CHESAPEAKE UTILITIES CORP 10-Q

Item 1. Financial Statements Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Income (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands, except per share data) Operating Revenues Regulated Energy $ 130,625 $ 101,141 $ 299,051 $ 243,411 Unregulated Energy 41,419 40,751 124,522 123,916 Other businesses and eliminations ( 5,772 ) ( 6,299 ) ( 11,557 ) ( 13,605 ) Total Operating Revenues 166,272 135,593 412,016 353,722 Operating Expenses Natural gas and electric costs 27,378 23,886 77,296 79,174 Propane and natural gas costs 12,262 11,907 43,561 45,208 Operations 52,339 42,163 103,899 86,930 FCG transaction and transition-related expenses 1,374 — 2,295 — Maintenance 5,561 5,258 11,464 10,362 Depreciation and amortization 17,877 17,303 34,893 34,486 Other taxes 8,691 6,730 18,233 14,301 Total Operating Expenses 125,482 107,247 291,641 270,461 Operating Income 40,790 28,346 120,375 83,261 Other income, net 1,110 831 1,305 1,107 Interest charges 16,813 6,964 33,839 14,196 Income Before Income Taxes 25,087 22,213 87,841 70,172 Income taxes 6,816 6,080 23,402 17,695 Net Income $ 18,271 $ 16,133 $ 64,439 $ 52,477 Weighted Average Common Shares Outstanding: Basic 22,284 17,794 22,267 17,777 Diluted 22,335 17,852 22,320 17,842 Earnings Per Share of Common Stock: Basic $ 0.82 $ 0.91 $ 2.89 $ 2.95 Diluted $ 0.82 $ 0.90 $ 2.89 $ 2.94 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 Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands) Net Income $ 18,271 $ 16,133 $ 64,439 $ 52,477 Other Comprehensive Income (Loss), net of tax: Employee Benefits, net of tax: Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $ 5 , $ 3 , $ 9 and $ 5 , respectively 14 12 27 21 Cash Flow Hedges, net of tax: Net gain (loss) on commodity contract cash flow hedges, net of tax of $ 72 , $( 784 ), $ 606 and $( 775 ), respectively 199 ( 2,065 ) 1,640 ( 2,045 ) Reclassifications of net (gain) loss on commodity contract cash flow hedges, net of tax $ 11 , $ 119 , $( 282 ) and $( 48 ), respectively 30 313 ( 761 ) ( 126 ) Net gain on interest rate swap cash flow hedges, net of tax of $ 32 , $ 267 , $ 175 and $ 213 , respectively 94 758 511 612 Reclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $( 43 ), $( 33 ), $( 87 ) and $( 50 ), respectively ( 127 ) ( 94 ) ( 255 ) ( 142 ) Total Other Comprehensive Income (Loss), net of tax 210 ( 1,076 ) 1,162 ( 1,680 ) Comprehensive Income $ 18,481 $ 15,057 $ 65,601 $ 50,797 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 June 30, 2024 December 31, 2023 (in thousands, except per share data) Property, Plant and Equipment Regulated Energy $ 2,515,712 $ 2,418,494 Unregulated Energy 420,074 410,807 Other businesses and eliminations 32,645 30,310 Total property, plant and equipment 2,968,431 2,859,611 Less: Accumulated depreciation and amortization ( 546,598 ) ( 516,429 ) Plus: Construction work in progress 157,347 113,192 Net property, plant and equipment 2,579,180 2,456,374 Current Assets Cash and cash equivalents 6,430 4,904 Trade and other receivables 56,362 74,485 Less: Allowance for credit losses ( 2,195 ) ( 2,699 ) Trade and other receivables, net 54,167 71,786 Accrued revenue 20,177 32,597 Propane inventory, at average cost 6,511 9,313 Other inventory, at average cost 19,715 19,912 Regulatory assets 19,646 19,506 Storage gas prepayments 2,801 4,695 Income taxes receivable 9,865 3,829 Prepaid expenses 12,549 15,407 Derivative assets, at fair value 1,180 1,027 Other current assets 3,236 2,723 Total current assets 156,277 185,699 Deferred Charges and Other Assets Goodwill 507,856 508,174 Other intangible assets, net 15,910 16,865 Investments, at fair value 13,620 12,282 Derivative assets, at fair value 192 40 Operating lease right-of-use assets 11,201 12,426 Regulatory assets 83,594 96,396 Receivables and other deferred charges 12,923 16,448 Total deferred charges and other assets 645,296 662,631 Total Assets $ 3,380,753 $ 3,304,704 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 June 30, 2024 December 31, 2023 (in thousands, except per share data) Capitalization Stockholders’ equity Preferred stock, par value $0.01 per share (authorized 2,000 shares), no shares issued and outstanding $ — $ — Common stock, par value $0.4867 per share (authorized 50,000 shares) 10,854 10,823 Additional paid-in capital 755,751 749,356 Retained earnings 525,525 488,663 Accumulated other comprehensive loss ( 1,576 ) ( 2,738 ) Deferred compensation obligation 9,703 9,050 Treasury stock ( 9,703 ) ( 9,050 ) Total stockholders’ equity 1,290,554 1,246,104 Long-term debt, net of current maturities 1,174,762 1,187,075 Total capitalization 2,465,316 2,433,179 Current Liabilities Current portion of long-term debt 18,592 18,505 Short-term borrowing 207,091 179,853 Accounts payable 69,041 77,481 Customer deposits and refunds 44,775 46,427 Accrued interest 3,652 7,020 Dividends payable 14,272 13,119 Accrued compensation 12,519 16,544 Regulatory liabilities 19,677 13,719 Derivative liabilities, at fair value 27 354 Other accrued liabilities 20,547 13,362 Total current liabilities 410,193 386,384 Deferred Credits and Other Liabilities Deferred income taxes 283,322 259,082 Regulatory liabilities 192,710 195,279 Environmental liabilities 2,402 2,607 Other pension and benefit costs 16,102 15,330 Derivative liabilities, at fair value 12 927 Operating lease - liabilities 9,341 10,550 Deferred investment tax credits and other liabilities 1,355 1,366 Total deferred credits and other liabilities 505,244 485,141 Environmental and other commitments and contingencies (Notes 6 and 7) Total Capitalization and Liabilities $ 3,380,753 $ 3,304,704 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) Six Months Ended June 30, 2024 2023 (in thousands) Operating Activities Net income $ 64,439 $ 52,477 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 34,787 34,486 Depreciation and accretion included in other costs 8,196 5,714 Deferred income taxes 23,810 5,695 Realized loss on commodity contracts and sale of assets ( 3,056 ) ( 1,032 ) Unrealized gain on investments and commodity contracts ( 1,006 ) ( 1,131 ) Employee benefits and compensation ( 48 ) 218 Share-based compensation 4,512 2,919 Other, net ( 229 ) — Changes in assets and liabilities: Accounts receivable and accrued revenue 30,070 30,812 Propane inventory, storage gas and other inventory 4,894 5,052 Regulatory assets and liabilities, net 12,221 28,796 Prepaid expenses and other current assets 4,319 2,953 Accounts payable and other accrued liabilities ( 4,624 ) ( 18,273 ) Income taxes receivable/payable ( 6,036 ) 1,265 Customer deposits and refunds ( 1,652 ) 1,316 Accrued compensation ( 4,192 ) ( 5,061 ) Accrued interest ( 3,368 ) 80 Other assets and liabilities, net 4,341 2,697 Net cash provided by operating activities 167,378 148,983 Investing Activities Property, plant and equipment expenditures ( 157,960 ) ( 90,265 ) Proceeds from sale of assets 1,767 2,034 Acquisitions, net of cash acquired 603 — Environmental expenditures ( 205 ) ( 760 ) Net cash used in investing activities ( 155,795 ) ( 88,991 ) Financing Activities Common stock dividends ( 25,827 ) ( 19,009 ) Issuance of stock under the Dividend Reinvestment Plan, net of offering fees 2,471 ( 14 ) Tax withholding payments related to net settled stock compensation ( 1,466 ) ( 2,455 ) Change in cash overdrafts due to outstanding checks 235 ( 2,157 ) Net borrowings (repayments) under line of credit agreements 27,003 ( 104,194 ) Proceeds from long-term debt, net of offering fees — 79,840 Repayment of long-term debt ( 12,473 ) ( 14,038 ) Net cash used in financing activities ( 10,057 ) ( 62,027 ) Net Increase (Decrease) in Cash and Cash Equivalents 1,526 ( 2,035 ) Cash and Cash Equivalents—Beginning of Period 4,904 6,204 Cash and Cash Equivalents—End of Period $ 6,430 $ 4,169 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) (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 March 31, 2023 17,790 $ 8,659 $ 379,703 $ 472,209 $ ( 1,983 ) $ 8,816 $ ( 8,816 ) $ 858,588 Net income — — — 16,133 — — — 16,133 Other comprehensive loss — — — — ( 1,076 ) — — ( 1,076 ) Dividend declared ($ 0.590 per share) — — — ( 10,547 ) — — — ( 10,547 ) Issuance under various plans (3) — — ( 8 ) — — — — ( 8 ) Share-based compensation and tax benefit (4) (5) 7 3 1,135 — — — — 1,138 Treasury stock activities — — — — — 185 ( 185 ) — Balance at June 30, 2023 17,797 $ 8,662 $ 380,830 $ 477,795 $ ( 3,059 ) $ 9,001 $ ( 9,001 ) $ 864,228 Balance at December 31, 2022 17,741 $ 8,635 $ 380,036 $ 445,509 $ ( 1,379 ) $ 7,060 $ ( 7,060 ) $ 832,801 Net income — — — 52,477 — — — 52,477 Other comprehensive loss — — — — ( 1,680 ) — — ( 1,680 ) Dividends declared ($ 1.125 per share) — — — ( 20,191 ) — — — ( 20,191 ) Issuance under various plans (3) — — ( 19 ) — — — — ( 19 ) Share-based compensation and tax benefit (4) (5) 56 27 813 — — — — 840 Treasury stock activities (2) — — — — — 1,941 ( 1,941 ) — Balance at June 30, 2023 17,797 $ 8,662 $ 380,830 $ 477,795 $ ( 3,059 ) $ 9,001 $ ( 9,001 ) $ 864,228 Balance at March 31, 2024 22,267 $ 10,838 $ 750,162 $ 521,689 $ ( 1,786 ) $ 9,562 $ ( 9,562 ) $ 1,280,903 Net income — — — 18,271 — — — 18,271 Other comprehensive income — — — — 210 — — 210 Dividend declared ($ 0.640 per share) — — — ( 14,435 ) — — — ( 14,435 ) Issuance under various plans (3) 25 12 2,607 — — — — 2,619 Share-based compensation and tax benefit (4) (5) 7 4 2,982 — — — — 2,986 Treasury stock activities — — — — — 141 ( 141 ) — Balance at June 30, 2024 22,299 $ 10,854 $ 755,751 $ 525,525 $ ( 1,576 ) $ 9,703 $ ( 9,703 ) $ 1,290,554 Balance at December 31, 2023 (6) 22,235 $ 10,823 $ 749,356 $ 488,663 $ ( 2,738 ) $ 9,050 $ ( 9,050 ) $ 1,246,104 Net income — — — 64,439 — — — 64,439 Other comprehensive income — — — — 1,162 — — 1,162 Dividends declared ($ 1.230 per share) — — — ( 27,577 ) — — — ( 27,577 ) Issuance under various plans (3) 28 13 2,879 — — — — 2,892 Share-based compensation and tax benefit (4) (5) 36 18 3,516 — — — — 3,534 Treasury stock activities (2) — — — — — 653 ( 653 ) — Balance at June 30, 2024 22,299 $ 10,854 $ 755,751 $ 525,525 $ ( 1,576 ) $ 9,703 $ ( 9,703 ) $ 1,290,554 (1) 2.0 million shares of preferred stock at $ 0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the Condensed Consolidated Statements of Stockholders’ Equity. (2) Includes 113 thousand, 108 thousand, 110 thousand, and 108 thousand shares at June 30, 2024, December 31, 2023, June 30, 2023 and December 31, 2022, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan. (3) Includes shares issued under the Retirement Savings Plan and DRIP and/or ATM 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 six months ended June 30, 2024 and 2023, we withheld 14 thousand and 20 thousand shares, respectively, for employee taxes. (6) Includes 4.4 million shares issued during 2023 related to the acquisition of FCG. See Notes 3 and 9 for details associated with the FCG acquisition and related financing. 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, 2023. 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. Recent Accounting Standards Yet to be Adopted 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. ASU 2023-07 will be effective 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, will not have a material 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 have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2024. ASU 2023-09 only impacts disclosures, and as a result, will not have a material 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. At this time, it is uncertain when the review will be completed, the final outcome of the review, and the ultimate disclosure requirements. 7 Table of Contents 2. Calculation of Earnings Per Share Three Months Ended Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands, except per share data) Calculation of Basic Earnings Per Share: Net Income $ 18,271 $ 16,133 $ 64,439 $ 52,477 Weighted average shares outstanding (1) 22,284 17,794 22,267 17,777 Basic Earnings Per Share $ 0.82 $ 0.91 $ 2.89 $ 2.95 Calculation of Diluted Earnings Per Share: Net Income $ 18,271 $ 16,133 $ 64,439 $ 52,477 Reconciliation of Denominator: Weighted shares outstanding—Basic (1) 22,284 17,794 22,267 17,777 Effect of dilutive securities—Share-based compensation 51 58 53 65 Adjusted denominator—Diluted 22,335 17,852 22,320 17,842 Diluted Earnings Per Share $ 0.82 $ 0.90 $ 2.89 $ 2.94 (1) Weighted average shares for the three and six months ended June 30, 2024 reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 3 and 9 for additional details on the acquisition and related equity offering. 3. Acquisitions Acquisition of Florida City Gas On November 30, 2023, we completed the acquisition of FCG for $ 922.8 million in cash, which included 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. FCG serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe. 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 14, Long-Term Debt , and Note 9, Stockholders' Equity, for additional details on these financing activities . We accounted for the acquisition of FCG using the acquisition method. As FCG is a regulated utility, the measurement of the fair value of most of the assets acquired and liabilities assumed were determined using the predecessor’s carrying value. In certain other instances where assets and liabilities are not subject to regulation, we determined the fair value in accordance with the principles of ASC Topic 820, Fair Value Measurements. The excess of the purchase price for FCG over the fair value of the assets acquired and liabilities assumed has been reflected as goodwill within the Regulated Energy segment. Goodwill resulting from the acquisition is 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. The components of the preliminary purchase price allocation are as follows: 8 Table of Contents (in thousands) Assets acquired: Acquisition Date Fair Value Cash $ 2,261 Accounts receivable, net 14,138 Regulatory assets - current 2,983 Other current assets 2,082 Property, plant and equipment 454,410 Goodwill 460,875 Regulatory assets - non-current 3,381 Other deferred charges and other assets 18,309 Total assets acquired 958,439 Liabilities assumed: Current liabilities ( 20,934 ) Regulatory liabilities ( 14,137 ) Other deferred credits and other liabilities ( 548 ) Total liabilities assumed ( 35,619 ) Net purchase price $ 922,820 Direct transaction costs of $ 10.4 million associated with the FCG acquisition were reflected in “FCG transaction-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 three and six months ended June 30, 2024, the Company’s consolidated results include $ 32.5 million and $ 68.4 million of operating revenue, respectively, and $ 1.9 million and $ 6.0 million of net income, respectively, attributable to FCG. These results include $ 1.4 million and $ 2.3 million of transaction and transition-related expenses, respectively, for the three and six months ended June 30, 2024. Acquisition of J.T. Lee and Son's In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $ 3.9 million. In connection with this acquisition, we recorded a $ 0.3 million liability which is subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Through this acquisition, we expanded our operating footprint in North Carolina, where customers are served by Diversified Energy. Sharp added approximately 3,000 customers and distribution of approximately 800,000 gallons of propane annually. The transaction also included a bulk plant with 60,000 gallons of propane storage, enabling the Company to realize efficiencies with additional storage capacity and overlapping delivery territories. In connection with this acquisition, we recorded $ 2.7 million in property plant and equipment, $ 0.9 million in goodwill, $ 0.2 million in working capital, and less than $ 0.1 million in intangible assets associated primarily with non-compete agreements, all of which are deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the three and six months ended June 30, 2024. 9 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 and six months ended June 30, 2024 and 2023: Three Months Ended June 30, 2024 Three Months Ended June 30, 2023 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 13,404 $ — $ — $ 13,404 $ 14,109 $ — $ — $ 14,109 Florida natural gas distribution 39,917 — — 39,917 40,766 — — 40,766 Florida City Gas 32,494 — — 32,494 — — — — FPU electric distribution 22,546 — — 22,546 23,034 — — 23,034 Maryland natural gas division 4,681 — — 4,681 4,622 — — 4,622 Sandpiper natural gas/propane operations 3,898 — — 3,898 4,079 — — 4,079 Elkton Gas 1,308 — — 1,308 1,303 — — 1,303 Total energy distribution 118,248 — — 118,248 87,913 — — 87,913 Energy transmission Aspire Energy — 5,331 — 5,331 — 5,726 — 5,726 Aspire Energy Express 368 — — 368 369 — — 369 Eastern Shore 19,860 — — 19,860 19,632 — — 19,632 Peninsula Pipeline 8,069 — — 8,069 7,593 — — 7,593 Total energy transmission 28,297 5,331 — 33,628 27,594 5,726 — 33,320 Energy generation Eight Flags — 4,464 — 4,464 — 4,532 — 4,532 Propane operations Propane delivery operations — 28,040 — 28,040 — 27,315 — 27,315 Compressed Natural Gas Services Marlin Gas Services — 3,647 — 3,647 — 3,238 — 3,238 Other and eliminations Eliminations ( 15,920 ) ( 63 ) ( 5,818 ) ( 21,801 ) ( 14,366 ) ( 60 ) ( 6,344 ) ( 20,770 ) Other — 46 46 — — 45 45 Total other and eliminations ( 15,920 ) ( 63 ) ( 5,772 ) ( 21,755 ) ( 14,366 ) ( 60 ) ( 6,299 ) ( 20,725 ) Total operating revenues (1) $ 130,625 $ 41,419 $ ( 5,772 ) $ 166,272 $ 101,141 $ 40,751 $ ( 6,299 ) $ 135,593 (1 ) Total operating revenues for the three months ended June 30, 2024 include other revenue (revenues from sources other than contracts with customers) of $ 0.1 million for both our Regulated and Unregulated Energy segments, and $ 0.2 million and $ 0.1 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2023. 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. 10 Table of Contents Six Months Ended June 30, 2024 Six Months Ended June 30, 2023 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 45,321 $ — $ — $ 45,321 $ 51,016 $ — $ — $ 51,016 Florida natural gas distribution 87,873 — — 87,873 87,124 — — 87,124 Florida City Gas 68,371 — — 68,371 — — — — FPU electric distribution 42,510 — — 42,510 45,771 — — 45,771 Maryland natural gas division 14,536 — — 14,536 16,884 — — 16,884 Sandpiper natural gas/propane operations 10,955 — — 10,955 11,161 — — 11,161 Elkton Gas 4,167 — — 4,167 5,444 — — 5,444 Total energy distribution 273,733 — — 273,733 217,400 — — 217,400 Energy transmission Aspire Energy — 18,939 — 18,939 — 19,680 — 19,680 Aspire Energy Express 737 — — 737 733 — — 733 Eastern Shore 41,126 — — 41,126 40,302 — — 40,302 Peninsula Pipeline 16,061 — — 16,061 14,504 — — 14,504 Total energy transmission 57,924 18,939 — 76,863 55,539 19,680 — 75,219 Energy generation Eight Flags — 9,019 — 9,019 — 9,832 — 9,832 Propane operations Propane delivery operations — 89,612 — 89,612 — 87,295 — 87,295 Compressed Natural Gas Services Marlin Gas Services — 7,075 — 7,075 — 7,238 — 7,238 Other and eliminations Eliminations ( 32,606 ) ( 123 ) ( 11,648 ) ( 44,377 ) ( 29,528 ) ( 129 ) ( 13,696 ) ( 43,353 ) Other — 91 91 — — 91 91 Total other and eliminations ( 32,606 ) ( 123 ) ( 11,557 ) ( 44,286 ) ( 29,528 ) ( 129 ) ( 13,605 ) ( 43,262 ) Total operating revenues (1) $ 299,051 $ 124,522 $ ( 11,557 ) $ 412,016 $ 243,411 $ 123,916 $ ( 13,605 ) $ 353,722 (1) Total operating revenues for the six months ended June 30, 2024 include other revenue (revenues from sources other than contracts with customers) of $ 0.7 million and $ 0.2 million for our Regulated and Unregulated Energy segments, respectively, and $ 0.8 million and $ 0.2 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2023. 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 . 11 Table of Contents Contract Balances The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2024 and December 31, 2023 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Non-current) Contract Liabilities (Current) (in thousands) Balance at 12/31/2023 $ 67,741 $ 18 $ 3,524 $ 1,022 Balance at 6/30/2024 50,022 18 3,258 619 Increase (Decrease) $ ( 17,719 ) $ — $ ( 266 ) $ ( 403 ) Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in receivables and other deferred charges in the condensed consolidated balance sheet 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 and six months ended June 30, 2024 and 2023, 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 June 30, 2024, are expected to be recognized as follows: (in thousands) 2024 2025 2026 2027 2028 2029 2030 and thereafter Eastern Shore and Peninsula Pipeline $ 18,267 $ 32,610 $ 28,791 $ 25,578 $ 23,499 $ 21,294 $ 125,881 Natural gas distribution operations 5,073 9,500 8,785 6,756 5,536 4,992 26,311 FPU electric distribution 375 749 364 364 364 — — Total revenue contracts with remaining performance obligations $ 23,715 $ 42,859 $ 37,940 $ 32,698 $ 29,399 $ 26,286 $ 152,192 12 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 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 was the first in the state and included four programs including, Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and a standard Offer Program in which customers can participate and allow for recovery. The evidentiary hearing on this matter was held in April 2024 with all programs, with the exception of the Offer Program, approved by the PSC and rates became effective May 1, 2024. Delaware Natural Gas Rate Case: In May 2024, our Delaware natural gas division provided notice to the Delaware PSC of its intent to file a petition seeking a general rate base increase based on a test period ending in December 2024. The filing is expected to be submitted to the Delaware PSC in August 2024 and the outcome of the application will be subject to review and approval by the Delaware PSC. 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 are seeking approval of the following: (i) permanent rate relief of approximately $ 6.9 million; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. The outcome of the application is subject to review and approval by the Maryland PSC. Rate changes are suspended until December 2024. 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 which will include an annual benefit of $ 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 project enables us to meet the significant growing demand for service in Yulee, Florida. The agreement enables us 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. The petition was approved by the Florida PSC in November 2022. 13 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 Commission 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. On June 23, 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied on September 12, 2023. On July 7, 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief on January 31, 2024 with answer briefs filed on April 30, 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 return on equity ("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. For the three and six months ended June 30, 2024, the Company recorded decreases to asset removal costs and depreciation expense of $ 2.3 million and $ 5.7 million, respectively, as a result of the RSAM adjustment. 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 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. The Commission voted to approve the projections in November 2023. FPU projects to spend $ 13.6 million on the program in 2024. 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 Commission 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. If approved, these efforts will serve to improve the safety and reliability of service to FCG's customers. These modifications, if approved, will result in an estimated additional $ 50.0 million in capital expenditures associated with the SAFE Program which would increase the total projected capital expenditures to $ 255.0 million over a 10-year period. The Commission decision is expected 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 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 14 Table of Contents 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. The Company began the conversions of the community gas systems 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 first and second quarters of 2025 for Boynton Beach and New Smyrna 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. Completion of the projects is projected for the fourth quarter of 2024 for Plant City and the fourth quarter of 2025 for Lake Mattie. 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 it's 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 its 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 its 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. FPU Electric Rate Case : In June 2024, our Florida Electric division provided notice to the Florida PSC of its intent to file a petition seeking a general rate base increase based on a 2025 projected test year. The filing is expected to be submitted to the Florida PSC in August 2024 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. Eastern Shore has requested certificate authorization by December 2024, with a target in-service date by the third quarter of 2025. In December 2023, the FERC issued its schedule for preparation of the Environmental Assessment ("EA"). In 15 Table of Contents April 2024, the FERC issued their EA with no significant impacts noted. The EA comment period closed May 28, 2024, and Eastern Shore responded to the one adverse comment received. TCJA In connection with the TCJA, which was signed into law in December 2017, our 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 $ 85.2 million and $ 85.8 million at June 30, 2024 and December 31, 2023, 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 June 30, 2024 and December 31, 2023, we had approximately $ 3.4 million and $ 3.6 million, respectively, in environmental liabilities related to the former MGP sites, and related regulatory assets of approximately $ 0.3 million and $ 0.5 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 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 parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the west parcel, 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 $ 3.3 million and $ 5.7 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 as of April 1, 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 16 Table of Contents 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 based on specific financial ratios. 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 ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2024, 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 June 30, 2024 was $ 35.0 million. The aggregate amount guaranteed related to our subsidiaries at June 30, 2024 was $ 27.0 million with the guarantees expiring on various dates through June 2025. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at June 30, 2024 was $ 4.0 million. As of June 30, 2024, we have issued letters of credit totaling $ 7.0 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 2025 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 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. 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 Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. 17 Table of Contents The following tables present financial information about our reportable segments: Three Months Ended Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy $ 127,000 $ 100,657 $ 294,927 $ 242,279 Unregulated Energy 39,272 34,936 117,089 111,443 Total operating revenues, unaffiliated customers $ 166,272 $ 135,593 $ 412,016 $ 353,722 Intersegment Revenues (1) Regulated Energy $ 3,625 $ 484 $ 4,124 $ 1,132 Unregulated Energy 2,147 5,816 7,433 12,473 Other businesses 46 45 91 91 Total intersegment revenues $ 5,818 $ 6,345 $ 11,648 $ 13,696 Operating Income (Loss) Regulated Energy $ 40,505 $ 29,291 $ 98,614 $ 66,916 Unregulated Energy 238 ( 993 ) 21,667 16,252 Other businesses and eliminations 47 48 94 93 Operating income 40,790 28,346 120,375 83,261 Other income, net 1,110 831 1,305 1,107 Interest charges 16,813 6,964 33,839 14,196 Income Before Income Taxes 25,087 22,213 87,841 70,172 Income taxes 6,816 6,080 23,402 17,695 Net Income $ 18,271 $ 16,133 $ 64,439 $ 52,477 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) June 30, 2024 December 31, 2023 Identifiable Assets Regulated Energy segment $ 2,882,798 $ 2,781,581 Unregulated Energy segment 447,913 477,402 Other businesses and eliminations 50,042 45,721 Total Identifiable Assets $ 3,380,753 $ 3,304,704 18 Table of Contents 9. Stockholders' Equity Common Stock Issuances In November 2023, in connection with our acquisition of FCG, we completed an equity offering resulting in the issuance of approximately 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 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. For the six months ended June 30, 2024, we received net proceeds of $ 2.5 million for issuances under the DRIP. There were no issuances under the DRIP during 2023. Our most recent ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $ 75.0 million, expired in June 2023. 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 as of June 30, 2024 and 2023. 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 thousands) As of December 31, 2023 $ ( 2,584 ) $ ( 274 ) $ 120 $ ( 2,738 ) Other comprehensive income before reclassifications — 1,640 511 2,151 Amounts reclassified from accumulated other comprehensive income (loss) 27 ( 761 ) ( 255 ) ( 989 ) Net current-period other comprehensive income (loss) 27 879 256 1,162 As of June 30, 2024 $ ( 2,557 ) $ 605 $ 376 $ ( 1,576 ) As of December 31, 2022 $ ( 2,506 ) $ 1,092 $ 35 $ ( 1,379 ) Other comprehensive income (loss) before reclassifications — ( 2,045 ) 612 ( 1,433 ) Amounts reclassified from accumulated other comprehensive income (loss) 21 ( 126 ) ( 142 ) ( 247 ) Net prior-period other comprehensive income (loss) 21 ( 2,171 ) 470 ( 1,680 ) As of June 30, 2023 $ ( 2,485 ) $ ( 1,079 ) $ 505 $ ( 3,059 ) 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. 19 Table of Contents 10. Employee Benefit Plans Net periodic (benefit) cost for the FPU Pension Plan for the three and six months ended June 30, 2024 and 2023 is set forth in the following table: Three Months Ended Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands) Interest cost $ 599 $ 633 $ 1,198 $ 1,266 Expected return on plan assets ( 724 ) ( 668 ) ( 1,448 ) ( 1,336 ) Amortization of net loss 69 110 138 220 Total periodic (benefit) cost $ ( 56 ) $ 75 $ ( 112 ) $ 150 Amounts reclassified from accumulated other comprehensive income (loss) and regulatory assets were not material during the three and six months ended June 30, 2024 and 2023. Net periodic benefit costs for our other pension and postretirement benefit plans were not material for the three and six months ended June 30, 2024 and 2023. 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 and six months ended June 30, 2024, there were no contributions to the FPU Pension Plan and we do not expect to contribute to the FPU Pension Plan during 2024. 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 and six months ended June 30, 2024 were immaterial. We expect to pay total cash benefits of less than $ 1.0 million for these other postretirement benefit plans in 2024. 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 sheet, had a fair value of $ 13.6 million at June 30, 2024 and $ 12.3 million at December 31, 2023. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors. 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. 20 Table of Contents The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2024 and 2023: Three Months Ended Six Months Ended June 30, June 30, 2024 2023 2024 2023 (in thousands) Awards to key employees $ 2,181 $ 284 $ 4,080 $ 2,440 Awards to non-employee directors 218 227 432 479 Total compensation expense 2,399 511 4,512 2,919 Less: tax benefit ( 612 ) ( 132 ) ( 1,152 ) ( 754 ) Share-based compensation amounts included in net income $ 1,787 $ 379 $ 3,360 $ 2,165 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 six months ended June 30, 2024: (in thousands, except per share data) Number of Shares Weighted Average Fair Value/Share Outstanding—December 31, 2023 213 $ 117.74 Granted 110 $ 105.21 Vested ( 43 ) $ 103.95 Expired ( 27 ) $ 86.24 Outstanding—June 30, 2024 253 $ 117.89 During the six months ended June 30, 2024, we granted awards of 110 thousand shares of common stock to officers and key employees under the SICP, including awards granted in February 2024. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2026. In March 2024, 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 2024 for the performance period ended December 31, 2023. 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 14 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 $ 1.5 million. At June 30, 2024, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $ 26.9 million. At June 30, 2024, there was approximately $ 12.8 million of unrecognized compensation cost related to these awards, which will be recognized through 2026. Non-employee Directors 21 Table of Contents 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 June 30, 2024, there was $ 0.7 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 June 30, 2024, our natural gas and electric distribution operations did not have any outstanding derivative contracts. Volume of Derivative Activity As of June 30, 2024, 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 10.5 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 June 2024 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. We expect to reclassify unrealized gains of approximately $ 0.7 million from accumulated other comprehensive income (loss) related to our commodity cash flow hedges to earnings during the 12 -month period ended June 30, 2025. 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 July 2024, we entered into an agreement for an additional interest rate swap effective August 1, 2024 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. 22 Table of Contents 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 sheet with a balance of $ 2.8 million and $ 2.1 million as of June 30, 2024 and December 31, 2023, 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 June 30, 2024 and December 31, 2023, are as follows: Derivative Assets Fair Value As Of (in thousands) Balance Sheet Location June 30, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value $ 866 $ 702 Interest rate swap agreements Derivative assets, at fair value 506 365 Total Derivative Assets (1) $ 1,372 $ 1,067 (1) Derivative assets, at fair value, include $ 1.2 million in current assets in the condensed consolidated balance sheet at June 30, 2024 and $ 1.0 million at December 31, 2023, with the remainder of the balance classified as long-term . Derivative Liabilities Fair Value As Of (in thousands) Balance Sheet Location June 30, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value $ 39 $ 1,078 Interest rate swap agreements Derivative liabilities, at fair value — 203 Total Derivative Liabilities (1) $ 39 $ 1,281 (1) Derivative liabilities, at fair value, included less than $ 0.1 million in current liabilities in the condensed consolidated balance sheet at June 30, 2024 and $ 0.4 million at December 31, 2023, with the remainder of the balance classified as long-term. 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 June 30, For the Six Months Ended June 30, (in thousands) (Loss) on Derivatives 2024 2023 2024 2023 Derivatives designated as cash flow hedges Propane swap agreements Revenues $ — $ — $ ( 307 ) $ 733 Propane swap agreements Unregulated propane and natural gas costs ( 41 ) ( 432 ) 1,350 ( 559 ) Interest rate swap agreements Interest expense 170 127 342 192 Total $ 129 $ ( 305 ) $ 1,385 $ 366 23 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 June 30, 2024 and December 31, 2023: Fair Value Measurements Using: As of June 30, 2024 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 1,395 — — 1,395 Investments—mutual funds and other 12,204 12,204 — — Total investments 13,620 12,225 — 1,395 Derivative assets 1,372 — 1,372 — Total assets $ 14,992 $ 12,225 $ 1,372 $ 1,395 Liabilities: Derivative liabilities $ 39 $ — $ 39 $ — 24 Table of Contents Fair Value Measurements Using: As of December 31, 2023 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 1,489 — — 1,489 Investments—mutual funds and other 10,772 10,772 — — Total investments 12,282 10,793 — 1,489 Derivative assets 1,067 — 1,067 — Total assets $ 13,349 $ 10,793 $ 1,067 $ 1,489 Liabilities: Derivative liabilities $ 1,281 $ — $ 1,281 $ — The changes in the fair value of Level 3 investments for the six months ended June 30, 2024 and 2023 were not material. Investment income from the Level 3 investments is reflected in other income, net in the condensed consolidated statements of income. At June 30, 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 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 June 30, 2024, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $ 1.2 billion, compared to the estimated fair value of approximately $ 1.1 billion. At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $ 1.2 billion, compared to a fair value of approximately $ 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. 25 Table of Contents 14. Long-Term Debt Our outstanding long-term debt is shown below: June 30, December 31, (in thousands) 2024 2023 Uncollateralized senior notes: 5.68% notes, due June 2026 $ 5,800 $ 8,700 6.39% notes, due December 2026 100,000 100,000 6.44% notes, due December 2027 100,000 100,000 6.43% notes, due May 2028 2,800 3,500 3.73% notes, due December 2028 10,000 10,000 6.45% notes, due December 2028 100,000 100,000 3.88% notes, due May 2029 25,000 30,000 6.62% notes, due December 2030 100,000 100,000 3.25% notes, due April 2032 56,000 59,500 6.71% notes, due December 2033 100,000 100,000 2.98% notes, due December 2034 70,000 70,000 3.00% notes, due July 2035 50,000 50,000 2.96% notes, due August 2035 40,000 40,000 2.49% notes, due January 2037 50,000 50,000 5.43% notes, due March 2038 80,000 80,000 3.48% notes, due May 2038 50,000 50,000 3.58% notes, due November 2038 50,000 50,000 6.73% notes, due December 2038 50,000 50,000 3.98% notes, due August 2039 100,000 100,000 2.95% notes, due March 2042 50,000 50,000 Equipment security note 2.46% note, due September 2031 7,259 7,633 Less: debt issuance costs ( 3,505 ) ( 3,753 ) Total long-term debt 1,193,354 1,205,580 Less: current maturities ( 18,592 ) ( 18,505 ) Total long-term debt, net of current maturities $ 1,174,762 $ 1,187,075 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 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 which closed during the fourth quarter of 2023. These notes have varying final 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. On March 14, 2023 we issued 5.43 percent Senior Notes due in March 2038 in the aggregate principal amount of $ 80.0 million and used the proceeds received from the issuances of the Senior Notes 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 an annual principal payment beginning in the sixth year after the issuance. 26 Table of Contents 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 June 30, 2024, a total of $ 255.0 million of borrowing capacity was available under these agreements. 15. Short-Term Borrowings As of June 30, 2024, we are authorized by our Board of Directors to borrow up to $ 375.0 million of short-term debt, as required. At June 30, 2024 and December 31, 2023, we had $ 207.1 million and $ 179.9 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.95 percent and 5.83 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at June 30, 2024. In August 2024, we amended and restated our Revolver which increased the total borrowing capacity 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. Borrowings under both tranches of the amended and restated 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. As of June 30, 2024, the pricing under the 364-day tranche of the Revolver included a commitment fee of 10 -basis points on undrawn amounts and an interest rate of 80 -basis points over SOFR plus a 10 -basis point SOFR adjustment on outstanding balances. As of June 30, 2024, the pricing under the five-year tranche of the Revolver included a commitment fee of 10 -basis points on undrawn amounts and an interest rate of 100 -basis points over SOFR plus a 10 -basis point SOFR adjustment on outstanding balances. 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 as described above. As of June 30, 2024, we were in compliance with this covenant. Our total available credit under the Revolver at June 30, 2024 was $ 163.0 million. As of June 30, 2024, we had issued $ 7.0 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. In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $ 965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 3, Acquisitions, Note 9, Stockholders Equity , and Note 14, Long-Term Debt . 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 27 Table of Contents 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 June 30, 2024, 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 June 30, 2024, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our condensed consolidated statements of income: Three Months Ended Six Months Ended June 30, June 30, (in thousands) Classification 2024 2023 2024 2023 Operating lease cost (1) Operations expense $ 738 $ 780 $ 1,474 $ 1,568 (1) Includes short-term leases and variable lease costs, which are not material . The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheet at June 30, 2024 and December 31, 2023: (in thousands) Balance sheet classification June 30, 2024 December 31, 2023 Assets Operating lease assets Operating lease right-of-use assets $ 11,201 $ 12,426 Liabilities Current Operating lease liabilities Other accrued liabilities $ 2,453 $ 2,454 Noncurrent Operating lease liabilities Operating lease - liabilities 9,341 10,550 Total lease liabilities $ 11,794 $ 13,004 28 Table of Contents The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating leases at June 30, 2024 and December 31, 2023: June 30, 2024 December 31, 2023 Weighted-average remaining lease term ( in years ) Operating leases 7.9 8.1 Weighted-average discount rate Operating leases 3.5 % 3.5 % The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2024 and 2023: Six Months Ended June 30, (in thousands) 2024 2023 Operating cash flows from operating leases $ 1,469 $ 1,465 The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2024 and for each of the next five years and thereafter: (in thousands) Operating Leases (1) Remainder of 2024 $ 1,416 2025 2,334 2026 1,777 2027 1,541 2028 1,164 2029 1,099 Thereafter 4,094 Total lease payments 13,425 Less: Interest ( 1,631 ) Present value of lease liabilities $ 11,794 (1) Operating lease payments include $ 2.1 million related to options to extend lease terms that are reasonably certain of being exercised. 29 Table of Contents