.7 ) ( 2.7 ) Accrued compensation ( 14.6 ) ( 9.5 ) Accrued interest 11.4 10.1 Other assets and liabilities, net ( 1.3 ) 1.0 Net cash provided by operating activities 85.0 97.3 Investing Activities Property, plant and equipment expenditures ( 113.8 ) ( 75.5 ) Proceeds from sale of assets 0.6 0.3 Acquisitions, net of cash acquired — 0.6 Environmental expenditures 0.1 ( 0.1 ) Net cash used in investing activities ( 113.1 ) ( 74.7 ) Financing Activities Common stock dividends ( 14.5 ) ( 12.9 ) Proceeds from issuance of common stock, net of expenses 19.8 — Tax withholding payments related to net settled stock compensation ( 1.0 ) ( 1.5 ) Change in cash overdrafts due to outstanding checks ( 1.7 ) 0.7 Net borrowings (repayments) under line of credit agreements 20.3 ( 10.2 ) Repayment of long-term debt and finance lease obligation ( 2.0 ) ( 1.9 ) Net cash provided by (used in) financing activities 20.9 ( 25.8 ) Net Decrease in Cash and Cash Equivalents ( 7.2 ) ( 3.2 ) Cash and Cash Equivalents—Beginning of Period 7.9 4.9 Cash and Cash Equivalents—End of Period $ 0.7 $ 1.7 The accompanying notes are an integral part of these condensed consolidated financial statements. 5 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) Common Stock (1) (dollars in millions, shares in thousands (except per share data)) Number of Shares (2) Par Value Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income (Loss) Deferred Compensation Treasury Stock Total Balance at December 31, 2023 22,235 $ 10.8 $ 749.4 $ 488.7 $ ( 2.8 ) $ 9.1 $ ( 9.1 ) $ 1,246.1 Net income — — — 46.2 — — — 46.2 Other comprehensive income — — — — 1.0 — — 1.0 Dividends declared ($ 0.590 per share) — — — ( 13.2 ) — — — ( 13.2 ) Issuance under various plans (3) 3 — 0.3 — — — — 0.3 Share-based compensation and tax benefit (4) (5) 29 — 0.5 — — — — 0.5 Treasury stock activities (2) — — — — — 0.5 ( 0.5 ) — Balance at March 31, 2024 22,267 $ 10.8 $ 750.2 $ 521.7 $ ( 1.8 ) $ 9.6 $ ( 9.6 ) $ 1,280.9 Balance at December 31, 2024 22,899 $ 11.1 $ 830.5 $ 550.3 $ ( 1.7 ) $ 9.8 $ ( 9.8 ) $ 1,390.2 Net income — — — 50.9 — — — 50.9 Other comprehensive income — — — — ( 0.6 ) — — ( 0.6 ) Dividends declared ($ 0.640 per share) — — — ( 14.8 ) — — — ( 14.8 ) Issuance under various plans and ATM program (3) 161 0.1 19.7 — — — — 19.8 Share-based compensation and tax benefit (4) (5) 29 — 1.8 — — — — 1.8 Treasury stock activities (2) — — — — — 2.4 ( 2.4 ) — Balance at March 31, 2025 23,089 $ 11.2 $ 852.0 $ 586.4 $ ( 2.3 ) $ 12.2 $ ( 12.2 ) $ 1,447.3 (1) 2.0 million shares of preferred stock at $ 0.01 par value have been authorized. No preferred shares have been issued or are outstanding; accordingly, no information has been included in the Condensed Consolidated Statements of Stockholders’ Equity. (2) Includes 126 thousand, 114 thousand, 111 thousand, and 108 thousand shares at March 31, 2025, December 31, 2024, March 31, 2024 and December 31, 2023, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan. (3) Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM program, as applicable. (4) Includes amounts for shares issued for directors’ compensation. (5) The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended March 31, 2025 and 2024, we withheld 8 thousand and 14 thousand shares, respectively, for employee taxes. The accompanying notes are an integral part of these condensed consolidated financial statements. 6 Table of Contents N OTES TO C ONDENSED C ONSOLIDATED F INANCIAL S TATEMENTS (U NAUDITED ) 1. Summary of Accounting Policies Basis of Presentation References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure. The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2024. In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented. Where necessary to improve comparability, prior period amounts have been reclassified to conform to current period presentation. Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures. 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, will not have a material impact on our financial position or results of operations. Recent Accounting Standards Yet to be Adopted 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. 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 and 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. 7 Table of Contents 2. Calculation of Earnings Per Share Three Months Ended March 31, 2025 2024 (dollars in millions, shares in thousands (except per share data)) Calculation of Basic Earnings Per Share: Net Income $ 50.9 $ 46.2 Weighted average shares outstanding 22,957 22,250 Basic Earnings Per Share $ 2.22 $ 2.07 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted shares outstanding—Basic 22,957 22,250 Effect of dilutive securities—Share-based compensation 84 56 Adjusted denominator—Diluted 23,041 22,306 Diluted Earnings Per Share $ 2.21 $ 2.07 3. Acquisitions There were no acquisitions completed during 2024 or during the three months ended March 31, 2025. T he Company’s consolidated results include certain transaction and transition-related expenses for the three months ended March 31, 2025 and 2024 related to the integration of the FCG acquisition which was completed in November 2023. Refer to our Annual Report on Form 10-K for the year ended December 31, 2024 for additional details on the FCG acquisition as well as previous acquisitions. 8 Table of Contents 4. Revenue Recognition 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 our revenue by major source based on product and service type for the three months ended March 31, 2025 and 2024: Three Months Ended March 31, 2025 Three Months Ended March 31, 2024 (in millions) Regulated Energy Unregulated Energy Other Businesses and Eliminations Total Regulated Energy Unregulated Energy Other Businesses and Eliminations Total Energy distribution Delaware natural gas division $ 42.3 $ — $ — $ 42.3 $ 31.9 $ — $ — $ 31.9 Florida natural gas distribution 51.3 — — 51.3 47.9 — — 47.9 Florida City Gas 43.6 — — 43.6 35.9 — — 35.9 FPU electric distribution 23.2 — — 23.2 20.0 — — 20.0 Maryland natural gas division (1) 12.9 — — 12.9 9.9 — — 9.9 Sandpiper natural gas/propane operations (1) 8.4 — — 8.4 7.0 — — 7.0 Elkton Gas (1) 4.0 — — 4.0 2.9 — — 2.9 Total energy distribution 185.7 — — 185.7 155.5 — — 155.5 Energy transmission Aspire Energy — 19.2 — 19.2 — 13.6 — 13.6 Aspire Energy Express 0.4 — — 0.4 0.4 — — 0.4 Eastern Shore 22.7 — — 22.7 21.2 — — 21.2 Peninsula Pipeline 10.0 — — 10.0 8.0 — — 8.0 Total energy transmission 33.1 19.2 — 52.3 29.6 13.6 — 43.2 Energy generation Eight Flags — 4.7 — 4.7 — 4.6 — 4.6 Propane operations Propane delivery operations — 74.7 — 74.7 — 61.6 — 61.6 CNG / RNG Services Marlin Gas Services — 7.2 — 7.2 — 3.4 — 3.4 Other RNG — 1.0 — 1.0 — — — — Total CNG / RNG Services — 8.2 — 8.2 — 3.4 — 3.4 Other Businesses and Eliminations Eliminations ( 19.2 ) ( 0.1 ) ( 7.6 ) ( 26.9 ) ( 16.7 ) ( 0.1 ) ( 5.8 ) ( 22.6 ) Total operating revenues (2) $ 199.6 $ 106.7 $ ( 7.6 ) $ 298.7 $ 168.4 $ 83.1 $ ( 5.8 ) $ 245.7 (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 natural gas/propane operations and Elkton Gas) will be consolidated for rate-making and other purposes and will be presented in a consolidated basis consistent with the final rate order going forward. (2) Total operating revenues for the three months ended March 31, 2025 include other revenue (revenues from sources other than contracts with customers) of $ 0.5 million loss and $ 0.1 million for our Regulated Energy and Unregulated Energy segments, respectively, and $ 0.6 million and $ 0.1 million for our Regulated Energy and Unregulated Energy segments, respectively, for the three months ended March 31, 2024. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper Energy and late fees . 9 Table of Contents Contract Balances The timing of revenue recognition, customer billings and cash collections results in trade receivables and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2024 and March 31, 2025 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Non-current) Contract Liabilities (Current) (in millions) Balance at 12/31/2024 $ 66.2 $ — $ 3.0 $ 1.2 Balance at 3/31/2025 84.3 — 2.9 0.8 Increase (Decrease) $ 18.1 $ — $ ( 0.1 ) $ ( 0.4 ) Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our non-current contract assets are included in receivables and other deferred charges in the condensed consolidated balance sheets and primarily 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 condensed 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 customer retail program on a ratable basis. For the three months ended March 31, 2025 and 2024, the amounts recognized in revenue were not material. Remaining Performance Obligations Certain of 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 March 31, 2025, are expected to be recognized as follows: (in millions) 2025 2026 2027 2028 2029 2030 2031 and thereafter Eastern Shore and Peninsula Pipeline $ 28.0 $ 34.9 $ 31.1 $ 29.0 $ 26.6 $ 21.2 $ 109.6 Natural gas distribution operations 9.2 12.3 10.8 10.8 10.7 7.3 31.0 FPU electric distribution 0.8 1.1 0.6 0.6 0.6 — — Total revenue contracts with remaining performance obligations $ 38.0 $ 48.3 $ 42.5 $ 40.4 $ 37.9 $ 28.5 $ 140.6 10 Table of Contents 5. 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 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 seeking 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 providing an annual revenue increase of $ 6.1 million, dividing the rate case into two phases and suspending the procedural schedule. The related, fully executed settlement agreement has been filed in the docket and awaits Delaware PSC approval, with a hearing scheduled in May 2025. Interim rates, set to recover the $ 6.1 million increase went into effect in March 2025. A procedural schedule is pending in Phase II which will address tariff-related changes including rate design. 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, the “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 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 related settlement agreement in part. The $ 2.6 million increase in annual base rates was approved and the Company filed a 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 and Phase II was approved including an additional $ 0.9 million in revenue requirement for a total cumulative increase of $ 3.5 million. The approval also included the consolidation of the operations of CUC-Maryland Division, Sandpiper Energy, and Elkton Gas into one entity which was renamed and will operate as Chesapeake Utilities of Maryland, Inc. Maryland Natural Gas Depreciation Study: In January 2024, the Company's Maryland natural gas distribution businesses filed a joint petition for approval of its proposed unified depreciation rates with the Maryland PSC. A settlement among the Company, PSC staff and the Maryland OPC was reached and the final order approving the related settlement agreement went into effect in July 2024, with new depreciation rates effective as of January 1, 2023. The approved depreciation rates 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, with construction on the overall project continuing through 2025. 11 Table of Contents 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 RSAM is 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 is 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 includes 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 is adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. At December 31, 2024, the RSAM reserve had been completely utilized. In February 2025, FCG filed a depreciation study with the Florida PSC. The application is requesting 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 is subject to review and approval by the Florida PSC. The Florida OPC filed a motion to hold this filing in abeyance, which was denied in April 2025. A final ruling on the depreciation study is expected in September 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 require 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 during the first quarter of 2022 and approved in the fourth quarter of 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. GUARD Program : 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 pipe and facilities consisting of obsolete and exposed pipe. 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. 12 Table of Contents 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 Dts/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 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 and conversions of the community gas systems commenced in the second quarter of 2024. 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 support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will 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. Construction is projected to be complete in the second and fourth quarters of 2025 for New Smyrna Beach and Boynton Beach, respectively. Central Florida Reinforcement Projects : In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida. The projects are driven by the need for increased supply to communities in central Florida that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will 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 May 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project is projected to be completed during the fourth quarter of 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 with the projects estimated to be completed in the first half of 2025. 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 fourth quarter of 2025. 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 supporting 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 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 the infrastructure in Miami-Dade county. The proposed expansion consists of the development of several pipeline projects to support growth and support FCG's distribution system in the area and also enhance FCG's ability to obtain gas from various access points in the Miami-Dade county area. The project was approved in February 2025 and construction is expected to be complete in the second half of 2025. 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 13 Table of Contents 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 in its current base rate case, which was filed as a joint motion for approval with the Florida PSC. This settlement allows for a total revenue increase of approximately $ 8.6 million on an annual basis. The Company anticipates this agreement to be on the Florida PSC hearing agenda for review and approval in June 2025. 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, and construction is expected to be complete in the second quarter of 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 project is necessary to comply with pipeline integrity management regulations of the Pipeline and Hazardous Materials Safety Administration ("PHMSA"). Capital Cost Surcharge: 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. TCJA In connection with the TCJA, which was signed into law in December 2017, customer rates for our regulated businesses were adjusted as approved by the regulators. Regulatory liabilities related to accumulated deferred income taxes (“ADIT”) associated with the TCJA amounted to $ 84.3 million and $ 84.6 million at March 31, 2025 and December 31, 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. 6. 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. 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 March 31, 2025 and December 31, 2024, we had approximately $ 3.3 million and $ 3.2 million, respectively, in environmental liabilities related to the former MGP sites, and related regulatory assets of approximately $ 0.3 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 MGPs in Winter Haven and Key West, 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 14 Table of Contents 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 parcel of our West Palm Beach, Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of the systems required to remediate the site are now complete with remediation activities ongoing as of March 31, 2025. Remaining remedial costs for West Palm Beach, including completion of the construction for the system start-up on the west parcel, and continued operation and maintenance, are estimated to take between five and fifteen years of operation, maintenance and monitoring, and final site work for closeout of the property is estimated to be between $ 2.8 million and $ 5.2 million. 7. 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. Florida 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. 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 March 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. Corporate Guarantees The Board of Directors 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 March 31, 2025 was $ 38.0 million. The aggregate amount guaranteed related to our subsidiaries at March 31, 2025 was $ 28.6 million with the guarantees expiring on various dates through March 2026. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at March 31, 2025 was $ 5.2 million. As of March 31, 2025, we have issued letters of credit totaling $ 7.6 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 February 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. 8. 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 15 Table of Contents by the chief operating decision maker, our President and Chief Executive Officer ("CEO"), 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. 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 table presents information about our reportable segments: Three Months Ended March 31, 2025 2024 (in millions) Regulated Unregulated Other Businesses and Eliminations (1) Total Regulated Unregulated Other Businesses and Eliminations (1) Total Operating revenues, unaffiliated customers $ 199.2 $ 99.5 $ — $ 298.7 $ 167.9 $ 77.8 $ — $ 245.7 Intersegment revenues (2) 0.4 7.2 ( 7.6 ) — 0.5 5.3 ( 5.8 ) — 199.6 106.7 ( 7.6 ) 298.7 168.4 83.1 ( 5.8 ) 245.7 Less: Natural gas, propane and electric costs 71.5 52.2 ( 7.4 ) 116.3 49.9 37.1 ( 5.8 ) 81.2 Operations and maintenance expenses 41.7 21.8 ( 0.1 ) 63.4 39.0 18.6 ( 0.1 ) 57.5 Depreciation and amortization 17.6 4.9 — 22.5 12.5 4.5 — 17.0 Other segment items (3) 8.3 1.5 ( 0.1 ) 9.7 8.9 1.5 — 10.4 Segment operating income $ 60.5 $ 26.3 $ — $ 86.8 $ 58.1 $ 21.4 $ 0.1 $ 79.6 Other income, net 0.6 0.2 Interest charges 18.1 17.0 Income before income taxes 69.3 62.8 Income taxes 18.4 16.6 Net Income $ 50.9 $ 46.2 Capital expenditures $ 96.1 $ 14.8 $ 2.0 $ 112.9 $ 59.9 $ 9.8 $ 0.9 $ 70.6 (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 - Other taxes and transaction and transition costs related to the integration of FCG; Unregulated - Other taxes. 16 Table of Contents (in millions) March 31, 2025 December 31, 2024 Identifiable Assets Regulated Energy segment $ 3,128.9 $ 3,042.9 Unregulated Energy segment 488.2 486.4 Other Businesses and Eliminations 47.5 47.7 Total Identifiable Assets $ 3,664.6 $ 3,577.0 9. Stockholders' Equity Common Stock Issuances We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and other plans. 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 three months ended March 31, 2025 and 2024, we received net proceeds of $ 19.8 million and $ 0.1 million, respectively, associated with shares issued under the direct stock purchase and waiver components of the DRIP as well as shares issued under our ATM program. Accumulated Other Comprehensive 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 loss. The following tables present the changes in the balances of accumulated other comprehensive loss components for the three months ended March 31, 2025 and 2024. All amounts in the following tables are presented net of tax. Defined Benefit Commodity Interest Rate Pension and Contract Swap Postretirement Cash Flow Cash Flow Plan Items Hedges Hedges Total (in millions) As of December 31, 2024 $ ( 2.1 ) $ 0.4 $ — $ ( 1.7 ) Other comprehensive income (loss) before reclassifications — 0.7 ( 0.7 ) — Amounts reclassified from accumulated other comprehensive income (loss) — ( 0.5 ) ( 0.1 ) ( 0.6 ) Net current-period other comprehensive income (loss) — 0.2 ( 0.8 ) ( 0.6 ) As of March 31, 2025 $ ( 2.1 ) $ 0.6 $ ( 0.8 ) $ ( 2.3 ) As of December 31, 2023 $ ( 2.6 ) $ ( 0.3 ) $ 0.1 $ ( 2.8 ) Other comprehensive income before reclassifications — 1.5 0.4 1.9 Amounts reclassified from accumulated other comprehensive loss — ( 0.8 ) ( 0.1 ) ( 0.9 ) Net prior-period other comprehensive income (loss) — 0.7 0.3 1.0 As of March 31, 2024 $ ( 2.6 ) $ 0.4 $ 0.4 $ ( 1.8 ) 17 Table of Contents 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 12, 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 cost (benefit). See Note 10, Employee Benefit Plans , for additional details. 10. Employee Benefit Plans Net periodic (benefit) cost for the FPU Pension Plan for the three months ended March 31, 2025 and 2024 is set forth in the following table: Three Months Ended March 31, 2025 2024 (in millions) Interest cost $ 0.6 $ 0.6 Expected return on plan assets ( 0.7 ) ( 0.7 ) Amortization of net loss — 0.1 Total periodic (benefit) cost $ ( 0.1 ) $ — Net periodic costs for our other pension and postretirement benefit plans were not material for the three months ended March 31, 2025 and 2024. In addition, total amounts reclassified from accumulated other comprehensive income (loss) and regulatory assets related to all pension and postretirement benefit plans were not material during the three months ended March 31, 2025 and 2024. The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to their respective regulatory orders, FPU and Chesapeake Utilities continue to record a portion of their unrecognized postretirement benefit costs related to their regulated operations as a regulatory asset. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive income (loss). During the three months ended March 31, 2025, there were no contributions to the FPU Pension Plan and we do not expect to contribute to the FPU Pension Plan during 2025. The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under these other postretirement benefit plans for the three months ended March 31, 2025 were not material. We expect to pay total cash benefits of approximately $ 0.3 million for these other postretirement benefit plans in 2025. Non-Qualified Deferred Compensation Plan Members of our Board of Directors 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 to 6 percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. 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. Assets held in the Rabbi Trust, recorded as Investments on the condensed consolidated balance sheets, had a fair value of $ 14.4 million at both March 31, 2025 and December 31, 2024. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors. 18 Table of Contents 11. Share-Based Compensation 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 to be issued at the end of the service period. The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2025 and 2024: Three Months Ended March 31, 2025 2024 (in millions) Awards to key employees $ 2.1 $ 1.9 Awards to non-employee directors 0.2 0.2 Total compensation expense 2.3 2.1 Less: tax benefit ( 0.6 ) ( 0.5 ) Share-based compensation amounts included in net income $ 1.7 $ 1.6 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, 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 the Monte Carlo valuation to estimate the fair value of each share granted. The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2025: (in thousands, except per share data) Number of Shares Weighted Average Fair Value/Share Outstanding—December 31, 2024 253 $ 117.96 Granted 95 $ 125.55 Vested ( 37 ) $ 129.97 Expired ( 26 ) $ 113.44 Outstanding—March 31, 2025 285 $ 115.55 During the three months ended March 31, 2025, we granted awards of 95 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. In March 2025, upon the election by certain of our executive officers and key employees, 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 for the performance period ended December 31, 2024. We paid the balance of such awarded shares to each such executive officer and remitted cash equivalent to the withheld shares to the appropriate taxing authorities. We withheld 8 thousand shares based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $ 1.0 million. 19 Table of Contents At March 31, 2025, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $ 36.7 million. At March 31, 2025, there was approximately $ 13.3 million of unrecognized compensation cost related to these awards, which will be recognized through 2027. 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 Shareholders. Accordingly, our directors that served on the Board as of May 2024 each received approximately 1 thousand shares of common stock, respectively, with a weighted average fair value of $ 110.53 per share. At March 31, 2025, there was $ 0.1 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 2025. 12. 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 March 31, 2025, our natural gas and electric distribution operations did not have any outstanding derivative contracts. Volume of Derivative Activity As of March 31, 2025, the volume of our commodity derivative contracts were as follows: Business unit Commodity Contract Type Quantity hedged (in millions) Designation Longest Expiration date of hedge Sharp Propane (gallons) Purchases 6.3 Cash flow hedges March 2027 Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes that are expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in April 2025 through March 2027) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the contract prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flow hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. The amount of unrealized gains that we expect to reclassify from accumulated other comprehensive income (loss) related to our commodity cash flow hedges to earnings during the 12 -month period ended March 31, 2026 is $ 0.6 million. 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 through September 2025, with pricing of 3.98 percent. In August 2024, we entered into an 20 Table of Contents 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 swap are recorded as a component of accumulated other comprehensive income (loss). When 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 March 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 condensed consolidated balance sheets as of March 31, 2025 and December 31, 2024, are as follows: Derivative Assets Fair Value As Of (in millions) Balance Sheet Location March 31, 2025 December 31, 2024 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value $ 0.6 $ 0.6 Interest rate swap agreements Derivative assets, at fair value 0.1 0.1 Total Derivative Assets (1) $ 0.7 $ 0.7 (1) Derivative assets, at fair value, include $ 0.6 million in current assets in the condensed consolidated balance sheet at March 31, 2025 and $ 0.6 million at December 31, 2024, with the remainder of the balances classified as long-term . Derivative Liabilities Fair Value As Of (in millions) Balance Sheet Location March 31, 2025 December 31, 2024 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value $ — $ — Interest rate swap agreements Derivative liabilities, at fair value 1.0 0.1 Total Derivative Liabilities (1) $ 1.0 $ 0.1 (1) Derivative liabilities, at fair value, include $ 0.1 million in current liabilities in the condensed consolidated balance sheet at March 31, 2025 and no current derivative liabilities at December 31, 2024, with the remainder of the balances classified as long-term. 21 Table of Contents The effects of gains and losses from derivative instruments on the condensed consolidated statements of income are as follows: Amount of Gain (Loss) on Derivatives Location of Gain For the Three Months Ended March 31, (in millions) (Loss) on Derivatives 2025 2024 Derivatives designated as cash flow hedges Propane swap agreements Revenues $ — $ ( 0.3 ) Propane swap agreements Unregulated propane and natural gas costs 0.7 1.4 Interest rate swap agreements Interest expense 0.1 0.2 Total $ 0.8 $ 1.3 22 Table of Contents 13. 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 the following: Fair Value Hierarchy Description of Fair Value Level Fair Value Technique Utilized Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities. Investments - equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. Investments - mutual funds and other - The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares. Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability. Derivative assets and liabilities - The fair value of the propane put/call options, propane and interest rate swap agreements are measured using market transactions for similar assets and liabilities in either the listed or over-the-counter markets. Level 3 Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity). Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value. 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 March 31, 2025 and December 31, 2024: Fair Value Measurements Using: As of March 31, 2025 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Assets: Investments—guaranteed income fund $ 1.0 $ — $ — $ 1.0 Investments—mutual funds and other 13.4 13.4 — — Total investments 14.4 13.4 — 1.0 Derivative assets 0.7 — 0.7 — Total assets $ 15.1 $ 13.4 $ 0.7 $ 1.0 Liabilities: Derivative liabilities $ 1.0 $ — $ 1.0 $ — 23 Table of Contents Fair Value Measurements Using: As of December 31, 2024 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in millions) Assets: Investments—guaranteed income fund $ 1.1 $ — $ — $ 1.1 Investments—mutual funds and other 13.3 13.3 — — Total investments 14.4 13.3 — 1.1 Derivative assets 0.7 — 0.7 — Total assets $ 15.1 $ 13.3 $ 0.7 $ 1.1 Liabilities: Derivative liabilities $ 0.1 $ — $ 0.1 $ — The changes in the fair value of Level 3 investments for the three months ended March 31, 2025 and 2024 were not material. Investment income from the Level 3 investments is reflected in other income, net in the condensed consolidated statements of income. At March 31, 2025, 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 and 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 and approximates its carrying value (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). At March 31, 2025, long-term debt, which includes current maturities but excludes debt issuance costs, had both a carrying value and estimated fair value of approximately $ 1.3 billion. At December 31, 2024, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $ 1.3 billion compared to an 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. 24 Table of Contents 14. Long-Term Debt Our outstanding long-term debt is shown below: March 31, December 31, (in millions) 2025 2024 Uncollateralized Senior Notes: 5.68% notes, due June 2026 $ 5.8 $ 5.8 6.39% notes, due December 2026 100.0 100.0 6.44% notes, due December 2027 100.0 100.0 6.43% notes, due May 2028 2.8 2.8 3.73% notes, due December 2028 8.0 8.0 6.45% notes, due December 2028 100.0 100.0 3.88% notes, due May 2029 25.0 25.0 5.20% notes, due October 2029 100.0 100.0 6.62% notes, due December 2030 100.0 100.0 3.25% notes, due April 2032 50.8 52.5 6.71% notes, due December 2033 100.0 100.0 2.98% notes, due December 2034 70.0 70.0 3.00% notes, due July 2035 50.0 50.0 2.96% notes, due August 2035 40.0 40.0 2.49% notes, due January 2037 50.0 50.0 5.43% notes, due March 2038 80.0 80.0 3.48% notes, due May 2038 50.0 50.0 3.58% notes, due November 2038 50.0 50.0 6.73% notes, due December 2038 50.0 50.0 3.98% notes, due August 2039 100.0 100.0 2.95% notes, due March 2042 50.0 50.0 Equipment security note 2.46% note, due September 2031 6.5 6.7 Less: debt issuance costs ( 3.4 ) ( 3.6 ) Total long-term debt 1,285.5 1,287.2 Less: current maturities ( 25.5 ) ( 25.5 ) Total long-term debt, net of current maturities $ 1,260.0 $ 1,261.7 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 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. Shelf Agreements We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026, however neither of such lenders have any obligation to purchase debt thereunder. At March 31, 2025, a total of $ 255.0 million of borrowing capacity was available under these Shelf Agreements. 25 Table of Contents 15. Short-Term Borrowings As of March 31, 2025, we are authorized by our Board of Directors to borrow up to $ 450.0 million of short-term debt, as required. At March 31, 2025 and December 31, 2024, we had $ 215.4 million and $ 196.5 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.08 percent and 5.06 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at March 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 which now expires in August 2025 and $ 200.0 million available under the five-year tranche which now expires in August 2029. 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 12, 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 March 31, 2025, we were in compliance with this covenant. Our total available credit under the Revolver at March 31, 2025 was $ 227.0 million. As of March 31, 2025, we had issued $ 7.6 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. 16. Leases We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These lease arrangements enable us to better conduct business operations in the regions in which we operate. Office space is leased to provide adequate workspace for our employees in several locations throughout our service territories. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses. Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at March 31, 2025, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of March 31, 2025, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. Total operating lease 26 Table of Contents cost and cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated financial statements were not material as of March 31, 2025 and 2024. The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheets at March 31, 2025 and December 31, 2024: (in millions) Balance sheet classification March 31, 2025 December 31, 2024 Assets Operating lease assets Operating lease right-of-use assets $ 9.7 $ 10.5 Liabilities Current Operating lease liabilities Other accrued liabilities $ 1.9 $ 2.4 Noncurrent Operating lease liabilities Operating lease - liabilities 8.4 8.7 Total lease liabilities $ 10.3 $ 11.1 The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating leases at March 31, 2025 and December 31, 2024: March 31, 2025 December 31, 2024 Weighted-average remaining lease term ( in years ) Operating leases 7.9 7.7 Weighted-average discount rate Operating leases 3.5 % 3.5 % The following table presents the future undiscounted maturities of our operating and financing leases at March 31, 2025 and for each of the next five years and thereafter: (in millions) Operating Leases (1) Remainder of 2025 $ 1.7 2026 1.8 2027 1.6 2028 1.3 2029 1.2 2030 1.1 Thereafter 3.0 Total lease payments 11.7 Less: Interest ( 1.4 ) Present value of lease liabilities $ 10.3 (1) Operating lease payments include $ 2.0 million related to options to extend lease terms that are reasonably certain of being exercised. 27 Table of Contents