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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
W ASHINGTON, D.C. 20549

FORM | 10-Q

☒ | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: September 30, 2025
OR

☐ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to
Commission File Number: 001-11590

C HESAPEAKE U TILITIES C ORPORATION (Exact name of registrant as specified in its charter)

Delaware |  | 51-0064146
(State or other jurisdiction of incorporation or organization) |  | (I.R.S. Employer Identification No.)

500 Energy Lane, Dover, Delaware 19901
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:

Title of each class | Trading Symbol(s) | Name of each exchange on which registered
Common Stock - par value per share $0.4867 | CPK | New York Stock Exchange, Inc.

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer |  | ☒ |  | Accelerated filer |  | ☐
Non-accelerated filer |  | ☐ |  | Smaller reporting company |  | ☐
|  |  |  | Emerging growth company |  | ☐

Table of Contents
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒
Common Stock, par value $0.4867 — 23,650,684 shares outstanding as of November 3, 2025.

Table of Contents
Table of Contents

PART I—FINANCIAL INFORMATION | 1
I TEM 1. | FINANCIAL STATEMENTS | 1
I TEM 2. | MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS | 31
I TEM 3. | QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 61
I TEM 4. | CONTROLS AND PROCEDURES | 62
PART II—OTHER INFORMATION | 62
I TEM 1. | LEGAL PROCEEDINGS | 62
I TEM 1 A. | RISK FACTORS | 62
I TEM 2. | UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS | 63
I TEM 3. | DEFAULTS UPON SENIOR SECURITIES | 63
I TEM 5. | OTHER INFORMATION | 63
I TEM 6. | EXHIBITS | 64
SIGNATURES | 65

Table of Contents
G LOSSARY OF D EFINITIONS
ASC: Accounting Standards Codification issued by the FASB
Adjusted Gross Margin: A non-GAAP measure calculated by deducting the purchased cost of natural gas, propane and electricity and the cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Adjusted Gross Margin exclude depreciation and amortization and certain costs presented in operations and maintenance expenses in accordance with regulatory requirements
Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities
Aspire Energy Express: Aspire Energy Express, LLC, a wholly-owned subsidiary of Chesapeake Utilities
ASU: Accounting Standards Update issued by the FASB
ATM: At-the-market
BOD: Chesapeake Utilities Corporation's Board of Directors
CDD: Cooling degree-day
Chesapeake, Chesapeake Utilities or Company: Chesapeake Utilities Corporation, individually or collectively with its divisions and subsidiaries, as appropriate in the context of the disclosure
CHP: Combined Heat and Power Plant
CNG: Compressed natural gas
Degree-day: Measure of the variation in the weather based on the extent to which the average daily temperature reaches above (CDD) or below (HDD) 65 degrees Fahrenheit
Delmarva Peninsula: A peninsula on the east coast of the U.S. comprised of Delaware and portions of Maryland and Virginia
DRIP: Dividend Reinvestment and Direct Stock Purchase Plan
Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value
Dts/d: Dekatherms per day
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake Utilities
Eight Flags: Eight Flags Energy, LLC, a wholly-owned subsidiary of Chesapeake Utilities
Elkton Gas: Elkton Gas Company, a wholly-owned subsidiary of Chesapeake Utilities
FASB: Financial Accounting Standards Board
FCG or Florida City Gas: Pivotal Utility Holdings, Inc, doing business as Florida City Gas, a wholly-owned subsidiary of Chesapeake Utilities that was acquired from Florida Power & Light Company on November 30, 2023
FERC: Federal Energy Regulatory Commission
FGT: Florida Gas Transmission Company
Florida Natural Gas: Refers to the Company's legacy Florida natural gas distribution operations (excluding FCG) that were consolidated under FPU, for both rate-making and operations purposes
Florida OPC: The Office of Public Counsel, an agency established by the Florida legislature who advocates on behalf of Florida's utility consumers prior to actions or rule changes
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities
GAAP: Generally Accepted Accounting Principles
Gross Margin: a term which is the excess of sales over costs of goods sold

Table of Contents
GUARD: Gas Utility Access and Replacement Directive, a PSC approved capital infrastructure program to enhance the safety, reliability and accessibility of portions of FPU’s natural gas distribution system in Florida
Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU
HDD: Heating degree-day
LNG: Liquefied natural gas
Marlin Gas Services: Marlin Gas Services, LLC, a wholly-owned subsidiary of Chesapeake Utilities
Maryland OPC: The Office of People’s Counsel, an agency established by the Maryland legislature who advocates on behalf of Maryland's utility consumers prior to actions or rule changes
MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we have previously issued Senior Notes and which is a party to the current MetLife Shelf Agreement, as amended
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake Utilities
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have previously issued Senior Notes and which is a party to the current Prudential Shelf Agreement, as amended
PSC: Public Service Commission, which is the state agency that regulates utility rates and/or services in certain of our jurisdictions
Revolver: Our $450.0 million unsecured revolving credit facility with certain lenders
RNG: Renewable natural gas
ROE: Return on equity
RSAM: Reserve surplus amortization mechanism which has been approved by the Florida PSC and is applicable to FCG
Sandpiper Energy: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities
SAFE: Safety, Access, and Facility Enhancement, a program to enhance the safety, reliability and accessibility of portions of FCG's natural gas distribution system
SEC: Securities and Exchange Commission
Senior Notes or Uncollateralized Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
Sharp: Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities
Shelf Agreement: An agreement entered into by Chesapeake Utilities and a counterparty pursuant to which Chesapeake Utilities may request that the counterparty purchase our unsecured senior debt with a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance
SICP: Stock and Incentive Compensation Plan pursuant to which we grant stock-based compensation awards
SOFR: Secured Overnight Financing Rate, a secured interbank overnight interest rate established as an alternative to LIBOR
TCJA: Tax Cuts and Jobs Act enacted on December 22, 2017
U.S.: The United States of America

Table of Contents
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(in millions, except shares (thousands) and per share data) |  |  |  |  |  |  |  |
Operating Revenues |  |  |  |  |  |  |  |
Regulated Energy |  | $ | 146.4 |  |  | $ | 130.6 |  |  | $ | 497.8 |  |  | $ | 429.7 |
Unregulated Energy |  | 40.7 |  |  | 35.6 |  |  | 195.3 |  |  | 160.1 |
Other Businesses and Eliminations |  | (7.5) |  |  | (6.0) |  |  | (22.0) |  |  | (17.6) |
Total Operating Revenues |  | 179.6 |  |  | 160.2 |  |  | 671.1 |  |  | 572.2 |
Operating Expenses |  |  |  |  |  |  |  |
Regulated natural gas and electric costs |  | 31.7 |  |  | 28.4 |  |  | 137.3 |  |  | 105.7 |
Unregulated propane and natural gas costs |  | 10.7 |  |  | 9.8 |  |  | 71.4 |  |  | 53.4 |
Operations |  | 53.6 |  |  | 49.5 |  |  | 166.5 |  |  | 153.4 |
Maintenance |  | 6.1 |  |  | 5.1 |  |  | 17.5 |  |  | 16.6 |
Depreciation and amortization |  | 23.3 |  |  | 16.8 |  |  | 67.7 |  |  | 51.7 |
Other taxes |  | 9.0 |  |  | 8.9 |  |  | 27.6 |  |  | 27.0 |
FCG transaction and transition-related expenses |  | 0.2 |  |  | 0.8 |  |  | 1.0 |  |  | 3.1 |
Total Operating Expenses |  | 134.6 |  |  | 119.3 |  |  | 489.0 |  |  | 410.9 |
Operating Income |  | 45.0 |  |  | 40.9 |  |  | 182.1 |  |  | 161.3 |
Other income, net |  | 0.2 |  |  | 0.5 |  |  | 1.2 |  |  | 1.7 |
Interest charges |  | 18.2 |  |  | 17.1 |  |  | 54.1 |  |  | 50.9 |
Income Before Income Taxes |  | 27.0 |  |  | 24.3 |  |  | 129.2 |  |  | 112.1 |
Income taxes |  | 7.6 |  |  | 6.8 |  |  | 35.0 |  |  | 30.2 |
Net Income |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 94.2 |  |  | $ | 81.9 |
Weighted Average Common Shares Outstanding: |  |  |  |  |  |  |  |
Basic |  | 23,526 |  |  | 22,501 |  |  | 23,265 |  |  | 22,346 |
Diluted |  | 23,629 |  |  | 22,564 |  |  | 23,360 |  |  | 22,402 |
Earnings Per Share of Common Stock: |  |  |  |  |  |  |  |
Basic |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 4.05 |  |  | $ | 3.67 |
Diluted |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 4.03 |  |  | $ | 3.66 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(in millions) |  |  |  |  |  |  |  |
Net Income |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 94.2 |  |  | $ | 81.9 |
Other Comprehensive Income (Loss), net of tax: |  |  |  |  |  |  |  |
Cash Flow Hedges, net of tax: |  |  |  |  |  |  |  |
Net gain (loss) on commodity contract cash flow hedges, net of tax of $(0.2), $(0.1), $(0.1) and $0.5, respectively |  | (0.4) |  |  | (0.6) |  |  | — |  |  | 1.0 |
Reclassifications of net (gain) loss on commodity contract cash flow hedges, net of tax $0.0, $0.0, $(0.2) and $(0.4), respectively |  | 0.1 |  |  | 0.1 |  |  | (0.5) |  |  | (0.6) |
Net loss on interest rate swap cash flow hedges, net of tax of $(0.1), $(0.6), $(0.3) and $(0.4), respectively |  | (0.1) |  |  | (1.8) |  |  | (0.8) |  |  | (1.3) |
Reclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $(0.1), $(0.1), $(0.1) and $(0.2), respectively |  | — |  |  | (0.2) |  |  | (0.2) |  |  | (0.4) |
Total Other Comprehensive Loss, net of tax |  | (0.4) |  |  | (2.5) |  |  | (1.5) |  |  | (1.3) |
Comprehensive Income |  | $ | 19.0 |  |  | $ | 15.0 |  |  | $ | 92.7 |  |  | $ | 80.6 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)

Assets |  | September 30, 2025 |  | December 31, 2024
(in millions, except shares and per share data) |  |  |  |
Property, Plant and Equipment |  |  |  |
Regulated Energy |  | $ | 2,848.6 |  |  | $ | 2,661.8 |
Unregulated Energy |  | 481.8 |  |  | 463.7 |
Other Businesses and Eliminations |  | 38.4 |  |  | 29.9 |
Total property, plant and equipment |  | 3,368.8 |  |  | 3,155.4 |
Less: Accumulated depreciation and amortization |  | (617.7) |  |  | (567.6) |
Plus: Construction work in progress |  | 254.4 |  |  | 148.1 |
Net property, plant and equipment |  | 3,005.5 |  |  | 2,735.9 |
Current Assets |  |  |  |
Cash and cash equivalents |  | 1.8 |  |  | 7.9 |
Trade and other receivables |  | 82.3 |  |  | 80.0 |
Less: Allowance for credit losses |  | (4.2) |  |  | (3.3) |
Trade and other receivables, net |  | 78.1 |  |  | 76.7 |
Accrued revenue |  | 25.2 |  |  | 37.8 |
Propane inventory, at average cost |  | 6.7 |  |  | 8.9 |
Other inventory, at average cost |  | 18.2 |  |  | 18.0 |
Regulatory assets |  | 30.0 |  |  | 23.9 |
Storage gas prepayments |  | 5.6 |  |  | 3.8 |
Income taxes receivable |  | 28.7 |  |  | 6.8 |
Prepaid expenses |  | 21.4 |  |  | 17.3 |
Derivative assets, at fair value |  | 0.1 |  |  | 0.6 |
Other current assets |  | 3.0 |  |  | 2.6 |
Total current assets |  | 218.8 |  |  | 204.3 |
Deferred Charges and Other Assets |  |  |  |
Goodwill |  | 507.5 |  |  | 507.7 |
Other intangible assets, net |  | 13.7 |  |  | 15.0 |
Investments, at fair value |  | 16.8 |  |  | 14.4 |
Derivative assets, at fair value |  | — |  |  | 0.1 |
Operating lease right-of-use assets |  | 9.6 |  |  | 10.5 |
Regulatory assets |  | 75.3 |  |  | 77.4 |
Receivables and other deferred charges |  | 14.2 |  |  | 11.7 |
Total deferred charges and other assets |  | 637.1 |  |  | 636.8 |
Total Assets |  | $ | 3,861.4 |  |  | $ | 3,577.0 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities |  | September 30, 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) |  | 11.5 |  |  | 11.1 |
Additional paid-in capital |  | 913.2 |  |  | 830.5 |
Retained earnings |  | 597.2 |  |  | 550.3 |
Accumulated other comprehensive loss |  | (3.2) |  |  | (1.7) |
Deferred compensation obligation |  | 12.5 |  |  | 9.8 |
Treasury stock |  | (12.5) |  |  | (9.8) |
Total stockholders’ equity |  | 1,518.7 |  |  | 1,390.2 |
Long-term debt, net of current maturities |  | 1,437.9 |  |  | 1,261.7 |
Total capitalization |  | 2,956.6 |  |  | 2,651.9 |
Current Liabilities |  |  |  |
Current portion of long-term debt |  | 34.5 |  |  | 25.5 |
Short-term borrowing |  | 95.8 |  |  | 196.5 |
Accounts payable |  | 89.2 |  |  | 78.3 |
Customer deposits and refunds |  | 44.9 |  |  | 45.7 |
Accrued interest |  | 17.4 |  |  | 4.8 |
Dividends payable |  | 16.1 |  |  | 14.7 |
Accrued compensation |  | 12.1 |  |  | 23.9 |
Regulatory liabilities |  | 13.1 |  |  | 16.1 |
Derivative liabilities, at fair value |  | 0.5 |  |  | — |
Other accrued liabilities |  | 27.6 |  |  | 13.9 |
Total current liabilities |  | 351.2 |  |  | 419.4 |
Deferred Credits and Other Liabilities |  |  |  |
Deferred income taxes |  | 338.8 |  |  | 296.1 |
Regulatory liabilities |  | 186.4 |  |  | 184.0 |
Environmental liabilities |  | 2.8 |  |  | 2.2 |
Other pension and benefit costs |  | 15.0 |  |  | 13.2 |
Derivative liabilities, at fair value |  | 1.3 |  |  | 0.1 |
Operating lease - liabilities |  | 8.0 |  |  | 8.7 |
Deferred investment tax credits and other liabilities |  | 1.3 |  |  | 1.4 |
Total deferred credits and other liabilities |  | 553.6 |  |  | 505.7 |
Environmental and other commitments and contingencies (Notes 6 and 7) |  |  |  |
Total Capitalization and Liabilities |  | $ | 3,861.4 |  |  | $ | 3,577.0 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)

|  | Nine Months Ended
|  | September 30,
|  | 2025 |  | 2024
(in millions) |  |  |  |
Operating Activities |  |  |  |
Net income |  | $ | 94.2 |  |  | $ | 81.9 |
Adjustments to reconcile net income to net cash provided by operating activities: |  |  |  |
Depreciation and amortization |  | 67.7 |  |  | 51.7 |
Depreciation and accretion included in other costs |  | 11.7 |  |  | 11.6 |
Deferred income taxes |  | 43.3 |  |  | 30.6 |
Realized loss on commodity contracts and sale of assets |  | (2.2) |  |  | (3.8) |
Unrealized gain on investments and commodity contracts |  | (1.8) |  |  | (1.7) |
Employee benefits and compensation |  | — |  |  | (0.1) |
Share-based compensation |  | 6.0 |  |  | 6.4 |
Other, net |  | — |  |  | (0.2) |
Changes in assets and liabilities: |  |  |  |
Accounts receivable and accrued revenue |  | 11.2 |  |  | 26.3 |
Propane inventory, storage gas and other inventory |  | 0.3 |  |  | 1.7 |
Regulatory assets and liabilities, net |  | (17.0) |  |  | 5.1 |
Prepaid expenses and other current assets |  | (2.7) |  |  | (0.4) |
Accounts payable and other accrued liabilities |  | 10.4 |  |  | 6.5 |
Income taxes receivable |  | (21.9) |  |  | (8.7) |
Customer deposits and refunds |  | (0.8) |  |  | 1.0 |
Accrued compensation |  | (12.3) |  |  | (2.3) |
Accrued interest |  | 12.6 |  |  | 6.8 |
Other assets and liabilities, net |  | (0.4) |  |  | 5.3 |
Net cash provided by operating activities |  | 198.3 |  |  | 217.7 |
Investing Activities |  |  |  |
Property, plant and equipment expenditures |  | (322.2) |  |  | (259.6) |
Proceeds from sale of assets |  | 4.0 |  |  | 3.1 |
Acquisitions, net of cash acquired |  | — |  |  | 0.6 |
Environmental expenditures |  | — |  |  | (0.1) |
Net cash used in investing activities |  | (318.2) |  |  | (256.0) |
Financing Activities |  |  |  |
Common stock dividends |  | (44.8) |  |  | (39.9) |
Proceeds from issuance of common stock, net of expenses |  | 76.1 |  |  | 56.7 |
Tax withholding payments related to net settled stock compensation |  | (1.0) |  |  | (1.5) |
Change in cash overdrafts due to outstanding checks |  | 2.4 |  |  | 1.4 |
Net borrowings (repayments) under line of credit agreements |  | (103.5) |  |  | 32.9 |
Proceeds from issuance of long-term debt |  | 199.1 |  |  | (0.1) |
Repayment of long-term debt and finance lease obligation |  | (14.5) |  |  | (14.5) |
Net cash provided by financing activities |  | 113.8 |  |  | 35.0 |
Net Decrease in Cash and Cash Equivalents |  | (6.1) |  |  | (3.3) |
Cash and Cash Equivalents—Beginning of Period |  | 7.9 |  |  | 4.9 |
Cash and Cash Equivalents—End of Period |  | $ | 1.8 |  |  | $ | 1.6 |

The accompanying notes are an integral part of these condensed consolidated financial statements.
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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 Loss |  | Deferred Compensation |  | Treasury Stock |  | Total
Balance at June 30, 2024 | 22,299 |  |  | $ | 10.9 |  |  | $ | 755.8 |  |  | $ | 525.5 |  |  | $ | (1.6) |  |  | $ | 9.7 |  |  | $ | (9.7) |  |  | $ | 1,290.6 |
Net income | — |  |  | — |  |  | — |  |  | 17.5 |  |  | — |  |  | — |  |  | — |  |  | 17.5 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (2.5) |  |  | — |  |  | — |  |  | (2.5) |
Dividend declared ($0.640 per share) | — |  |  | — |  |  | — |  |  | (14.6) |  |  | — |  |  | — |  |  | — |  |  | (14.6) |
Issuance under various plans (3) | 474 |  |  | 0.2 |  |  | 55.4 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 55.6 |
Share-based compensation and tax benefit (4) (5) | — |  |  | — |  |  | 1.7 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1.7 |
Treasury stock activities | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.1 |  |  | (0.1) |  |  | — |
Balance at September 30, 2024 | 22,773 |  |  | $ | 11.1 |  |  | $ | 812.9 |  |  | $ | 528.4 |  |  | $ | (4.1) |  |  | $ | 9.8 |  |  | $ | (9.8) |  |  | $ | 1,348.3 |
Balance at December 31, 2023 | 22,235 |  |  | $ | 10.8 |  |  | $ | 749.4 |  |  | $ | 488.7 |  |  | $ | (2.8) |  |  | $ | 9.1 |  |  | $ | (9.1) |  |  | $ | 1,246.1 |
Net income | — |  |  | — |  |  | — |  |  | 81.9 |  |  | — |  |  | — |  |  | — |  |  | 81.9 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (1.3) |  |  | — |  |  | — |  |  | (1.3) |
Dividends declared ($1.870 per share) | — |  |  | — |  |  | — |  |  | (42.2) |  |  | — |  |  | — |  |  | — |  |  | (42.2) |
Issuance under various plans (3) | 502 |  |  | 0.3 |  |  | 58.3 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 58.6 |
Share-based compensation and tax benefit (4) (5) | 36 |  |  | — |  |  | 5.2 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 5.2 |
Treasury stock activities (2) | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 0.7 |  |  | (0.7) |  |  | — |
Balance at September 30, 2024 | 22,773 |  |  | $ | 11.1 |  |  | $ | 812.9 |  |  | $ | 528.4 |  |  | $ | (4.1) |  |  | $ | 9.8 |  |  | $ | (9.8) |  |  | $ | 1,348.3 |
Balance at June 30, 2025 | 23,420 |  |  | $ | 11.4 |  |  | $ | 896.4 |  |  | $ | 594.1 |  |  | $ | (2.8) |  |  | $ | 12.5 |  |  | $ | (12.5) |  |  | $ | 1,499.1 |
Net income | — |  |  | — |  |  | — |  |  | 19.4 |  |  | — |  |  | — |  |  | — |  |  | 19.4 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (0.4) |  |  | — |  |  | — |  |  | (0.4) |
Dividend declared ($0.685 per share) | — |  |  | — |  |  | — |  |  | (16.3) |  |  | — |  |  | — |  |  | — |  |  | (16.3) |
Issuance under various plans (3) | 125 |  |  | 0.1 |  |  | 15.1 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 15.2 |
Share-based compensation and tax benefit (4) (5) | 1 |  |  | — |  |  | 1.7 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1.7 |
Balance at September 30, 2025 | 23,546 |  |  | $ | 11.5 |  |  | $ | 913.2 |  |  | $ | 597.2 |  |  | $ | (3.2) |  |  | $ | 12.5 |  |  | $ | (12.5) |  |  | $ | 1,518.7 |
Balance at December 31, 2024 | 22,899 |  |  | $ | 11.1 |  |  | $ | 830.5 |  |  | $ | 550.3 |  |  | $ | (1.7) |  |  | $ | 9.8 |  |  | $ | (9.8) |  |  | $ | 1,390.2 |
Net income | — |  |  | — |  |  | — |  |  | 94.2 |  |  | — |  |  | — |  |  | — |  |  | 94.2 |
Other comprehensive loss | — |  |  | — |  |  | — |  |  | — |  |  | (1.5) |  |  | — |  |  | — |  |  | (1.5) |
Dividends declared ($2.010 per share) | — |  |  | — |  |  | — |  |  | (47.3) |  |  | — |  |  | — |  |  | — |  |  | (47.3) |
Issuance under various plans and ATM program (3) | 611 |  |  | 0.4 |  |  | 76.0 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 76.4 |
Share-based compensation and tax benefit (4) (5) | 36 |  |  | — |  |  | 6.7 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 6.7 |
Treasury stock activities (2) | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2.7 |  |  | (2.7) |  |  | — |
Balance at September 30, 2025 | 23,546 |  |  | $ | 11.5 |  |  | $ | 913.2 |  |  | $ | 597.2 |  |  | $ | (3.2) |  |  | $ | 12.5 |  |  | $ | (12.5) |  |  | $ | 1,518.7 |

(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 128 thousand, 114 thousand, 113 thousand, and 108 thousand shares at September 30, 2025, December 31, 2024, September 30, 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 nine months ended September 30, 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.
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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 an impact on our financial position or results of operations.
Recent Accounting Standards Yet to be Adopted
FASB
Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-03, Disaggregation of Income Statement Expenses, which requires disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-03 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.
Internal-Use Software (ASC 350) - In September 2025, the FASB issued ASU 2025-06, Targeted Improvements to the Accounting for Internal-Use Software. This update, among other changes, eliminates the project stages used in the historical guidance and instead, focuses on a principles-based approach that utilizes management's commitment to the project and the probability of project completion. ASU 2025-06 will be effective for our interim and annual financial statements beginning January 1, 2028. We do not expect ASU 2025-06 to have a material impact on our financial position or results of operation.
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SEC
Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks, and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed that sought review of the final ruling in multiple courts of appeals. In March 2025, the SEC withdrew its defense of the final rule. We will continue to monitor any further developments related to the stay and review process.
Federal Statute Updates
In July 2025, H.R. 1 (referred to as the "One Big Beautiful Bill Act") was signed into law. The comprehensive legislative package contains, among other topics, significant tax law changes and regulatory compliance updates, with various effective dates, including provisions related to limitations of interest expense deductions and the reinstatement of bonus depreciation for qualified property. These provisions of the One Big Beautiful Bill Act have had a positive impact on our income tax provision beginning in the third quarter of 2025, and we continue to evaluate the anticipated impacts to our financial position, results of operations, and/or cash flows on a go-forward basis.
2. Calculation of Earnings Per Share

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(dollars in millions, shares in thousands (except per share data)) |  |  |  |  |  |  |  |
Calculation of Basic Earnings Per Share: |  |  |  |  |  |  |  |
Net Income |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 94.2 |  |  | $ | 81.9 |
Weighted average shares outstanding |  | 23,526 |  |  | 22,501 |  |  | 23,265 |  |  | 22,346 |
Basic Earnings Per Share |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 4.05 |  |  | $ | 3.67 |
Calculation of Diluted Earnings Per Share: |  |  |  |  |  |  |  |
Reconciliation of Denominator: |  |  |  |  |  |  |  |
Weighted shares outstanding—Basic |  | 23,526 |  |  | 22,501 |  |  | 23,265 |  |  | 22,346 |
Effect of dilutive securities—Share-based compensation |  | 103 |  | 63 |  | 95 |  | 56
Adjusted denominator—Diluted |  | 23,629 |  |  | 22,564 |  |  | 23,360 |  |  | 22,402 |
Diluted Earnings Per Share |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 4.03 |  |  | $ | 3.66 |

3. Acquisitions
There were no acquisitions completed during 2024 or during the nine months ended September 30, 2025. The Company’s consolidated results include certain transaction and transition-related expenses for the three and nine months ended September 30, 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.
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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 nine months ended September 30, 2025 and 2024:

|  | Three Months Ended September 30, 2025 |  | Three Months Ended September 30, 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 |  | $ | 10.9 |  |  | $ | — |  |  | $ | — |  |  | $ | 10.9 |  |  | $ | 9.5 |  |  | $ | — |  |  | $ | — |  |  | $ | 9.5 |
Florida natural gas distribution |  | 42.3 |  |  | — |  |  | — |  |  | 42.3 |  |  | 36.9 |  |  | — |  |  | — |  |  | 36.9 |
Florida City Gas |  | 40.8 |  |  | — |  |  | — |  |  | 40.8 |  |  | 33.4 |  |  | — |  |  | — |  |  | 33.4 |
FPU electric distribution |  | 30.7 |  |  | — |  |  | — |  |  | 30.7 |  |  | 29.9 |  |  | — |  |  | — |  |  | 29.9 |
Maryland natural gas (1) |  | 8.6 |  |  | — |  |  | — |  |  | 8.6 |  |  | 8.3 |  |  | — |  |  | — |  |  | 8.3 |
Total energy distribution |  | 133.3 |  |  | — |  |  | — |  |  | 133.3 |  |  | 118.0 |  |  | — |  |  | — |  |  | 118.0 |
Energy transmission |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Aspire Energy |  | — |  |  | 6.0 |  |  | — |  |  | 6.0 |  |  | — |  |  | 4.6 |  |  | — |  |  | 4.6 |
Aspire Energy Express |  | 0.4 |  |  | — |  |  | — |  |  | 0.4 |  |  | 0.4 |  |  | — |  |  | — |  |  | 0.4 |
Eastern Shore |  | 20.7 |  |  | — |  |  | — |  |  | 20.7 |  |  | 19.6 |  |  | — |  |  | — |  |  | 19.6 |
Peninsula Pipeline |  | 14.6 |  |  | — |  |  | — |  |  | 14.6 |  |  | 8.9 |  |  | — |  |  | — |  |  | 8.9 |
Total energy transmission |  | 35.7 |  |  | 6.0 |  |  | — |  |  | 41.7 |  |  | 28.9 |  |  | 4.6 |  |  | — |  |  | 33.5 |
Energy generation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eight Flags |  | — |  |  | 4.9 |  |  | — |  |  | 4.9 |  |  | — |  |  | 4.3 |  |  | — |  |  | 4.3 |
Propane operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Propane delivery operations |  | — |  |  | 22.2 |  |  | — |  |  | 22.2 |  |  | — |  |  | 22.9 |  |  | — |  |  | 22.9 |
CNG / RNG Services |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marlin Gas Services |  | — |  |  | 6.7 |  |  | — |  |  | 6.7 |  |  | — |  |  | 3.8 |  |  | — |  |  | 3.8 |
Other RNG |  | — |  |  | 1.0 |  |  | — |  |  | 1.0 |  |  | — |  |  | 0.1 |  |  | — |  |  | 0.1 |
Total CNG / RNG Services |  | — |  |  | 7.7 |  |  | — |  |  | 7.7 |  |  | — |  |  | 3.9 |  |  | — |  |  | 3.9 |
Other Businesses and Eliminations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eliminations |  | (22.6) |  |  | (0.1) |  |  | (7.5) |  |  | (30.2) |  |  | (16.3) |  |  | (0.1) |  |  | (6.0) |  |  | (22.4) |
Total operating revenues (2) |  | $ | 146.4 |  |  | $ | 40.7 |  |  | $ | (7.5) |  |  | $ | 179.6 |  |  | $ | 130.6 |  |  | $ | 35.6 |  |  | $ | (6.0) |  |  | $ | 160.2 |

(1) In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for rate-making and other purposes and are reflected on a consolidated basis for all periods presented consistent with the final rate order. See Note 5, Rates and Other Regulatory Activities, for additional information.
(2) Total operating revenues for the three months ended September 30, 2025 include other revenue (revenues from sources other than contracts with customers) of $0.1 million and $0.1 million for our Regulated Energy and Unregulated Energy segments, respectively, and $0.2 million and $0.1 million for our Regulated Energy and Unregulated Energy segments for the three months ended September 30, 2024. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland natural gas operations and late fees.
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|  | Nine Months Ended September 30, 2025 |  | Nine Months Ended September 30, 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 |  | $ | 68.7 |  |  | $ | — |  |  | $ | — |  |  | $ | 68.7 |  |  | $ | 54.8 |  |  | $ | — |  |  | $ | — |  |  | $ | 54.8 |
Florida natural gas distribution |  | 140.2 |  |  | — |  |  | — |  |  | 140.2 |  |  | 124.8 |  |  | — |  |  | — |  |  | 124.8 |
Florida City Gas |  | 123.9 |  |  | — |  |  | — |  |  | 123.9 |  |  | 101.8 |  |  | — |  |  | — |  |  | 101.8 |
FPU electric distribution |  | 80.1 |  |  | — |  |  | — |  |  | 80.1 |  |  | 72.4 |  |  | — |  |  | — |  |  | 72.4 |
Maryland natural gas (1) |  | 44.6 |  |  | — |  |  | — |  |  | 44.6 |  |  | 38.0 |  |  | — |  |  | — |  |  | 38.0 |
Total energy distribution |  | 457.5 |  |  | — |  |  | — |  |  | 457.5 |  |  | 391.8 |  |  | — |  |  | — |  |  | 391.8 |
Energy transmission |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Aspire Energy |  | — |  |  | 33.6 |  |  | — |  |  | 33.6 |  |  | — |  |  | 23.5 |  |  | — |  |  | 23.5 |
Aspire Energy Express |  | 1.1 |  |  | — |  |  | — |  |  | 1.1 |  |  | 1.1 |  |  | — |  |  | — |  |  | 1.1 |
Eastern Shore |  | 64.6 |  |  | — |  |  | — |  |  | 64.6 |  |  | 60.7 |  |  | — |  |  | — |  |  | 60.7 |
Peninsula Pipeline |  | 36.4 |  |  | — |  |  | — |  |  | 36.4 |  |  | 25.0 |  |  | — |  |  | — |  |  | 25.0 |
Total energy transmission |  | 102.1 |  |  | 33.6 |  |  | — |  |  | 135.7 |  |  | 86.8 |  |  | 23.5 |  |  | — |  |  | 110.3 |
Energy generation |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eight Flags |  | — |  |  | 14.2 |  |  | — |  |  | 14.2 |  |  | — |  |  | 13.3 |  |  | — |  |  | 13.3 |
Propane operations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Propane delivery operations |  | — |  |  | 123.4 |  |  | — |  |  | 123.4 |  |  | — |  |  | 112.5 |  |  | — |  |  | 112.5 |
CNG / RNG Services |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Marlin Gas Services |  | — |  |  | 21.2 |  |  | — |  |  | 21.2 |  |  | — |  |  | 10.9 |  |  | — |  |  | 10.9 |
Other RNG |  | — |  |  | 3.1 |  |  | — |  |  | 3.1 |  |  | — |  |  | 0.1 |  |  | — |  |  | 0.1 |
Total CNG / RNG Services |  | — |  |  | 24.3 |  |  | — |  |  | 24.3 |  |  | — |  |  | 11.0 |  |  | — |  |  | 11.0 |
Other Businesses and Eliminations |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
Eliminations |  | (61.8) |  |  | (0.2) |  |  | (22.0) |  |  | (84.0) |  |  | (48.9) |  |  | (0.2) |  |  | (17.6) |  |  | (66.7) |
Total operating revenues (2) |  | $ | 497.8 |  |  | $ | 195.3 |  |  | $ | (22.0) |  |  | $ | 671.1 |  |  | $ | 429.7 |  |  | $ | 160.1 |  |  | $ | (17.6) |  |  | $ | 572.2 |

(1) In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for rate-making and other purposes and are reflected on a consolidated basis for all periods presented consistent with the final rate order. See Note 5, Rates and Other Regulatory Activities, for additional information.
(2) Total operating revenues for the nine months ended September 30, 2025 include other revenue (revenues from sources other than contracts with customers) of $0.6 million and $0.3 million for our Regulated Energy and Unregulated Energy segments, respectively, and $0.9 million and $0.3 million for our Regulated Energy and Unregulated Energy segments, respectively, for the nine months ended September 30, 2024. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland natural gas operations and late fees.
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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 September 30, 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 9/30/2025 |  | 69.2 |  |  | — |  |  | 3.0 |  |  | 1.4 |
Increase (Decrease) |  | $ | 3.0 |  |  | $ | — |  |  | $ | — |  |  | $ | 0.2 |

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 and nine months ended September 30, 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 September 30, 2025, are expected to be recognized as follows:

(in millions) | 2025 |  | 2026 |  | 2027 |  | 2028 |  | 2029 |  | 2030 |  | 2031 and thereafter
Eastern Shore and Peninsula Pipeline | $ | 10.7 |  |  | $ | 37.4 |  |  | $ | 33.5 |  |  | $ | 31.1 |  |  | $ | 28.7 |  |  | $ | 22.9 |  |  | $ | 109.9 |
Natural gas distribution operations | 3.6 |  |  | 11.3 |  |  | 9.1 |  |  | 10.0 |  |  | 9.9 |  |  | 9.9 |  |  | 29.1 |
FPU electric distribution | 0.2 |  |  | 1.0 |  |  | 0.6 |  |  | 0.6 |  |  | 0.6 |  |  | — |  |  | — |
Total revenue contracts with remaining performance obligations | $ | 14.5 |  |  | $ | 49.7 |  |  | $ | 43.2 |  |  | $ | 41.7 |  |  | $ | 39.2 |  |  | $ | 32.8 |  |  | $ | 139.0 |

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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 and approved by the Delaware PSC in June 2025 providing an annual revenue increase of $6.1 million, as well as dividing the rate case into two phases. Rates set to recover the approved components of the increase were effective in March 2025. In October 2025, a settlement among the Company, PSC staff and the Delaware Division of the Public Advocate was reached for Phase II of the rate case addressing tariff-related changes including rate design and approved by the Delaware Public Service Commission with rates effective as of October 15, 2025.
Maryland
Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, 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, during which Phase II was approved, including an additional $0.9 million in revenue requirement for a total cumulative increase of $3.5 million. A final order was issued in April 2025 and included approval of the consolidation of the operations and the assets of CUC-Maryland Division, Sandpiper Energy, and Elkton Gas into one entity, which was renamed and operates as Chesapeake Utilities of Maryland, Inc.
Maryland Natural Gas Depreciation Study: In January 2024, the Company's natural gas distribution businesses in Maryland 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.
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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 was recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM 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.
FCG Depreciation Study: 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. The OPC has since filed motions to reconsider and dismiss the docket, which were denied by the Florida PSC in September 2025. At this time, the docket is set for hearing in December 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 related to the SPP. Our Florida electric distribution operation’s initial SPP plan was filed and approved in 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs of $20.4 million for both capital and operating expenses. Our Florida electric distribution operations filed an updated SPP plan in January 2025 which was approved in June 2025, with modifications by the Florida PSC.
GUARD 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 result in an estimated additional $50.0 million in capital
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expenditures associated with the SAFE Program, which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.
Newberry Expansion: In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 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. Conversions of the community gas systems commenced in the second quarter of 2024 and are projected to be complete in the fourth quarter of 2025.
East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will provide additional supply to coastal communities on the East Coast of Florida, which are experiencing significant population growth. Peninsula Pipeline proposed several pipeline extensions to support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the fourth quarter of 2025.
Central Florida Reinforcement Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida which are also experiencing significant population growth. Peninsula Pipeline proposed to 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 went into service in July 2025.
Renewable Natural Gas Supply Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition at its July 2024 meeting with the projects estimated to be completed in the first half of 2026. In October 2025, the Florida PSC approved amendments to the Transportation Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements.
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 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 and the project was completed in September 2024.
Miami Inner Loop Pipeline 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 FCG's distribution system in the area, as well as enhance FCG's access to gas from various points in the
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Miami-Dade County area. The expansion was approved in February 2025 and interim services began in August 2025 with permanent facilities expected to be in service by the second quarter of 2026.
FPU Electric Rate Case: In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million were approved with an effective date of November 1, 2024. In March 2025, the Florida PSC approved the permanent rate increase, but the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to resolve all outstanding issues in its current base rate case, which was filed as a joint motion for approval with the Florida PSC. This settlement which was approved by the Florida PSC in July 2025, provides for a total revenue increase of approximately $8.6 million on an annual basis, with $1.0 million of the increase deferred from the first year's base rate increase and recovered over three years. A step-up rate increase was also approved for up to $0.7 million, upon completion of the purchase and refurbishment of certain substations, which is expected in December 2026.
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, Delaware 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. Construction has commenced and the project is expected to be placed into service in mid-2026 dependent on final FERC approval.
In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025.
Salisbury Integrity Project: Eastern Shore submitted a Prior Notice Filing under its Blanket Certificate to the FERC in March 2025 requesting to construct, own, operate, and maintain approximately 5.5 miles of 10-inch looping pipeline in Wicomico County, Maryland. The protest period terminated in May 2025 with no protests filed. The project is necessary to comply with pipeline integrity management regulations of the Pipeline and Hazardous Materials Safety Administration ("PHMSA").
Capital Cost Surcharge: In December 2024, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2024. The combined revised surcharge became effective January 1, 2025.
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 $83.7 million and $84.6 million at September 30, 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.
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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 September 30, 2025 and December 31, 2024, we had approximately $3.1 million and $3.2 million, respectively, in environmental liabilities related to the former MGP sites, and related regulatory assets of 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 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 September 30, 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 close out of the property is estimated to be bet ween $2.5 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 September 30, 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
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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 BOD has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of September 30, 2025 was $40.0 million. The aggregate amount guaranteed related to our subsidiaries at September 30, 2025 was $30.4 million with the guarantees expiring on various dates through September 2026. In addition, the BOD has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at September 30, 2025 was $4.0 million.
As of September 30, 2025, we have issued letters of credit totaling $4.3 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 April 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 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:
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| Three Months Ended September 30,
| 2025 |  | 2024
(in millions) | Regulated | Unregulated | Other Businesses and Eliminations (1) | Total |  | Regulated | Unregulated | Other Businesses and Eliminations (1) | Total
Operating revenues, unaffiliated customers | $ | 145.8 |  | $ | 33.8 |  | $ | — |  | $ | 179.6 |  |  | $ | 130.2 |  | $ | 30.0 |  | $ | — |  | $ | 160.2 |
Intersegment revenues (2) | 0.6 |  | 6.9 |  | (7.5) |  | — |  |  | 0.4 |  | 5.6 |  | (6.0) |  | — |
| 146.4 |  | 40.7 |  | (7.5) |  | 179.6 |  |  | 130.6 |  | 35.6 |  | (6.0) |  | 160.2 |
Less: |  |  |  |  |  |  |  |  |
Natural gas, propane and electric costs | 31.7 |  | 18.3 |  | (7.6) |  | 42.4 |  |  | 28.4 |  | 15.8 |  | (6.0) |  | 38.2 |
Operations and maintenance expenses | 39.7 |  | 19.9 |  | 0.1 |  | 59.7 |  |  | 37.6 |  | 17.0 |  | — |  | 54.6 |
Depreciation and amortization | 18.2 |  | 5.1 |  | — |  | 23.3 |  |  | 12.3 |  | 4.5 |  | — |  | 16.8 |
Other segment items (3) | 7.9 |  | 1.3 |  | — |  | 9.2 |  |  | 8.3 |  | 1.4 |  | — |  | 9.7 |
Segment operating income | $ | 48.9 |  | $ | (3.9) |  | $ | — |  | $ | 45.0 |  |  | $ | 44.0 |  | $ | (3.1) |  | $ | — |  | $ | 40.9 |
Other income, net |  |  |  | 0.2 |  |  |  |  |  | 0.5 |
Interest charges |  |  |  | 18.2 |  |  |  |  |  | 17.1 |
Income before income taxes |  |  |  | 27.0 |  |  |  |  |  | 24.3 |
Income taxes |  |  |  | 7.6 |  |  |  |  |  | 6.8 |
Net Income |  |  |  | $ | 19.4 |  |  |  |  |  | $ | 17.5 |
Capital expenditures | $ | 108.1 |  | $ | 9.6 |  | $ | 5.1 |  | $ | 122.8 |  |  | $ | 89.0 |  | $ | 8.3 |  | $ | — |  | $ | 97.3 |

(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.

| Nine Months Ended September 30,
| 2025 |  | 2024
(in millions) | Regulated | Unregulated | Other Businesses and Eliminations (1) | Total |  | Regulated | Unregulated | Other Businesses and Eliminations (1) | Total
Operating revenues, unaffiliated customers | $ | 496.4 |  | $ | 174.7 |  | $ | — |  | $ | 671.1 |  |  | $ | 425.1 |  | $ | 147.1 |  | $ | — |  | $ | 572.2 |
Intersegment revenues (2) | 1.4 |  | 20.6 |  | (22.0) |  | — |  |  | 4.6 |  | 13.0 |  | (17.6) |  | — |
| 497.8 |  | 195.3 |  | (22.0) |  | 671.1 |  |  | 429.7 |  | 160.1 |  | (17.6) |  | 572.2 |
Less: |  |  |  |  |  |  |  |  |
Natural gas, propane and electric costs | 137.3 |  | 93.4 |  | (22.0) |  | 208.7 |  |  | 105.7 |  | 70.9 |  | (17.5) |  | 159.1 |
Operations and maintenance expenses | 122.1 |  | 61.9 |  | — |  | 184.0 |  |  | 115.9 |  | 54.2 |  | (0.1) |  | 170.0 |
Depreciation and amortization | 52.6 |  | 15.1 |  | — |  | 67.7 |  |  | 39.5 |  | 12.2 |  | — |  | 51.7 |
Other segment items (3) | 24.6 |  | 4.0 |  | — |  | 28.6 |  |  | 26.0 |  | 4.1 |  | — |  | 30.1 |
Segment operating income | $ | 161.2 |  | $ | 20.9 |  | $ | — |  | 182.1 |  |  | $ | 142.6 |  | $ | 18.7 |  | $ | — |  | 161.3 |
Other income, net |  |  |  | 1.2 |  |  |  |  |  | 1.7 |
Interest charges |  |  |  | 54.1 |  |  |  |  |  | 50.9 |
Income before income taxes |  |  |  | 129.2 |  |  |  |  |  | 112.1 |
Income taxes |  |  |  | 35.0 |  |  |  |  |  | 30.2 |
Net Income |  |  |  | $ | 94.2 |  |  |  |  |  | $ | 81.9 |
Capital expenditures | $ | 295.7 |  | $ | 32.1 |  | $ | 7.8 |  | $ | 335.6 |  |  | $ | 230.9 |  | $ | 24.6 |  | $ | 1.3 |  | $ | 256.8 |

(1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.
(2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
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(3) Other segment items for each reportable segment include: Regulated - Other taxes and transaction and transition costs related to the integration of FCG; Unregulated - Other taxes.

(in millions) |  | September 30, 2025 |  | December 31, 2024
Identifiable Assets |  |  |  |
Regulated Energy segment |  | $ | 3,325.0 |  |  | $ | 3,042.9 |
Unregulated Energy segment |  | 470.2 |  |  | 486.4 |
Other Businesses and Eliminations |  | 66.2 |  |  | 47.7 |
Total Identifiable Assets |  | $ | 3,861.4 |  |  | $ | 3,577.0 |

9. Stockholders' Equity
Common Stock Issuances
We maintain effective shelf registration statements with the SEC for the issuance of common stock in various types of equity offerings, including pursuant to our DRIP and ATM program. Depending on our capital needs and subject to market conditions, we may issue additional shares under the direct stock purchase component of the DRIP in addition to other possible debt and equity offerings. In November 2024, we established a new ATM program under which we may sell shares of our common stock up to an aggregate offering price of $100.0 million. This current ATM program is active through November 2027. For the nine months ended September 30, 2025 and 2024, we received net proceeds of $76.3 million and $56.8 million, respectively, associated with shares issued under 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 nine months ended September 30, 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 loss before reclassifications |  | — |  |  | — |  |  | (0.8) |  |  | (0.8) |
Amounts reclassified from accumulated other comprehensive loss |  | — |  |  | (0.5) |  |  | (0.2) |  |  | (0.7) |
Net current-period other comprehensive loss |  | — |  |  | (0.5) |  |  | (1.0) |  |  | (1.5) |
As of September 30, 2025 |  | $ | (2.1) |  |  | $ | (0.1) |  |  | $ | (1.0) |  |  | $ | (3.2) |

As of December 31, 2023 |  | $ | (2.6) |  |  | $ | (0.3) |  |  | $ | 0.1 |  |  | $ | (2.8) |
Other comprehensive income (loss) before reclassifications |  | — |  |  | 1.0 |  |  | (1.3) |  |  | (0.3) |
Amounts reclassified from accumulated other comprehensive loss |  | — |  |  | (0.6) |  |  | (0.4) |  |  | (1.0) |
Net prior-period other comprehensive income (loss) |  | — |  |  | 0.4 |  |  | (1.7) |  |  | (1.3) |
As of September 30, 2024 |  | $ | (2.6) |  |  | $ | 0.1 |  |  | $ | (1.6) |  |  | $ | (4.1) |

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,
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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 cost (benefit) for the FPU Pension Plan for the three and nine months ended September 30, 2025 and 2024 is set forth in the following table:

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(in millions) |  |  |  |  |  |  |  |
Interest cost |  | $ | 0.6 |  |  | $ | 0.6 |  |  | $ | 1.8 |  |  | $ | 1.8 |
Expected return on plan assets |  | (0.7) |  |  | (0.8) |  |  | (2.1) |  |  | (2.2) |
Amortization of net loss |  | 0.1 |  |  | 0.1 |  |  | 0.1 |  |  | 0.2 |
Total net periodic benefit |  | $ | — |  |  | $ | (0.1) |  |  | $ | (0.2) |  |  | $ | (0.2) |

Net periodic costs for our other pension and postretirement benefit plans were not material for the three and nine months ended September 30, 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 and nine months ended September 30, 2025 and 2024.
The components of our net periodic costs (benefits) 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 nine months ended September 30, 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 and nine months ended September 30, 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 BOD and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up 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 $16.8 million and $14.4 million at September 30, 2025 and December 31, 2024, respectively. 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
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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 and nine months ended September 30, 2025 and 2024:

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
|  | 2025 |  | 2024 |  | 2025 |  | 2024
(in millions) |  |  |  |  |  |  |  |
Awards to key employees |  | $ | 1.1 |  |  | $ | 1.7 |  |  | $ | 5.3 |  |  | $ | 5.8 |
Awards to non-employee directors |  | 0.3 |  |  | 0.2 |  |  | 0.7 |  |  | 0.6 |
Total compensation expense |  | 1.4 |  |  | 1.9 |  |  | 6.0 |  |  | 6.4 |
Less: tax benefit |  | (0.4) |  |  | (0.5) |  |  | (1.6) |  |  | (1.6) |
Share-based compensation amounts included in net income |  | $ | 1.0 |  |  | $ | 1.4 |  |  | $ | 4.4 |  |  | $ | 4.8 |

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 nine months ended September 30, 2025:

(in thousands, except per share data) |  | Number of Shares |  | Weighted Average Fair Value/Share
Outstanding—December 31, 2024 |  | 253 |  |  | $ | 117.96 |
Granted |  | 99 |  |  | $ | 125.56 |
Vested |  | (37) |  |  | $ | 129.76 |
Expired |  | (26) |  |  | $ | 113.34 |
Outstanding—September 30, 2025 |  | 289 |  |  | $ | 115.63 |

During the nine months ended September 30, 2025, we granted awards of 99 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.
At September 30, 2025, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $39.0 million. At September 30, 2025, there was approximately $7.7 million of unrecognized compensation cost related to these awards, which will be recognized through 2027.
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Non-employee Directors
Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year or less.
Our directors receive an annual retainer of shares of common stock under the SICP for services rendered through the subsequent Annual Meeting of Stockholders. Accordingly, our directors that served on the BOD as of May 2025 each received approximately 1 thousand shares of common stock, respectively, with a weighted average fair value of $134.05 per share.
At September 30, 2025, there was $0.6 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May 2026.
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 September 30, 2025, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Volume of Derivative Activity
As of September 30, 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 |  | 11.7 |  | Cash flow hedges |  | June 2028

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 October 2025 through June 2028) 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 loss 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 September 30, 2026 is $0.2 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 a three-year interest rate swap with a notional amount of $50.0 million at pricing of 3.98 percent. As of September 30, 2025, this swap had expired. In August 2024, we entered into an additional interest rate swap through August 2029, at a notional amount of $50.0 million and pricing of 3.97 percent. Our interest rate swaps are cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate.
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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 condensed consolidated balance sheets which had a balance of $2.4 million and $1.9 million as of September 30, 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 September 30, 2025 and December 31, 2024, are as follows:

|  | Derivative Assets
|  |  |  | Fair Value As Of
(in millions) |  | Balance Sheet Location |  | September 30, 2025 |  | December 31, 2024
Derivatives designated as cash flow hedges |  |  |  |  |  |
Propane swap agreements |  | Derivative assets, at fair value |  | $ | 0.1 |  |  | $ | 0.6 |
Interest rate swap agreements |  | Derivative assets, at fair value |  | — |  |  | 0.1 |
Total Derivative Assets (1) |  |  |  | $ | 0.1 |  |  | $ | 0.7 |

(1) Derivative assets, at fair value, include $0.1 million in current assets in the condensed consolidated balance sheet at September 30, 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 |  | September 30, 2025 |  | December 31, 2024
Derivatives designated as cash flow hedges |  |  |  |  |  |
Propane swap agreements |  | Derivative liabilities, at fair value |  | $ | 0.3 |  |  | $ | — |
Interest rate swap agreements |  | Derivative liabilities, at fair value |  | 1.5 |  |  | 0.1 |
Total Derivative Liabilities (1) |  |  |  | $ | 1.8 |  |  | $ | 0.1 |

(1) Derivative liabilities, at fair value, include $0.5 million in current liabilities in the condensed consolidated balance sheet at September 30, 2025 and no current derivative liabilities at December 31, 2024, with the remainder of the balances classified as long-term.
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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 September 30, |  | For the Nine Months Ended September 30,
(in millions) |  | (Loss) on Derivatives |  | 2025 |  | 2024 |  | 2025 |  | 2024
Derivatives designated as cash flow hedges |  |  |  |  |  |  |  |  |  |
Propane swap agreements |  | Revenues |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | (0.3) |
Propane swap agreements |  | Unregulated propane and natural gas costs |  | (0.1) |  |  | (0.1) |  |  | 0.7 |  |  | 1.3 |
Interest rate swap agreements |  | Interest expense |  | 0.1 |  |  | 0.3 |  |  | 0.3 |  |  | 0.6 |
Total |  |  |  | $ | — |  |  | $ | 0.2 |  |  | $ | 1.0 |  |  | $ | 1.6 |

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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 include 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 September 30, 2025 and December 31, 2024:

|  |  |  | Fair Value Measurements Using:
As of September 30, 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 |  | $ | 0.9 |  |  | $ | — |  |  | $ | — |  |  | $ | 0.9 |
Investments—mutual funds and other |  | 15.9 |  |  | 15.9 |  |  | — |  |  | — |
Total investments |  | 16.8 |  |  | 15.9 |  |  | — |  |  | 0.9 |
Derivative assets |  | 0.1 |  |  | — |  |  | 0.1 |  |  | — |
Total assets |  | $ | 16.9 |  |  | $ | 15.9 |  |  | $ | 0.1 |  |  | $ | 0.9 |
Liabilities: |  |  |  |  |  |  |  |
Derivative liabilities |  | $ | 1.8 |  |  | $ | — |  |  | $ | 1.8 |  |  | $ | — |

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|  |  |  | 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 nine months ended September 30, 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 September 30, 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 September 30, 2025, long-term debt, which includes current maturities but excludes debt issuance costs, had both a carrying value and estimated fair value of approximately $1.5 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.
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14. Long-Term Debt
Our outstanding long-term debt is shown below:

|  | September 30, |  | December 31,
(in millions) |  | 2025 |  | 2024
Uncollateralized Senior Notes: |  |  |  |
5.68% notes, due June 2026 |  | $ | 2.9 |  |  | $ | 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 |  | 2.1 |  |  | 2.8 |
4.88% notes, due August 2028 |  | 60.0 |  |  | — |
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 |  | 20.0 |  |  | 25.0 |
5.20% notes, due November 2029 |  | 100.0 |  |  | 100.0 |
5.02% notes, due September 2030 |  | 50.0 |  |  | — |
6.62% notes, due December 2030 |  | 100.0 |  |  | 100.0 |
5.16% notes, due August 2031 |  | 90.0 |  |  | — |
3.25% notes, due April 2032 |  | 47.3 |  |  | 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 |  | 6.0 |  |  | 6.7 |
Less: debt issuance costs |  | (3.9) |  |  | (3.6) |
Total long-term debt |  | 1,472.4 |  |  | 1,287.2 |
Less: current maturities |  | (34.5) |  |  | (25.5) |
Total long-term debt, net of current maturities |  | $ | 1,437.9 |  |  | $ | 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
In August 2025, we entered into a Note Purchase Agreement for the issuance of Senior Notes in the aggregate principal amount of $200.0 million with an initial funding of $150.0 million in August 2025 and an additional $50.0 million in September 2025. These Senior Notes have an average interest rate of 5.04 percent consisting of $60.0 million of 4.88 percent notes due in August 2028, $50.0 million of 5.02 percent notes due in September 2030, and $90.0 million of 5.16 percent notes due in August 2031. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. The outstanding principal balance of the Senior Notes will be due on their respective maturity dates with interest payments payable semiannually beginning in 2026
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until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other 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 which began in 2025.
Shelf Agreements
We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026 and June 2030, respectively, however neither of such lenders have any obligation to purchase debt thereunder. In June 2025, we amended our Shelf Agreement with MetLife to expand the total borrowing capacity and extend the term of the agreement for an additional five years. At September 30, 2025, a total of $305.0 million of borrowing capacity was available under these Shelf Agreements.
15. Short-Term Borrowings
As of September 30, 2025, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At September 30, 2025 and December 31, 2024, we had $95.8 million and $196.5 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.96 percent and 5.06 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at September 30, 2025.
In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche and $200.0 million available under the five-year tranche which expires in August 2029. In August 2025, we exercised an option under the Revolver to extend the 364-day tranche through August 2026. All other terms and conditions of the agreement remain unchanged. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be subject to a pricing grid, including the commitment fee and the interest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. The 364-day tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion.
We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 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 September 30, 2025, we were in compliance with this covenant.
Our total available credit under the Revolver at September 30, 2025 was $349.9 million. As of September 30, 2025, we had issued $4.3 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
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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 condensed consolidated balance sheet at September 30, 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 September 30, 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 cost included in our condensed consolidated statements of income were not material for the three and nine months ended September 30, 2025 and 2024. Total cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows were not material for the nine months ended September 30, 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 September 30, 2025 and December 31, 2024:

(in millions) |  | Balance sheet classification |  | September 30, 2025 |  | December 31, 2024
Assets |  |  |  |  |  |
Operating lease assets |  | Operating lease right-of-use assets |  | $ | 9.6 |  |  | $ | 10.5 |
Liabilities |  |  |  |  |  |
Current |  |  |  |  |  |
Operating lease liabilities |  | Other accrued liabilities |  | $ | 1.9 |  |  | $ | 2.4 |
Noncurrent |  |  |  |  |  |
Operating lease liabilities |  | Operating lease - liabilities |  | 8.0 |  |  | 8.7 |
Total lease liabilities |  |  |  | $ | 9.9 |  |  | $ | 11.1 |

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating leases at September 30, 2025 and December 31, 2024:

|  | September 30, 2025 |  | December 31, 2024
Weighted-average remaining lease term (in years) |  |  |  |
Operating leases |  | 7.5 |  | 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 September 30, 2025 and for each of the next five years and thereafter:
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(in millions) |  | Operating Leases (1)
Remainder of 2025 |  | $ | 0.6 |
2026 |  | 2.0 |
2027 |  | 1.8 |
2028 |  | 1.4 |
2029 |  | 1.3 |
2030 |  | 1.1 |
Thereafter |  | 3.0 |
Total lease payments |  | 11.2 |
Less: Interest |  | (1.3) |
Present value of lease liabilities |  | $ | 9.9 |

(1) Operating lease payments include $2.0 million related to options to extend lease terms that are reasonably certain of being exercised.
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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2024, including the audited consolidated financial statements and notes thereto.
Safe Harbor for Forward-Looking Statements
We make statements in this Quarterly Report on Form 10-Q (this "Quarterly Report") that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future events or otherwise. These statements are subject to many risks and uncertainties. In addition to the risk factors described under Item 1A., Risk Factors in our 2024 Annual Report on Form 10-K, the following important factors, among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:
•state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed and the degree to which competition enters the electric and natural gas industries;
•the outcomes of regulatory, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the related costs are adequately covered by insurance or recoverable in rates;
•the impact of climate change, including the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change;
•the impact of significant changes to current tax regulations and rates, including the impact they may have on our financial positions, results of operations and/or cash flows;
•the timing of certification authorizations associated with new capital projects and the ability to construct facilities at or below estimated costs, and within estimated timeframes;
•changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now, or may in the future, own or operate;
•changes in the current political environment, including the effects the Presidential administration could have on energy policy, the economy and consumer confidence;
•possible increased federal, state and local regulation of the safety of our operations;
•the availability and reliability of adequate technology, including our ability to adapt to technological advances, effectively implement new technologies and manage the related costs;
•the inherent hazards and risks involved in transporting and distributing natural gas, electricity and propane;
•the economy in our service territories or markets, the nation, and worldwide, including the impact of economic conditions (which we do not control) such as the risk and uncertainties associated with tariffs and trade wars, on demand for natural gas, electricity, propane or other fuels;
•risks related to cyber-attacks or cyber-terrorism that could disrupt our business operations or result in failure of information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information;
•issues relating to the implementation and effective use of technologies to support our business, including artificial intelligence;
•adverse weather conditions, including the effects of hurricanes, ice storms and other damaging weather events;
•customers' preferred energy sources and our expectations regarding customer consumption;
•industrial, commercial and residential growth or contraction in our markets or service territories;
•the effect of competition on our businesses from other energy suppliers and alternative forms of energy;
•the timing and extent of changes in commodity prices and interest rates;
•the effect of spot, forward and future market prices on our various energy businesses;
•the extent of our success in connecting natural gas and electric supplies to our transmission systems, establishing and maintaining key supply sources, and expanding natural gas and electric markets;
•the creditworthiness of counterparties with which we are engaged in transactions;
•the capital-intensive nature of our regulated energy businesses;
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•our ability to access the credit and capital markets to execute our business strategy, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;
•the ability to successfully execute, manage and integrate a merger, acquisition or divestiture of assets or businesses and the related regulatory or other conditions associated with the merger, acquisition or divestiture;
•the impact on our costs and funding obligations, under our pension and other postretirement benefit plans, of potential downturns in the financial markets, lower discount rates, and costs associated with health care legislation and regulation;
•the ability to continue to hire, train and retain appropriately qualified personnel;
•the availability of, and competition for, qualified personnel supporting our natural gas, electricity and propane businesses;
•the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and
•the impacts associated with a pandemic, including the duration and scope of the pandemic the corresponding impact on our supply chains, our personnel, our contract counterparties, general economic conditions and growth, the financial markets and any costs to comply with governmental mandates.
Introduction
Chesapeake Utilities Corporation is a Delaware corporation formed in 1947 with operations primarily in the Mid-Atlantic region, North Carolina, South Carolina, Florida and Ohio. We are an energy delivery company engaged in the distribution of natural gas, electricity and propane, the transmission of natural gas, the generation of electricity and steam, and in providing mobile compressed natural gas and other energy-related services to our customers.
Our strategy is focused on growing earnings from a stable regulated energy delivery foundation and investing in related businesses and services that together provide opportunities for returns greater than traditional utility returns. We seek to identify and develop opportunities across the energy value chain, with emphasis on regulated midstream and downstream investments that are accretive to earnings per share and create opportunities to continue our record of top tier returns on equity relative to our peer group. The Company’s growth strategy includes the continued investment and expansion of the Company’s regulated operations that provide a stable base of earnings, as well as investments in other related non-regulated businesses and services including sustainable investments, such as renewable natural gas-related investments.

Currently, our growth strategy is focused on the following platforms, including: •Prudently deploying investment capital. ◦Optimizing the earnings growth in our existing businesses, which includes organic growth, territory expansions, and new products and services. ◦Identification and pursuit of additional pipeline expansions, including new interstate and intrastate transmission projects. ◦Growth of Marlin Gas Services’ CNG transport business and expansion into LNG and RNG transport services as well as methane capture. ◦Identifying and undertaking additional strategic propane acquisitions that provide a larger foundation in current markets and expand our brand and presence into new strategic growth markets. ◦Leveraging our current capabilities, including our integrated set of energy delivery businesses, to support and contribute to a more sustainable future. •Proactively managing our regulatory agenda. ◦Driving regulatory initiatives that align with our growth strategy and investment plans. •Continually executing on our business transformation initiatives. ◦Increased opportunities to transform the Company with a focus on people, process, technology and organizational structure.

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 normally highest due to colder temperatures.
Sustainability Across the Company
Our focus on sustainability is supported and shared across the organization by the dedication and efforts of our BOD and its Committees, as well as the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, our BOD is committed to overseeing the sustainability of the Company, its environmental stewardship initiatives, its safety and operational compliance practices.
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These commitments guide our mission to deliver energy that makes life better for the people and communities we serve. They impact every aspect of the relationships we have with our stakeholders. Beginning in 2024, we unveiled our first in a continuing series of sustainability micro-reports. We encourage our investors to review the micro-reports, as well as prior sustainability reports, which can be accessed on our website, and welcome feedback as we continue to enhance our sustainability disclosures.
Non-GAAP Financial Measures
This document, including the tables herein, include references to both Generally Accepted Accounting Principles ("GAAP") and non-GAAP financial measures, including Adjusted Gross Margin, Adjusted Net Income and Adjusted EPS. A "non-GAAP financial measure" is generally defined as a numerical measure of a company's historical or future performance that includes or excludes amounts, or that is subject to adjustments, so as to be different from the most directly comparable measure calculated or presented in accordance with GAAP. Our management believes certain non-GAAP financial measures, when considered together with GAAP financial measures, provide information that is useful to investors in understanding period-over-period operating results separate and apart from items that may, or could, have a disproportionately positive or negative impact on results in any particular period.
We calculate Adjusted Gross Margin by deducting the purchased cost of natural gas, propane and electricity and the cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Adjusted Gross Margin exclude depreciation and amortization and certain costs presented in operations and maintenance expenses in accordance with regulatory requirements. We calculate Adjusted Net Income and Adjusted EPS by deducting non-recurring costs and expenses associated with significant acquisitions that may affect the comparison of period-over-period results. These non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. The Company believes that these non-GAAP financial measures are useful and meaningful to investors as a basis for making investment decisions, and provide investors with information that demonstrates the profitability achieved by the Company under allowed rates for regulated energy operations and under the Company's competitive pricing structures for unregulated energy operations. The Company's management uses these non-GAAP financial measures in assessing a business unit's and the overall Company performance. Other companies may calculate these non-GAAP financial measures in a different manner.
Unless otherwise noted, EPS and Adjusted EPS information are presented on a diluted basis.
The following tables reconcile Gross Margin, Net Income, and EPS, all as defined under GAAP, to our non-GAAP financial measures of Adjusted Gross Margin, Adjusted Net Income and Adjusted EPS for the three and nine months ended September 30, 2025 and 2024:
Adjusted Gross Margin

|  | For the Three Months Ended September 30, 2025
(in millions) |  | Regulated Energy |  | Unregulated Energy |  | Other Businesses and Eliminations |  | Total
Operating Revenues |  | $ | 146.4 |  |  | $ | 40.7 |  |  | $ | (7.5) |  |  | $ | 179.6 |
Cost of Sales: |  |  |  |  |  |  |  |
Natural gas, propane and electric costs |  | (31.7) |  |  | (18.3) |  |  | 7.6 |  |  | (42.4) |
Depreciation & amortization |  | (18.2) |  |  | (5.1) |  |  | — |  |  | (23.3) |
Operations & maintenance expenses (1) |  | (12.6) |  |  | (9.5) |  |  | — |  |  | (22.1) |
Gross Margin (GAAP) |  | 83.9 |  |  | 7.8 |  |  | 0.1 |  |  | 91.8 |
Operations & maintenance expenses (1) |  | 12.6 |  |  | 9.5 |  |  | — |  |  | 22.1 |
Depreciation & amortization |  | 18.2 |  |  | 5.1 |  |  | — |  |  | 23.3 |
Adjusted Gross Margin (Non-GAAP) |  | $ | 114.7 |  |  | $ | 22.4 |  |  | $ | 0.1 |  |  | $ | 137.2 |

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|  | For the Three Months Ended September 30, 2024
(in millions) |  | Regulated Energy |  | Unregulated Energy |  | Other Businesses and Eliminations |  | Total
Operating Revenues |  | $ | 130.6 |  |  | $ | 35.6 |  |  | $ | (6.0) |  |  | $ | 160.2 |
Cost of Sales: |  |  |  |  |  |  |  |
Natural gas, propane and electric costs |  | (28.4) |  |  | (15.8) |  |  | 6.0 |  |  | (38.2) |
Depreciation & amortization |  | (12.3) |  |  | (4.5) |  |  | — |  |  | (16.8) |
Operations & maintenance expenses (1) |  | (10.7) |  |  | (8.1) |  |  | — |  |  | (18.8) |
Gross Margin (GAAP) |  | 79.2 |  |  | 7.2 |  |  | — |  |  | 86.4 |
Operations & maintenance expenses (1) |  | 10.7 |  |  | 8.1 |  |  | — |  |  | 18.8 |
Depreciation & amortization |  | 12.3 |  |  | 4.5 |  |  | — |  |  | 16.8 |
Adjusted Gross Margin (Non-GAAP) |  | $ | 102.2 |  |  | $ | 19.8 |  |  | $ | — |  |  | $ | 122.0 |

|  | For the Nine Months Ended September 30, 2025
(in millions) |  | Regulated Energy |  | Unregulated Energy |  | Other Businesses and Eliminations |  | Total
Operating Revenues |  | $ | 497.8 |  |  | $ | 195.3 |  |  | $ | (22.0) |  |  | $ | 671.1 |
Cost of Sales: |  |  |  |  |  |  |  |
Natural gas, propane and electric costs |  | (137.3) |  |  | (93.4) |  |  | 22.0 |  |  | (208.7) |
Depreciation & amortization |  | (52.6) |  |  | (15.1) |  |  | — |  |  | (67.7) |
Operations & maintenance expenses (1) |  | (40.5) |  |  | (29.0) |  |  | (0.1) |  |  | (69.6) |
Gross Margin (GAAP) |  | 267.4 |  |  | 57.8 |  |  | (0.1) |  |  | 325.1 |
Operations & maintenance expenses (1) |  | 40.5 |  |  | 29.0 |  |  | 0.1 |  |  | 69.6 |
Depreciation & amortization |  | 52.6 |  |  | 15.1 |  |  | — |  |  | 67.7 |
Adjusted Gross Margin (Non-GAAP) |  | $ | 360.5 |  |  | $ | 101.9 |  |  | $ | — |  |  | $ | 462.4 |

|  | For the Nine Months Ended September 30, 2024
(in millions) |  | Regulated Energy |  | Unregulated Energy |  | Other Businesses and Eliminations |  | Total
Operating Revenues |  | $ | 429.7 |  |  | $ | 160.1 |  |  | $ | (17.6) |  |  | $ | 572.2 |
Cost of Sales: |  |  |  |  |  |  |  |
Natural gas, propane and electric costs |  | (105.7) |  |  | (70.9) |  |  | 17.5 |  |  | (159.1) |
Depreciation & amortization |  | (39.5) |  |  | (12.2) |  |  | — |  |  | (51.7) |
Operations & maintenance expenses (1) |  | (35.7) |  |  | (24.4) |  |  | — |  |  | (60.1) |
Gross Margin (GAAP) |  | 248.8 |  |  | 52.6 |  |  | (0.1) |  |  | 301.3 |
Operations & maintenance expenses (1) |  | 35.7 |  |  | 24.4 |  |  | — |  |  | 60.1 |
Depreciation & amortization |  | 39.5 |  |  | 12.2 |  |  | — |  |  | 51.7 |
Adjusted Gross Margin (Non-GAAP) |  | $ | 324.0 |  |  | $ | 89.2 |  |  | $ | (0.1) |  |  | $ | 413.1 |

(1) Operations & maintenance expenses within the condensed consolidated statements of income are presented in accordance with regulatory requirements and to provide comparability within the industry. Operations & maintenance expenses which are deemed to be directly attributable to revenue producing activities have been separately presented above in order to calculate Gross Margin as defined under GAAP.
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2025 to 2024 Gross Margin (GAAP) Variance – Regulated Energy
Gross Margin (GAAP) for the Regulated Energy segment for the quarter ended September 30, 2025 was $83.9 million, an increase of $4.7 million, or 5.9 percent, compared to the same period in 2024. The increase in gross margin largely reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects, and organic growth in our natural gas distribution businesses.
Gross Margin (GAAP) for the Regulated Energy segment for the nine months ended September 30, 2025 was $267.4 million, an increase of $18.6 million, or 7.5 percent, compared to the same period in 2024. The increase in gross margin largely reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects, and organic growth in our natural gas distribution businesses.
2025 to 2024 Gross Margin (GAAP) Variance – Unregulated Energy
Gross Margin (GAAP) for the Unregulated Energy segment for the quarter ended September 30, 2025 was $7.8 million, an increase of $0.6 million, or 8.3 percent, compared to the same period in 2024. The increase in gross margin was primarily attributable to higher CNG, RNG, and LNG services compared to the prior-year period and increased performance from Aspire Energy, partially offset by lower results from our propane distribution business.
Gross Margin (GAAP) for the Unregulated Energy segment for the nine months ended September 30, 2025 was $57.8 million, an increase of $5.2 million, or 9.9 percent, compared to the same period in 2024. The increase in gross margin was primarily attributable to greater demand for CNG, RNG and LNG services, higher results from our propane distribution business largely attributable to increased customer consumption from colder year-over-year weather in our Delmarva service territory, and increased performance from Aspire Energy.
Adjusted Net Income and Adjusted EPS

|  | Three Months Ended |  | Nine Months Ended
|  | September 30, |  | September 30,
(dollars in millions, shares in thousands (except per share data)) |  | 2025 |  | 2024 |  | 2025 |  | 2024
Net Income (GAAP) |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 94.2 |  |  | $ | 81.9 |
FCG transaction and transition-related expenses, net (1) |  | 0.1 |  |  | 0.6 |  |  | 0.7 |  |  | 2.3 |
Adjusted Net Income (Non-GAAP) |  | $ | 19.5 |  |  | $ | 18.1 |  |  | $ | 94.9 |  |  | $ | 84.2 |
Weighted average common shares outstanding - diluted |  | 23,629 |  |  | 22,564 |  |  | 23,360 |  |  | 22,402 |
Earnings Per Share - Diluted (GAAP) |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 4.03 |  |  | $ | 3.66 |
FCG transaction and transition-related expenses, net (1) |  | — |  |  | 0.02 |  |  | 0.03 |  |  | 0.10 |
Adjusted Earnings Per Share - Diluted (Non-GAAP) |  | $ | 0.82 |  |  | $ | 0.80 |  |  | $ | 4.06 |  |  | $ | 3.76 |

(1) Transaction and transition-related expenses represent non-recurring costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding, and legal fees.
2025 to 2024 Net Income (GAAP) Variance
Net income (GAAP) for the quarter ended September 30, 2025 was $19.4 million, or $0.82 per share, compared to $17.5 million, or $0.78 per share, for the same quarter of 2024. Net income for the three months ended September 30, 2025 and 2024, included $0.1 million and $0.6 million, respectively, of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $1.4 million or 7.7 percent compared to the prior-year period.
Net income (GAAP) for the nine months ended September 30, 2025 was $94.2 million, or $4.03 per share, compared to $81.9 million, or $3.66 per share, for the same quarter of 2024. Net income for the nine months ended September 30, 2025 and 2024, included $0.7 million and $2.3 million, respectively, of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $10.7 million or 12.7 percent compared to the prior-year period.
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Results of Operations for the Three and Nine Months Ended September 30, 2025
Operational Highlights
Our adjusted net income for the three months ended September 30, 2025 was $19.5 million, or $0.82 per share, compared to $18.1 million, or $0.80 per share, for the same quarter of 2024. Operating income for the third quarter of 2025 was $45.0 million, an increase of $4.1 million compared to the same period in 2024. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $3.5 million or 8.4 percent compared to the prior-year period. The increase in adjusted gross margin in the third quarter of 2025 was driven by incremental margin from regulatory initiatives and infrastructure programs, natural gas growth and transmission expansion projects, and increased demand for CNG, RNG, and LNG services. The increase in operating expenses was driven largely by higher depreciation attributable to growth projects and the absence of an RSAM adjustment from FCG (which represented a $3.2 million benefit in the third quarter of 2024). Higher expenses associated with facilities, maintenance and outside services also contributed to the increase.
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|  | Three Months Ended |  |
|  | September 30, |  | Increase
|  | 2025 |  | 2024 |  | (Decrease)
(in millions, except shares (thousands) and per share data) |  |  |  |  |  |
Adjusted Gross Margin |  |  |  |  |  |
Regulated Energy segment |  | $ | 114.7 |  |  | $ | 102.2 |  |  | $ | 12.5 |
Unregulated Energy segment |  | 22.4 |  |  | 19.8 |  |  | 2.6 |
Other Businesses and Eliminations |  | 0.1 |  |  | — |  |  | 0.1 |
Total Adjusted Gross Margin |  | $ | 137.2 |  |  | $ | 122.0 |  |  | $ | 15.2 |
Operating Income (Loss) |  |  |  |  |  |
Regulated Energy segment |  | $ | 48.9 |  |  | $ | 44.0 |  |  | $ | 4.9 |
Unregulated Energy segment |  | (3.9) |  |  | (3.1) |  |  | (0.8) |
Other Businesses and Eliminations |  | — |  |  | — |  |  | — |
Total Operating Income |  | 45.0 |  |  | 40.9 |  |  | 4.1 |
Other income, net |  | 0.2 |  |  | 0.5 |  |  | (0.3) |
Interest charges |  | 18.2 |  |  | 17.1 |  |  | 1.1 |
Income Before Income Taxes |  | 27.0 |  |  | 24.3 |  |  | 2.7 |
Income taxes |  | 7.6 |  |  | 6.8 |  |  | 0.8 |
Net Income |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 1.9 |
Weighted Average Common Shares Outstanding: |  |  |  |  |  |
Basic |  | 23,526 |  |  | 22,501 |  |  | 1,025 |
Diluted |  | 23,629 |  |  | 22,564 |  |  | 1,065 |
Earnings Per Share of Common Stock |  |  |  |  |  |
Basic |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 0.04 |
Diluted |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 0.04 |
Adjusted Net Income and Adjusted Earnings Per Share |  |  |  |  |  |
Net Income (GAAP) |  | $ | 19.4 |  |  | $ | 17.5 |  |  | $ | 1.9 |
FCG transaction and transition-related expenses, net (1) |  | 0.1 |  |  | 0.6 |  |  | (0.5) |
Adjusted Net Income (Non-GAAP) |  | $ | 19.5 |  |  | $ | 18.1 |  |  | $ | 1.4 |
Earnings Per Share - Diluted (GAAP) |  | $ | 0.82 |  |  | $ | 0.78 |  |  | $ | 0.04 |
FCG transaction and transition-related expenses, net (1) |  | — |  |  | 0.02 |  |  | (0.02) |
Adjusted Earnings Per Share - Diluted (Non-GAAP) |  | $ | 0.82 |  |  | $ | 0.80 |  |  | $ | 0.02 |

(1) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees.
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Key variances between the third quarter of 2024 and 2025 included:

(in millions, except per share data) |  | Pre-tax Income |  | Net Income |  | Earnings Per Share
Third Quarter of 2024 Adjusted Results (1) |  | $ | 25.1 |  |  | $ | 18.1 |  |  | $ | 0.80 |
Change in Adjusted Gross Margins: |  |  |  |  |  |
Natural gas transmission service expansions, including interim services (2) |  | 5.6 |  |  | 4.0 |  |  | 0.17 |
Contributions from regulated infrastructure programs (2) |  | 3.9 |  |  | 2.8 |  |  | 0.12 |
Rate changes associated with recent rate case activities (2) |  | 3.6 |  |  | 2.6 |  |  | 0.11 |
Increased CNG/RNG/LNG services (2) |  | 3.1 |  |  | 2.2 |  |  | 0.09 |
Natural gas growth (excluding service expansions) |  | 1.5 |  |  | 1.1 |  |  | 0.05 |
Increased Aspire Energy performance - rate changes and gathering fees |  | 0.4 |  |  | 0.3 |  |  | 0.01 |
Changes in customer consumption |  | (0.9) |  |  | (0.6) |  |  | (0.03) |
Change in propane margins and service fees |  | (0.7) |  |  | (0.5) |  |  | (0.02) |
|  | 16.5 |  |  | 11.9 |  |  | 0.50 |
Increased Operating Expenses (Excluding Natural Gas, Propane, and Electric Costs): |  |  |  |  |  |
Depreciation, amortization and property tax costs |  | (7.7) |  |  | (5.6) |  |  | (0.24) |
Facilities expenses, maintenance costs and outside services |  | (3.4) |  |  | (2.5) |  |  | (0.10) |
Payroll, benefits and other employee-related expenses |  | (0.6) |  |  | (0.4) |  |  | (0.01) |
Insurance related costs |  | (0.4) |  |  | (0.3) |  |  | (0.01) |
|  | (12.1) |  |  | (8.8) |  |  | (0.36) |
Interest charges |  | (1.1) |  |  | (0.8) |  |  | (0.03) |
Increase in shares outstanding due to 2024 and 2025 equity offerings (3) |  | — |  |  | — |  |  | (0.04) |
Net other changes |  | (1.3) |  |  | (0.9) |  |  | (0.05) |
|  | (2.4) |  |  | (1.7) |  |  | (0.12) |
Third Quarter of 2025 Adjusted Results (1) |  | $ | 27.1 |  |  | $ | 19.5 |  |  | $ | 0.82 |

(1) Transaction and transition-related expenses attributable to the acquisition and integration of FCG have been excluded from the Company’s non-GAAP
measures of adjusted net income and adjusted EPS. See reconciliations above for a detailed comparison to the related GAAP measures.
(2) Refer to Major Projects and Initiatives table for additional information.
(3) Reflects the impact of common shares issued under the DRIP and ATM program.
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Our adjusted net income for the nine months ended September 30, 2025 was $94.9 million, or $4.06 per share, compared to $84.2 million, or $3.76 per share, for the same period of 2024. Operating income for the first nine months of 2025 was $182.1 million, an increase of $20.8 million compared to the same period in 2024. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $18.7 million or 11.4 percent compared to the prior-year period. The increase in adjusted gross margin in the first nine months of 2025 was driven by incremental margin from regulatory initiatives and infrastructure programs, natural gas growth and transmission expansion projects, increased CNG, RNG and LNG services, and increased customer consumption resulting from year-over-year colder temperatures in our Mid-Atlantic and Ohio service territories. These increases were partially offset by reduced margin per gallon and related fees in our propane distribution business and a reduced volume of off-system sales and service fees. Higher operating expenses were driven largely by the absence of an RSAM adjustment from FCG (which represented an $8.9 million benefit during the first nine months of 2024) and higher depreciation attributable to growth projects. Higher facilities, maintenance and outside services, insurance, and payroll, benefits and other employee-related expenses compared to the prior-year period also contributed to the increase.
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|  | Nine Months Ended |  |
|  | September 30, |  | Increase
|  | 2025 |  | 2024 |  | (Decrease)
(in millions, except shares (thousands) and per share data) |  |  |  |  |  |
Adjusted Gross Margin |  |  |  |  |  |
Regulated Energy segment |  | $ | 360.5 |  |  | $ | 324.0 |  |  | $ | 36.5 |
Unregulated Energy segment |  | 101.9 |  |  | 89.2 |  |  | 12.7 |
Other Businesses and Eliminations |  | — |  |  | (0.1) |  |  | 0.1 |
Total Adjusted Gross Margin |  | $ | 462.4 |  |  | $ | 413.1 |  |  | $ | 49.3 |
Operating Income |  |  |  |  |  |
Regulated Energy segment |  | $ | 161.2 |  |  | $ | 142.6 |  |  | $ | 18.6 |
Unregulated Energy segment |  | 20.9 |  |  | 18.7 |  |  | 2.2 |
Other Businesses and Eliminations |  | — |  |  | — |  |  | — |
Total Operating Income |  | 182.1 |  |  | 161.3 |  |  | 20.8 |
Other income, net |  | 1.2 |  |  | 1.7 |  |  | (0.5) |
Interest charges |  | 54.1 |  |  | 50.9 |  |  | 3.2 |
Income Before Income Taxes |  | 129.2 |  |  | 112.1 |  |  | 17.1 |
Income taxes |  | 35.0 |  |  | 30.2 |  |  | 4.8 |
Net Income |  | $ | 94.2 |  |  | $ | 81.9 |  |  | $ | 12.3 |
Weighted Average Common Shares Outstanding: |  |  |  |  |  |
Basic |  | 23,265 |  |  | 22,346 |  |  | 919 |
Diluted |  | 23,360 |  |  | 22,402 |  |  | 958 |
Earnings Per Share of Common Stock |  |  |  |  |  |
Basic |  | $ | 4.05 |  |  | $ | 3.67 |  |  | $ | 0.38 |
Diluted |  | $ | 4.03 |  |  | $ | 3.66 |  |  | $ | 0.37 |
Adjusted Net Income and Adjusted Earnings Per Share |  |  |  |  |  |
Net Income (GAAP) |  | $ | 94.2 |  |  | $ | 81.9 |  |  | $ | 12.3 |
FCG transaction and transition-related expenses, net (1) |  | 0.7 |  |  | 2.3 |  |  | (1.6) |
Adjusted Net Income (Non-GAAP) |  | $ | 94.9 |  |  | $ | 84.2 |  |  | $ | 10.7 |
Earnings Per Share - Diluted (GAAP) |  | $ | 4.03 |  |  | $ | 3.66 |  |  | $ | 0.37 |
FCG transaction and transition-related expenses, net (1) |  | 0.03 |  |  | 0.10 |  |  | (0.07) |
Adjusted Earnings Per Share - Diluted (Non-GAAP) |  | $ | 4.06 |  |  | $ | 3.76 |  |  | $ | 0.30 |

(1) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees.
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Key variances between the nine months ended September 30, 2024 and September 30, 2025 included:

(in millions, except per share data) |  | Pre-tax Income |  | Net Income |  | Earnings Per Share
Nine months ended September 30, 2024 Adjusted Results (1) |  | $ | 115.2 |  |  | $ | 84.2 |  |  | $ | 3.76 |
Change in Adjusted Gross Margins: |  |  |  |  |  |
Natural gas transmission service expansions, including interim services (2) |  | 11.7 |  |  | 8.5 |  |  | 0.37 |
Contributions from regulated infrastructure programs (2) |  | 11.0 |  |  | 8.0 |  |  | 0.34 |
Increased CNG/RNG/LNG services (2) |  | 10.1 |  |  | 7.3 |  |  | 0.31 |
Rate changes associated with recent rate case activities (2) |  | 9.2 |  |  | 6.7 |  |  | 0.29 |
Natural gas growth including conversions (excluding service expansions) |  | 5.5 |  |  | 4.0 |  |  | 0.17 |
Changes in customer consumption |  | 4.8 |  |  | 3.5 |  |  | 0.15 |
Increased Aspire Energy performance - rate changes and gathering fees |  | 0.2 |  |  | 0.2 |  |  | 0.01 |
Change in propane margins and service fees |  | (1.3) |  |  | (0.9) |  |  | (0.04) |
Change in service fees and off-system sales |  | (0.7) |  |  | (0.5) |  |  | (0.02) |
|  | 50.5 |  |  | 36.8 |  |  | 1.58 |
Increased Operating Expenses (Excluding Natural Gas, Propane, and Electric Costs): |  |  |  |  |  |
Depreciation, amortization and property taxes |  | (17.4) |  |  | (12.7) |  |  | (0.54) |
Facilities expenses, maintenance costs and outside services |  | (8.2) |  |  | (6.0) |  |  | (0.26) |
Payroll, benefits and other employee-related expenses |  | (3.8) |  |  | (2.8) |  |  | (0.12) |
Insurance related costs |  | (0.7) |  |  | (0.5) |  |  | (0.02) |
|  | (30.1) |  |  | (22.0) |  |  | (0.94) |
Interest charges |  | (3.2) |  |  | (2.4) |  |  | (0.10) |
Increase in shares outstanding due to 2024 and 2025 equity offerings (3) |  | — |  |  | — |  |  | (0.17) |
Net other changes |  | (2.3) |  |  | (1.7) |  |  | (0.07) |
|  | (5.5) |  |  | (4.1) |  |  | (0.34) |
Nine months ended September 30, 2025 Adjusted Results (1) |  | $ | 130.1 |  |  | $ | 94.9 |  |  | $ | 4.06 |

(1) Transaction and transition-related expenses attributable to the acquisition and integration of FCG have been excluded from the Company’s non-GAAP
measures of adjusted net income and adjusted EPS. See reconciliations above for a detailed comparison to the related GAAP measures.
(2) Refer to Major Projects and Initiatives table for additional information.
(3) Reflects the impact of common shares issued under the DRIP and ATM program.
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Summary of Key Factors
Recently Completed and Ongoing Major Projects and Initiatives
We continuously pursue and develop additional projects and regulatory initiatives to serve existing and new customers, further grow our businesses and earnings, and increase shareholder value. The following table includes all major projects and initiatives that are currently underway or recently completed. Our practice is to add incremental margin associated with new projects and regulatory initiatives to this table once negotiations or details are substantially final and/or the associated earnings can be estimated. Major projects and initiatives that have generated consistent year-over-year adjusted gross margin contributions are removed from the table at the beginning of the next calendar year.

| Adjusted Gross Margin
| Three Months Ended |  | Nine Months Ended |  | Year Ended |  | Estimate for
| September 30, |  | September 30, |  | December 31, |  | Fiscal
(in millions) | 2025 |  | 2024 |  | 2025 |  | 2024 |  | 2024 |  | 2025 |  | 2026
Pipeline Expansions: |  |  |  |  |  |  |  |  |  |  |  |  |
St. Cloud / Twin Lakes Expansion | $ | 1.0 |  |  | $ | 0.1 |  |  | $ | 1.9 |  |  | $ | 0.4 |  |  | $ | 0.6 |  |  | $ | 2.8 |  |  | $ | 3.8 |
Wildlight | 0.5 |  |  | 0.6 |  |  | 1.5 |  |  | 1.0 |  |  | 1.5 |  |  | 3.0 |  |  | 4.3 |
Newberry | 0.6 |  |  | 0.6 |  |  | 1.8 |  |  | 0.7 |  |  | 1.4 |  |  | 2.6 |  |  | 2.6 |
Worcester Resiliency Upgrade | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 10.2 |
Boynton Beach | 0.9 |  |  | — |  |  | 2.3 |  |  | — |  |  | — |  |  | 3.0 |  |  | 3.4 |
New Smyrna Beach | 0.6 |  |  | — |  |  | 0.9 |  |  | — |  |  | — |  |  | 1.6 |  |  | 2.6 |
Central Florida Reinforcement | 0.9 |  |  | — |  |  | 1.5 |  |  | — |  |  | 0.1 |  |  | 2.6 |  |  | 4.3 |
Warwick | 0.5 |  |  | — |  |  | 1.5 |  |  | — |  |  | 0.4 |  |  | 1.9 |  |  | 1.9 |
Renewable Natural Gas Supply Projects | 1.0 |  |  | — |  |  | 1.5 |  |  | — |  |  | — |  |  | 2.5 |  |  | 5.4 |
Miami Inner Loop | 0.9 |  |  | — |  |  | 0.9 |  |  | — |  |  | — |  |  | 2.8 |  |  | 7.6 |
Duncan Plains | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |
Total Pipeline Expansions | 6.9 |  |  | 1.3 |  |  | 13.8 |  |  | 2.1 |  |  | 4.0 |  |  | 22.8 |  |  | 46.1 |
CNG/RNG/LNG Transportation and Infrastructure | 6.6 |  |  | 3.5 |  |  | 20.5 |  |  | 10.4 |  |  | 16.4 |  |  | 25.5 |  |  | 26.5 |
Regulatory Initiatives: |  |  |  |  |  |  |  |  |  |  |  |  |
Florida GUARD program | 1.9 |  |  | 0.9 |  |  | 5.1 |  |  | 2.4 |  |  | 3.6 |  |  | 6.9 |  |  | 9.9 |
FCG SAFE Program | 2.3 |  |  | 1.1 |  |  | 6.2 |  |  | 2.2 |  |  | 3.8 |  |  | 8.5 |  |  | 12.0 |
Capital Cost Surcharge Programs | 1.4 |  |  | 0.8 |  |  | 4.3 |  |  | 2.4 |  |  | 3.2 |  |  | 5.7 |  |  | 7.1 |
Electric Storm Protection Plan | 1.8 |  |  | 0.7 |  |  | 4.4 |  |  | 2.0 |  |  | 3.2 |  |  | 5.9 |  |  | 8.8 |
Maryland Rate Case | 0.5 |  |  | — |  |  | 1.1 |  |  | — |  |  | — |  |  | 1.5 |  |  | 3.5 |
Delaware Rate Case (1) | 0.7 |  |  | — |  |  | 2.9 |  |  | — |  |  | 0.6 |  |  | 4.5 |  |  | 6.1 |
Electric Rate Case (1) | 2.4 |  |  | — |  |  | 5.2 |  |  | — |  |  | 0.3 |  |  | 7.1 |  |  | 8.6 |
Total Regulatory Initiatives | 11.0 |  |  | 3.5 |  |  | 29.2 |  |  | 9.0 |  |  | 14.7 |  |  | 40.1 |  |  | 56.0 |
Total | $ | 24.5 |  |  | $ | 8.3 |  |  | $ | 63.5 |  |  | $ | 21.5 |  |  | $ | 35.1 |  |  | $ | 88.4 |  |  | $ | 128.6 |

(1) Includes adjusted gross margin attributable to interim rates during 2024 and 2025. See additional information provided below.
Detailed Discussion of Major Projects and Initiatives
Pipeline Expansions
St. Cloud / Twin Lakes Expansion
In July 2022, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 2,400 Dts/d of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline constructed a pipeline extension and regulator station for FPU. The extension supports new incremental load due to growth in the area, including providing service, most immediately, to the residential development, Twin Lakes. The expansion also improves reliability and provides operational benefits to FPU’s existing distribution system in the area, supporting future growth. This project was placed into service during July 2023 and generated additional adjusted gross margin of $0.9 million
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and $1.5 million for the three and nine months ended September 30, 2025. We expect this extension to generate annual adjusted gross margin of approximately $0.6 million in 2025 and annually thereafter.
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. We expect this expansion to generate annual adjusted gross margin of approximately $2.2 million in 2025 and $3.2 million annually thereafter.
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. 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 project generated gross margin of $0.5 million for the three months ended September 30, 2025 and additional adjusted gross margin of $0.5 million for the nine months ended September 30, 2025. It is expected to contribute adjusted gross margin of approximately $3.0 million in 2025 and $4.3 million annually thereafter.
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. Conversions of the community gas systems commenced in the second quarter of 2024 and are projected to be complete in the fourth quarter of 2025. The project generated gross margin of $0.6 million for the three months ended September 30, 2025 and additional adjusted gross margin of $1.1 million for the nine months ended September 30, 2025. It is expected to contribute adjusted gross margin of approximately $2.6 million in 2025 and annually thereafter.
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, Delaware 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. Construction has commenced and the project is expected to be placed into service in mid-2026 dependent on final FERC approval.
In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025. The project is expected to generate $10.2 million in adjusted gross margin in 2026 and $17.6 million in 2027 and thereafter.
East Coast Reinforcement Projects (Boynton Beach and New Smyrna Beach)
In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will provide additional supply to coastal communities on the East Coast of Florida, which are experiencing significant population growth. Peninsula Pipeline proposed several pipeline extensions to support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the fourth quarter of 2025. The projects generated adjusted gross margin of $1.5 million and $3.2 million for the three and nine months ended September 30, 2025, respectively, and are expected to contribute adjusted gross margin of approximately $4.6 million in 2025 and $6.0 million annually thereafter.
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Central Florida Reinforcement Projects (Plant City and Lake Mattie)
In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida which are also experiencing significant population growth. Peninsula Pipeline proposed to 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 went into service in July 2025. The project generated additional adjusted gross margin of $0.9 million and $1.5 million for the three and nine months ended September 30, 2025, respectively, and both projects are expected to contribute total adjusted gross margin of approximately $2.6 million in 2025 and $4.3 million annually thereafter.
Warwick Pipeline Project
In July 2024, we announced plans to extend Eastern Shore's transmission deliverability by constructing an additional 4.4 miles of six inch steel pipeline. The project will reinforce the supply and growth for our Delaware division distribution system and expand natural gas service further into Maryland for anticipated future growth. This project was placed into service during the fourth quarter of 2024, generated additional adjusted gross margin of $0.5 million and $1.5 million for the three and nine months ended September 30, 2025, respectively, and is expected to contribute adjusted gross margin of approximately $1.9 million in 2025 and annually thereafter.
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 2026. In October 2025, the Florida PSC approved amendments to the Transportation Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements. These three renewable projects generated adjusted gross margin of $1.0 million and $1.5 million for the three and nine months ended September 30, 2025, respectively, and are projected to generate total adjusted gross margin of approximately $2.5 million in 2025 and $5.4 million annually thereafter.
Miami Inner Loop Pipeline 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 FCG's distribution system in the area, as well as enhance FCG's access to gas from various points in the Miami-Dade County area. The expansion was approved in February 2025 and interim services began in August 2025 with permanent facilities expected to be in service by the second quarter of 2026. The project generated adjusted gross margin of $0.9 million for the three and nine months ended September 30, 2025 and is expected to contribute adjusted gross margin of approximately $2.8 million in 2025 and $7.6 million annually thereafter.
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 and the project was completed in September 2024.
Duncan Plains Pipeline Project
In July 2025, Aspire Energy Express entered into an agreement with American Electric Power to construct and operate an intrastate natural gas pipeline in central Ohio to serve a new fuel-cell facility, which will provide on-site electric power to a data center. This new transmission infrastructure is expected to be in service in the first half of 2027.
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CNG/RNG/LNG Transportation and Infrastructure
We have made a commitment to meet customer demand for CNG, RNG and LNG in the markets we serve. This has included making investments within Marlin Gas Services to be able to transport these products through its virtual pipeline fleet to customers. To date, we have also made an infrastructure investment in Ohio, enabling RNG to fuel a third-party landfill fleet and to transport RNG to end use customers off our pipeline system.
We are also involved in various other projects, all at various stages and all with different opportunities to participate across the energy value chain. In many of these projects, Marlin will play a key role in ensuring the RNG is transported to one of our many pipeline systems where it will be injected. We include our RNG transportation services and infrastructure related adjusted gross margin from across the organization in combination with our CNG and LNG projects.
We estimate annual adjusted gross margin, including amounts attributable to the Full Circle Dairy and Noble Road projects described below, of approximately $25.5 million in 2025 and $26.5 million in 2026 for these transportation related services, with potential for additional growth in future years.
Full Circle Dairy
In February 2023, we announced plans to construct, own and operate a dairy manure RNG facility at Full Circle Dairy in Madison County, Florida. The project consists of a facility converting dairy manure to RNG and transportation assets to bring the gas to market. The first injection of RNG occurred in the second quarter of 2024.
Noble Road Landfill RNG Project
In October 2021, Aspire Energy completed construction of its Noble Road Landfill RNG pipeline project, a 33.1-mile pipeline, which transports RNG generated from the Noble Road landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In conjunction with this expansion, Aspire Energy also upgraded an existing compressor station and installed two new metering and regulation sites. The RNG volume represents more than 10 percent of Aspire Energy’s gas gathering volumes.
Regulatory Initiatives
Florida 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. For t he three and nine months ended September 30, 2025, there was $1.0 million and $2.7 million, respectively, of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $6.9 million of adjusted gross margin in 2025 and $9.9 million in 2026.
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. For t he three and nine months ended September 30, 2025, there was $1.2 million and $4.0 million, respectively, of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $8.5 million of adjusted gross margin in 2025 and $12.0 million in 2026.
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 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 approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.
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Capital Cost Surcharge Programs
In December 2024, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2024. The combined revised surcharge became effective January 1, 2025. 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. 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. For t he three and nine months ended September 30, 2025, there was $0.6 million and $1.9 million, respectively, of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to generate adjusted gross margin of approximately $5.7 million in 2025 and $7.1 million in 2026 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.
Storm Protection Plan
In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC"), 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 related to its SPP. Our Florida electric distribution operation's SPP and SPPCRC were filed d uring the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs for both capital and operating expenses. For the three and nine months ended September 30, 2025, this initiative generated additional adjusted gross margin of $1.1 million and $2.4 million, respectively, and is expected to generate $5.9 million of adjusted gross margin in 2025 and $8.8 million in 2026. We expect continued investment under the SPP going forward.
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, during which Phase II was approved, including an additional $0.9 million in revenue requirement, for a total cumulative increase of $3.5 million. A final order was issued in April 2025 and included approval of the consolidation of the operations and the assets of CUC-Maryland Division, Sandpiper Energy, and Elkton Gas into one entity which was renamed and operates as Chesapeake Utilities of Maryland, Inc. For t he three and nine months ended September 30, 2025, there was $0.5 million and $1.1 million, respectively, of incremental adjusted gross margin generated and t he proceeding is expected to result in additional adjusted gross margin of approximately $1.5 million in 2025 and $3.5 million annually thereafter.
Maryland Natural Gas Depreciation Study
In January 2024, our natural gas distribution businesses in Maryland 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.
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
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the Public Advocate was reached and approved by the Delaware PSC in June 2025 providing an annual revenue increase of $6.1 million, as well as dividing the rate case into two phases. Rates set to recover the approved components of the increase were effective in March 2025. In October 2025, a settlement among the Company, PSC staff and the Delaware Division of the Public Advocate was reached for Phase II of the rate case addressing tariff-related changes including rate design and approved by the Delaware Public Service Commission with rates effective as of October 15, 2025. For t he three and nine months ended September 30, 2025, there was $0.7 million and $2.9 million, respectively, of incremental adjusted gross margin generated and final rates are expected to generate approximately $4.5 million of adjusted gross margin in 2025 and $6.1 million in 2026.
FPU Electric Rate Case
In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million were approved with an effective date of November 1, 2024. In March 2025, the Florida PSC approved the permanent rate increase, but the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to resolve all outstanding issues in its current base rate case, which was filed as a joint motion for approval with the Florida PSC. This settlement which was approved by the Florida PSC in July 2025, provides for a total revenue increase of approximately $8.6 million on an annual basis, with $1.0 million of the increase deferred from the first year's base rate increase and recovered over three years. A step-up rate increase was also approved for up to $0.7 million, upon completion of the purchase and refurbishment of certain substations, which is expected in December 2026. The settlement was approved by the Florida PSC in July 2025. For the three and nine months ended September 30, 2025, there was $2.4 million and $5.2 million, respectively, of incremental adjusted gross margin generated and final rates are expected to generate approximately $7.1 million of adjusted gross margin in 2025 and $8.6 million in 2026.
Other Major Factors Influencing Adjusted Gross Margin
Weather Impact
Weather was not a significant factor to adjusted gross margin in the third quarter of 2025 compared to the same period in 2024.
For the nine months ended September 30, 2025, increased customer consumption, which includes the effects of colder weather conditions, largely in our Ohio and Delmarva service areas, compared to the prior-year period resulted in a $4.8 million increase in adjusted gross margin.
The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 2025 and 2024.
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| Three Months Ended |  |  |  | Nine Months Ended |  |
| September 30, |  |  |  | September 30, |  |
| 2025 |  | 2024 |  | Variance |  | 2025 |  | 2024 |  | Variance
Delmarva Peninsula |  |  |  |  |  |  |  |  |  |  |
Actual HDD | 4 |  |  | 6 |  |  | (2) |  |  | 2,505 |  |  | 2,287 |  |  | 218 |
10-Year Average HDD ("Normal") | 19 |  |  | 27 |  |  | (8) |  |  | 2,538 |  |  | 2,635 |  |  | (97) |
Variance from Normal | (15) |  |  | (21) |  |  |  |  | (33) |  |  | (348) |  |  |
Florida |  |  |  |  |  |  |  |  |  |  |
Actual HDD | 1 |  |  | — |  |  | 1 |  |  | 611 |  |  | 511 |  |  | 100 |
10-Year Average HDD ("Normal") | 1 |  |  | 1 |  |  | — |  |  | 526 |  |  | 512 |  |  | 14 |
Variance from Normal | — |  |  | (1) |  |  |  |  | 85 |  |  | (1) |  |  |
Florida City Gas |  |  |  |  |  |  |  |  |  |  |
Actual HDD | — |  |  | — |  |  | — |  |  | 310 |  |  | 231 |  |  | 79 |
10-Year Average HDD ("Normal") | — |  |  | — |  |  | — |  |  | 234 |  |  | 239 |  |  | (5) |
Variance from Normal | — |  |  | — |  |  |  |  | 76 |  |  | (8) |  |  |
Ohio |  |  |  |  |  |  |  |  |  |  |
Actual HDD | 107 |  |  | 43 |  |  | 64 |  |  | 3,881 |  |  | 3,180 |  |  | 701 |
10-Year Average HDD ("Normal") | 55 |  |  | 65 |  |  | (10) |  |  | 3,480 |  |  | 3,661 |  |  | (181) |
Variance from Normal | 52 |  |  | (22) |  |  |  |  | 401 |  |  | (481) |  |  |
Florida |  |  |  |  |  |  |  |  |  |  |
Actual CDD | 1,298 |  |  | 1,528 |  |  | (230) |  |  | 2,602 |  |  | 2,824 |  |  | (222) |
10-Year Average CDD ("Normal") | 1,429 |  |  | 1,420 |  |  | 9 |  |  | 2,624 |  |  | 2,615 |  |  | 9 |
Variance from Normal | (131) |  |  | 108 |  |  |  |  | (22) |  |  | 209 |  |  |

Natural Gas Distribution Growth
The average number of residential customers served on the Delmarva Peninsula increased by approximately 4.3 percent for both the three and nine months ended September 30, 2025. The average number of residential customers served by Florida Public Utilities Company increased by approximately 3.5 percent and 3.9 percent for the three and nine months ended September 30, 2025, respectively, while the average number of residential customers served by Florida City Gas increased by approximately 2.2 percent and 2.1 percent for the three and nine months ended September 30, 2025, respectively.
The details of the adjusted gross margin increase are provided in the following table:

| Three Months Ended |  | Nine Months Ended
| September 30, 2025 |  | September 30, 2025
(in millions) | Delmarva Peninsula |  | Florida |  | Delmarva Peninsula |  | Florida
Customer Growth: |  |  |  |  |  |  |
Residential | $ | 0.3 |  |  | $ | 0.6 |  |  | $ | 1.2 |  |  | $ | 2.4 |
Commercial and industrial | — |  |  | 0.6 |  |  | 0.2 |  |  | 1.7 |
Total Customer Growth | $ | 0.3 |  |  | $ | 1.2 |  |  | $ | 1.4 |  |  | $ | 4.1 |

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Regulated Energy Segment
For the quarter ended September 30, 2025 compared to the quarter ended September 30, 2024:

|  | Three Months Ended |  |
|  | September 30, |  |
|  | 2025 |  | 2024 |  | Change
(in millions) |  |  |  |  |  |
Revenue |  | $ | 146.4 |  |  | $ | 130.6 |  |  | $ | 15.8 |
Regulated natural gas and electric costs |  | 31.7 |  |  | 28.4 |  |  | 3.3 |
Adjusted gross margin (1) |  | 114.7 |  |  | 102.2 |  |  | 12.5 |
Operations & maintenance |  | 37.5 |  |  | 36.2 |  |  | (1.3) |
Depreciation, amortization and property taxes (2) |  | 26.9 |  |  | 19.8 |  |  | (7.1) |
Other taxes |  | 1.2 |  |  | 1.4 |  |  | 0.2 |
FCG transaction and transition-related expenses (3) |  | 0.2 |  |  | 0.8 |  |  | 0.6 |
Total operating expenses |  | 65.8 |  |  | 58.2 |  |  | (7.6) |
Operating income |  | $ | 48.9 |  |  | $ | 44.0 |  |  | $ | 4.9 |

(1) Adjusted Gross Margin is a non-GAAP measure utilized by management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.
(2) Includes the absence of an RSAM adjustment from FCG which represented a $3.2 million benefit in the third quarter of 2024.
(3) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees.
Operating income for the Regulated Energy segment for the third quarter of 2025 was $48.9 million, an increase of $4.9 million, or 11.1 percent, over the same period in 2024. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $4.3 million, or 9.6 percent, compared to the same period in 2024. Higher operating income reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects, and organic growth in our natural gas distribution businesses. Excluding the transaction and transition-related expenses described above, the increase in total operating expenses of $8.2 million was largely attributable to higher depreciation attributable to growth projects and the absence of a $3.2 million RSAM adjustment from FCG during the prior-year period and higher expenses associated with facilities, maintenance and outside services. These increases were partially offset by reduced payroll, benefits and other employee-related expenses during the quarter.
Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table:

(in millions) |  |
Natural gas transmission service expansions, including interim services | $ | 5.6 |  |
Contributions from regulated infrastructure programs | 3.9 |  |
Rate changes associated with recent rate case activities (1) | 3.6 |  |
Natural gas growth including conversions (excluding service expansions) | 1.5 |  |
Changes in customer consumption | (0.9) |  |
Other variances | (1.2) |  |
Quarter-over-quarter increase in adjusted gross margin | $ | 12.5 |  |

(1) Includes adjusted gross margin contributions from both interim and permanent base rates. Refer to Major Projects discussion for additional information.
The following narrative discussion provides further detail and analysis of the significant items in the table above:
Natural Gas Transmission Service Expansions, including interim services
We generated increased adjusted gross margin of $5.6 million for the three months ended September 30, 2025 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore.
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Contributions from Regulated Infrastructure Programs
Regulated infrastructure programs generated incremental adjusted gross margin of $3.9 million in the third quarter of 2025. The increase in adjusted gross margin was primarily related to FCG's SAFE program, Florida Natural Gas' GUARD program, Eastern Shore's Capital Cost Surcharge program, and FPU Electric's SPP. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.
Rate Changes Associated with Recent Rate Case Activities
Rate changes associated with the Delaware and Maryland natural gas rate cases and Florida Electric base rate case contributed additional adjusted gross margin of $3.6 million for the three months ended September 30, 2025. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.
Natural Gas Distribution Customer Growth
We generated additional adjusted gross margin of $1.5 million from natural gas customer growth. Adjusted gross margin increased by $1.2 million for our Florida natural gas distribution service territories and $0.3 million on the Delmarva Peninsula for the three months ended September 30, 2025, as compared to the same period in 2024, due to residential customer growth in Florida and on the Delmarva Peninsula, respectively, as well as growth attributable to commercial and industrial customers.
Changes in Customer Consumption
Customer consumption, inclusive of weather-related consumption, reduced adjusted gross margin by $0.9 million for the three months ended September 30, 2025.
Operating Expenses
Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table:

(in millions) |
Depreciation, amortization and property tax costs (1) | $ | (7.1) |
Facilities expenses, maintenance costs and outside services | (2.1) |
FCG transaction and transition-related expenses (2) | 0.6 |
Payroll, benefits and other employee-related expenses | 0.9 |
Other variances | 0.1 |
Quarter-over-quarter increase in operating expenses | $ | (7.6) |

(1) Includes the absence of an RSAM adjustment from FCG which represented a $3.2 million benefit in the third quarter of 2024.
(2) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to,
transition services, consulting, system integration, rebranding and legal fees.
For the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024:

|  | Nine Months Ended |  |
|  | September 30, |  |
|  | 2025 |  | 2024 |  | Change
(in millions) |  |  |  |  |  |
Revenue |  | $ | 497.8 |  |  | $ | 429.7 |  |  | $ | 68.1 |
Regulated natural gas and electric costs |  | 137.3 |  |  | 105.7 |  |  | 31.6 |
Adjusted gross margin (1) |  | 360.5 |  |  | 324.0 |  |  | 36.5 |
Operations & maintenance |  | 115.6 |  |  | 110.1 |  |  | (5.5) |
Depreciation, amortization and property taxes (2) |  | 78.3 |  |  | 63.6 |  |  | (14.7) |
Other taxes |  | 4.4 |  |  | 4.6 |  |  | 0.2 |
FCG transaction and transition-related expenses (3) |  | 1.0 |  |  | 3.1 |  |  | 2.1 |
Total operating expenses |  | 199.3 |  |  | 181.4 |  |  | (17.9) |
Operating income |  | $ | 161.2 |  |  | $ | 142.6 |  |  | $ | 18.6 |

(1) Adjusted Gross Margin is a non-GAAP measure utilized by management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.
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(2) Includes the absence of an RSAM adjustment from FCG which represented an $8.9 million benefit during the nine months ended September 30, 2024.
(3) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees.
Operating income for the Regulated Energy segment for the nine months ended September 30, 2025 was $161.2 million, an increase of $18.6 million or 13.0 percent, over the same period in 2024. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $16.5 million, or 11.3 percent, compared to the same period in 2024. Higher operating income reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects, and organic growth in our natural gas distribution businesses. Excluding the transaction and transition-related expenses described above, the increase in total operating expenses of $20.0 million was largely attributable to the absence of an $8.9 million RSAM adjustment from FCG during the prior-year period, higher depreciation attributable to growth projects and expenses associated with facilities, maintenance and outside services and insurance costs.
Items contributing to the period-over-period increase in adjusted gross margin are listed in the following table:

(in millions) |  |
Natural gas transmission service expansions, including interim services | $ | 11.7 |  |
Contributions from regulated infrastructure programs | 11.0 |  |
Rate changes associated with recent rate case activities (1) | 9.2 |  |
Natural gas growth including conversions (excluding service expansions) | 5.5 |  |
Changes in customer consumption | 0.9 |  |
Adjusted gross margin from off-system natural gas capacity sales | (0.7) |  |
Other variances | (1.1) |  |
Period-over-period increase in adjusted gross margin | $ | 36.5 |  |

(1) Includes adjusted gross margin contributions from both interim and permanent base rates. Refer to Major Projects discussion for additional information.
The following narrative discussion provides further detail and analysis of the significant items in the table above:
Natural Gas Transmission Service Expansions, including interim services
We generated increased adjusted gross margin of $11.7 million for the nine months ended September 30, 2025 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore.
Contributions from Regulated Infrastructure Programs
Regulated infrastructure programs generated incremental adjusted gross margin of $11.0 million for the nine months ended September 30, 2025. The increase in adjusted gross margin was primarily related to FCG's SAFE program, Florida's GUARD program, Eastern Shore's Capital Cost Surcharge program, and FPU Electric's SPP. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.
Rate Changes Associated with Recent Rate Case Activities
Rate changes associated with the Delaware and Maryland natural gas rate cases and Florida Electric base rate case contributed additional adjusted gross margin of $9.2 million for the nine months ended September 30, 2025. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.
Natural Gas Distribution Customer Growth
We generated additional adjusted gross margin of $5.5 million from natural gas customer growth. Adjusted gross margin increased by $4.1 million for our Florida natural gas distribution service territories and $1.4 million on the Delmarva Peninsula for the nine months ended September 30, 2025, as compared to the same period in 2024, due to residential customer growth in Florida and on the Delmarva Peninsula, as well as growth attributable to commercial and industrial customers.
Changes in Customer Consumption
Customer consumption, inclusive of weather-related consumption, increased adjusted gross margin by $0.9 million for the nine months ended September 30, 2025.
Adjusted Gross Margin from Off-system Natural Gas Capacity Sales
Fewer off-system natural gas capacity sales reduced adjusted gross margin by $0.7 million for the nine months ended September 30, 2025.
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Operating Expenses
Items contributing to the period-over-period increase in operating expenses are listed in the following table:

(in millions) |
Depreciation, amortization and property tax costs (1) | $ | (14.7) |
Facilities expenses, maintenance costs and outside services | (4.5) |
Insurance related costs | (1.1) |
FCG transaction and transition-related expenses (2) | 2.1 |
Other variances | 0.3 |
Period-over-period increase in operating expenses | $ | (17.9) |

(1) Includes the absence of an RSAM adjustment from FCG which represented an $8.9 million benefit during the nine months ended September 30, 2024.
(2) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to,
transition services, consulting, system integration, rebranding and legal fees.
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Unregulated Energy Segment
For the quarter ended September 30, 2025 compared to the quarter ended September 30, 2024:

|  | Three Months Ended |  |
|  | September 30, |  |
|  | 2025 |  | 2024 |  | Change
(in millions) |  |  |  |  |  |
Revenue |  | $ | 40.7 |  |  | $ | 35.6 |  |  | $ | 5.1 |
Unregulated propane and natural gas costs |  | 18.3 |  |  | 15.8 |  |  | 2.5 |
Adjusted gross margin (1) |  | 22.4 |  |  | 19.8 |  |  | 2.6 |
Operations & maintenance |  | 19.9 |  |  | 17.1 |  |  | (2.8) |
Depreciation, amortization and property tax costs |  | 5.8 |  |  | 5.1 |  |  | (0.7) |
Other taxes |  | 0.6 |  |  | 0.7 |  |  | 0.1 |
Total operating expenses |  | 26.3 |  |  | 22.9 |  |  | (3.4) |
Operating loss |  | $ | (3.9) |  |  | $ | (3.1) |  |  | $ | (0.8) |

(1) Adjusted Gross Margin is a non-GAAP measure utilized by management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.
Operating results for the Unregulated Energy segment for the third quarter of 2025 reflect a $0.8 million decrease compared to the same period in 2024. The increase in adjusted gross margin in the Unregulated Energy segment during the third quarter of 2025 was primarily driven by increased levels of CNG, RNG and LNG services and increased performance at Aspire Energy, partially offset by reduced margin per gallon and fees in our propane distribution business. Operating expenses increased due to higher payroll, benefits and employee-related expenses as well as increased facilities, maintenance and outside service costs compared to the prior-year period. Higher depreciation, amortization and property tax costs also contributed to the increase in operating expenses during the quarter.
Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table:

(in millions) |  |
Propane Operations |  |
Change in propane margins and service fees |  | $ | (0.7) |
CNG/RNG/LNG Transportation and Infrastructure |  |
Increased CNG/RNG/LNG services |  | 3.1 |
Aspire Energy |  |
Increased performance from Aspire Energy |  | 0.4 |
Other variances |  | (0.2) |
Quarter-over-quarter increase in adjusted gross margin |  | $ | 2.6 |

The following narrative discussion provides further detail and analysis of the significant items in the table above.
Propane Operations
•Change in propane margins and service fees - Adjusted g ross margin decreased by $0.7 million during the third quarter of 2025, mainly due to decreased margins and customer service fees. Market conditions, which include market pricing and competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices and can impact our margins.
CNG/RNG/LNG Transportation and Infrastructure
•Increased level of CNG, RNG and LNG services - Adjusted gross margin increased by $3.1 million during the third quarter of 2025 as compared to the same period in the prior year due to higher levels of CNG and RNG hold services and contributions from our Full Circle Dairy RNG facility.
Aspire Energy
•Increased performance from Aspire Energy - Adjusted gross margin increased by $0.4 million compared to the prior-
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year period.
Operating Expenses
Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table:

(in millions) |
Payroll, benefits and other employee-related expenses | $ | (1.5) |
Facilities expenses, maintenance costs and outside services | (1.3) |
Depreciation, amortization and property tax costs | (0.7) |
Other variances | 0.1 |
Quarter-over-quarter increase in operating expenses | $ | (3.4) |

For the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024:

|  | Nine Months Ended |  |
|  | September 30, |  |
|  | 2025 |  | 2024 |  | Change
(in millions) |  |  |  |  |  |
Revenue |  | $ | 195.3 |  |  | $ | 160.1 |  |  | $ | 35.2 |
Unregulated propane and natural gas costs |  | 93.4 |  |  | 70.9 |  |  | 22.5 |
Adjusted gross margin (1) |  | 101.9 |  |  | 89.2 |  |  | 12.7 |
Operations & maintenance |  | 62.1 |  |  | 54.5 |  |  | (7.6) |
Depreciation, amortization and property tax costs |  | 16.8 |  |  | 14.1 |  |  | (2.7) |
Other taxes |  | 2.1 |  |  | 1.9 |  |  | (0.2) |
Total operating expenses |  | 81.0 |  |  | 70.5 |  |  | (10.5) |
Operating income |  | $ | 20.9 |  |  | $ | 18.7 |  |  | $ | 2.2 |

(1) Adjusted Gross Margin is a non-GAAP measure utilized by management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.
Operating results for the Unregulated Energy segment for the nine months ended September 30, 2025 reflect a $2.2 million increase compared to the same period in 2024. The increase in adjusted gross margin in the Unregulated Energy segment during the first nine months of 2025 was primarily due to increased levels of CNG, RNG and LNG services as well as increased consumption in our propane distribution business and at Aspire Energy. These margin improvements were partially offset by lower margin per gallon and fees in our propane distribution business. The increase in operating expenses included higher payroll, benefits and other employee-related expenses, increased facilities, maintenance and outside service costs, and higher depreciation, amortization and property tax costs compared to the prior-year period.
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Items contributing to the period-over-period increase in adjusted gross margin are listed in the following table:

(in millions) |  |
Propane Operations |  |
Increased propane customer consumption |  | $ | 2.8 |
Change in propane margins and service fees |  | (1.3) |
CNG/RNG/LNG Transportation and Infrastructure |  |
Increased CNG/RNG/LNG services |  | 10.1 |
Aspire Energy |  |
Increased customer consumption |  | 1.1 |
Increased performance from Aspire Energy |  | 0.2 |
Other variances |  | (0.2) |
Period-over-period increase in adjusted gross margin |  | $ | 12.7 |

The following narrative discussion provides further detail and analysis of the significant items in the table above.
Propane Operations
•Propane customer consumption - Adjusted gross margin increased by $2.8 million due to increased customer consumption resulting primarily from colder year-over-year weather in our Delmarva service territory.
•Change in propane margins and service fees - Adjusted g ross margin decreased by $1.3 million for the nine months ended September 30, 2025, mainly due to decreased margins and customer service fees. Market conditions, which include market pricing and competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices and can impact our margins.
CNG/RNG/LNG Transportation and Infrastructure
•Increased level of CNG, RNG and LNG services - Adjusted gross margin increased by $10.1 million for the nine months ended September 30, 2025 as compared to the same period in the prior year due to higher levels of CNG and RNG hold services and contributions from our Full Circle Dairy RNG facility.
Aspire Energy
•Increased customer consumption - Adjusted gross margin increased by $1.1 million due to increased customer consumption during the current year primarily related to year-over-year colder weather in our Ohio service area.
•Increased performance from Aspire Energy - Adjusted gross margin increased by $0.2 million compared to the prior-year period.
Operating Expenses
Items contributing to the period-over-period increase in operating expenses are listed in the following table:

(in millions) |
Payroll, benefits and other employee-related expenses | $ | (3.9) |
Facilities expenses, maintenance costs and outside services | (3.7) |
Depreciation, amortization and property tax costs | (2.7) |
Other variances | (0.2) |
Period-over-period increase in operating expenses | $ | (10.5) |

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O THER I NCOME, N ET
For the quarter ended September 30, 2025 compared to the quarter ended September 30, 2024
Other income, net, which includes non-operating investment income, interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, amounted to $0.2 million in the third quarter of 2025 compared to $0.5 million during the prior-year period.
For the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024
Other income, net, was $1.2 million for the nine months ended September 30, 2025 compared to $1.7 million during the prior-year period.
I NTEREST CHARGES
For the quarter ended September 30, 2025 compared to the quarter ended September 30, 2024
Interest charges for the three months ended September 30, 2025 increased by $1.1 million compared to the same period in 2024, attributable primarily to the Senior Notes issued in November 2024 and in August and September 2025. Increased interest expense was partially offset by lower average outstanding Revolver borrowings and weighted-average interest rate compared to the prior-year period. The weighted-average interest rate on our Revolver borrowings was 5.0 percent for the three months ended September 30, 2025 compared to 5.8 percent during the prior-year period.
For the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024
Interest charges for the nine months ended September 30, 2025 increased by $3.2 million compared to the same period in 2024, attributable primarily to the Senior Notes issued in November 2024 and in August and September 2025. Increased interest expense was partially offset by lower average outstanding Revolver borrowings and weighted-average interest rate compared to the prior-year period. The weighted-average interest rate on our Revolver borrowings was 5.1 percent for the nine months ended September 30, 2025 compared to 5.8 percent during the prior-year period.
INCOME TAXES
For the quarter ended September 30, 2025 compared to the quarter ended September 30, 2024
Income tax expense was $7.6 million and $6.8 million for the quarters ended September 30, 2025 and September 30, 2024, respectively, resulting in an effective income tax rate of 28.1 percent and 27.9 percent, respectively, during the periods then ended.
For the nine months ended September 30, 2025 compared to the nine months ended September 30, 2024
Income tax expense was $35.0 million and $30.2 million for the nine months ended September 30, 2025 and September 30, 2024, respectively, resulting in an effective income tax rate of 27.1 percent and 26.9 percent, respectively, during the periods then ended.
F INANCIAL P OSITION, L IQUIDITY AND C APITAL R ESOURCES
Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures, which we believe will provide sufficient liquidity to fund our current obligations, debt service requirements and capital expenditures over the next twelve months.
We may also issue long-term debt and equity to fund capital expenditures and to maintain our capital structure within our target capital structure range. We maintain effective shelf registration statements with the SEC for the issuance of common stock in various types of equity offerings, including pursuant to our DRIP and ATM program. Depending on our capital needs and subject to market conditions, we may issue additional shares under the DRIP in addition to other possible debt and equity offerings.
Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered by our distribution operations, and our natural gas transmission operations to customers during the peak-heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $335.6 million for the nine months ended September 30, 2025.
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In the table below, we have provided the range of our forecasted capital expenditures for 2025:

| 2025
(in millions) | Low |  | High
Regulated Energy: |  |  |
Natural gas distribution | $ | 170.0 |  |  | $ | 175.0 |
Natural gas transmission | 170.0 |  |  | 175.0 |
Electric distribution | 35.0 |  |  | 40.0 |
Total Regulated Energy | 375.0 |  |  | 390.0 |
Unregulated Energy: |  |  |
Propane distribution | 12.0 |  |  | 15.0 |
Energy transmission | 8.0 |  |  | 10.0 |
Other unregulated energy | 12.0 |  |  | 15.0 |
Total Unregulated Energy | 32.0 |  |  | 40.0 |
Other: |  |  |
Corporate and other businesses | 18.0 |  |  | 20.0 |
Total 2025 Forecasted Capital Expenditures | $ | 425.0 |  |  | $ | 450.0 |

The capital expenditure projection is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing political and economic conditions, supply chain disruptions, capital delays that are greater than currently anticipated, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital and other factors discussed in Item 1A., Risk Factors, in our 2024 Annual Report on Form 10-K. At September 30, 2025, the Company further increased and refined its 2025 capital guidance range to $425.0 million to $450.0 million given progress on its capital projects. The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.
Capital Structure
We are committed to maintaining a sound capital structure and strong credit ratings. This commitment, along with adequate and timely rate relief for our regulated energy operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost, which will benefit our customers, creditors, employees and stockholders.
The following table presents our capitalization, excluding and including short-term borrowings, as of September 30, 2025 and December 31, 2024:

|  | September 30, 2025 |  | December 31, 2024
(in millions) |  |  |  |  |  |  |  |
Long-term debt, net of current maturities |  | $ | 1,437.9 |  |  | 49 | % |  | $ | 1,261.7 |  |  | 48 | %
Stockholders’ equity |  | 1,518.7 |  |  | 51 | % |  | 1,390.2 |  |  | 52 | %
Total capitalization, excluding short-term debt |  | $ | 2,956.6 |  |  | 100 | % |  | $ | 2,651.9 |  |  | 100 | %
|  | September 30, 2025 |  | December 31, 2024
(in millions) |  |  |  |  |  |  |  |
Short-term debt |  | $ | 95.8 |  |  | 3 | % |  | $ | 196.5 |  |  | 7 | %
Long-term debt, including current maturities |  | 1,472.4 |  |  | 48 | % |  | 1,287.2 |  |  | 45 | %
Stockholders’ equity |  | 1,518.7 |  |  | 49 | % |  | 1,390.2 |  |  | 48 | %
Total capitalization, including short-term debt |  | $ | 3,086.9 |  |  | 100 | % |  | $ | 2,873.9 |  |  | 100 | %

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was 49 percent as of September 30, 2025, as the Company continues to remain focused on moving back closer to this target ratio. In the last twelve months, the Company has issued $92.0 million of new equity via the DRIP and ATM program, representing 729 thousand incremental shares.
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We seek to align permanent financing with the in-service dates of our capital projects. We may utilize more temporary short-term debt when the financing cost is attractive as a bridge to the permanent long-term financing or if the equity markets are volatile.
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 nine months ended September 30, 2025 and 2024, we received net proceeds of $76.3 million and $56.8 million, respectively, associated with shares issued under the DRIP as well as shares issued under our ATM program.
Shelf Agreements
We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026 and June 2030, respectively, however neither of such lenders have any obligation to purchase debt thereunder. In June 2025, we amended our Shelf Agreement with MetLife to expand the total borrowing capacity and extend the term of the agreement for an additional five years. At September 30, 2025, a total of $305.0 million of borrowing capacity was available under these Shelf Agreements.
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.
Short-term Borrowings
As of September 30, 2025, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At September 30, 2025 and December 31, 2024, we had $95.8 million and $196.5 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.96 percent and 5.06 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at September 30, 2025.
In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche and $200.0 million available under the five-year tranche which expires in August 2029. In August 2025, we exercised an option under the Revolver to extend the 364-day tranche through August 2026. All other terms and conditions of the agreement remain unchanged. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be subject to a pricing grid, including the commitment fee and the interest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. The 364-day tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion.
We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 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 September 30, 2025, we were in compliance with this covenant.
Our total available credit under the Revolver at September 30, 2025 was $349.9 million. As of September 30, 2025, we had issued $4.3 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.
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Long-Term Debt
In August 2025, we entered into a Note Purchase Agreement for the issuance of Senior Notes in the aggregate principal amount of $200.0 million with an initial funding of $150.0 million in August 2025 and an additional $50.0 million in September 2025. These Senior Notes have an average interest rate of 5.04 percent consisting of $60.0 million of 4.88 percent notes due in August 2028, $50.0 million of 5.02 percent notes due in September 2030, and $90.0 million of 5.16 percent notes due in August 2031. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. The outstanding principal balance of the Senior Notes will be due on their respective maturity dates with interest payments payable semiannually beginning in 2026 until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes.
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 which began in 2025.
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the nine months ended September 30, 2025 and 2024:

|  | Nine Months Ended
|  | September 30,
(in millions) |  | 2025 |  | 2024
Net cash provided by (used in): |  |  |  |
Operating activities |  | $ | 198.3 |  |  | $ | 217.7 |
Investing activities |  | (318.2) |  |  | (256.0) |
Financing activities |  | 113.8 |  |  | 35.0 |
Net decrease in cash and cash equivalents |  | (6.1) |  |  | (3.3) |
Cash and cash equivalents—beginning of period |  | 7.9 |  |  | 4.9 |
Cash and cash equivalents—end of period |  | $ | 1.8 |  |  | $ | 1.6 |

Cash Flows Provided by Operating Activities
Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items such as depreciation and amortization, changes in deferred income taxes, share-based compensation expense and working capital. Working capital requirements are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.
During the nine months ended September 30, 2025, net cash provided by operating activities was $198.3 million. Operating cash flows were primarily impacted by the following:
•Net income, adjusted for non-cash adjustments, provided a $175.6 million source of cash;
•An increased level of deferred taxes associated largely with incremental tax depreciation from growth investments resulted in a source of cash of $43.3 million;
•Changes in net regulatory assets and liabilities due primarily to the change in fuel costs collected through the various cost recovery mechanisms resulted in a $17.0 million use of cash; and
•Other working capital changes resulted in a $3.5 million use of cash.
Cash Flows Used in Investing Activities
Net cash used in investing activities totaled $318.2 million during the nine months ended September 30, 2025, attributable to $322.2 million related to new capital expenditures partially offset by proceeds from asset sales of $4.0 million.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities totaled $113.8 million during the nine months ended September 30, 2025 and was largely impacted by the following:
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•Net proceeds of $184.6 million from long-term debt issuances and repayments;
•Net proceeds of $76.1 million from the issuance of stock;
•Net repayments under the Revolver of $103.5 million; and
•A $44.8 million use of cash for dividend payments in 2025.
Off-Balance Sheet Arrangements
Our BOD has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of September 30, 2025 was $40.0 million. The aggregate amount guaranteed related to our subsidiaries at September 30, 2025 was $30.4 million, with the guarantees expiring on various dates through September 30, 2026. In addition, the BOD authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at September 30, 2025 was $4.0 million.
As of September 30, 2025, we have issued letters of credit totaling $4.3 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 throu gh April 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. Additional information is presented in Note 7, Other Commitments and Contingencies, in the condensed consolidated financial statements.
Contractual Obligations
There has been no material change in the contractual obligations presented in our 2024 Annual Report on Form 10-K.
Rates and Regulatory Matters
Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore 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. We regularly are involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 5, Rates and Other Regulatory Activities, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments, applicable to us, and their expected impact on our financial position, results of operations and cash flows, are described in Note 1, Summary of Accounting Policies, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Recent International Trade Developments
Recently, significant trade tariffs were enacted and proposed to be enacted through presidential executive orders affecting products exported by a number of U.S. trading partners. While some tariffs scheduled to take effect were temporarily suspended, broad tariffs remain in effect with the possibility of additional tariffs being imposed. Trade tariffs are likely to increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. For example, the cost of pipes, meters, transformers, and specialized equipment we use in our capital projects may materially increase thus increasing our overall investment in and cost of these projects. We are currently unable to predict the effects of the recently imposed and possible future tariffs on our business.
Additionally, the current presidential administration has directed various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion, commentary and actions regarding potential significant changes to U.S. trade policies, treaties and tariffs. In 2025, the President indicated that the United States would impose retaliatory measures with respect to jurisdictions that have or are likely to put in place tax rules that are extraterritorial or disproportionately affect U.S. companies. The likelihood of these changes being enacted or implemented is unclear. We are currently unable to predict whether such changes will occur and, if so, their ultimate impact on our businesses. We are also unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, which could include project delays, cost increases, and obstacles to the Company’s strategic plan execution. We are closely monitoring the impacts of trade tariffs and the potential effect they may have on the Company’s financial position, results of operations, or cash flows.
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Item 3. Quantitative and Qualitative Disclosures about Market Risk
I NTEREST R ATE R ISK
Long-term debt is subject to potential losses based on changes in interest rates. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. Increases in interest rates expose us to potential increased costs we could incur when we (i) issue new debt instruments or (ii) provide financing and liquidity for our business activities. We also utilize interest rate swap agreements to mitigate short-term borrowing rate risk. Additional information about our long-term debt and short-term borrowing is disclosed in Note 14, Long-Term Debt, and Note 15, Short-Term Borrowings, respectively, in the condensed consolidated financial statements.
C OMMODITY P RICE R ISK
Regulated Energy Segment
We have entered into agreements with various wholesale suppliers to purchase natural gas and electricity for resale to our customers. Our regulated energy distribution businesses that sell natural gas or electricity to end-use customers have fuel cost recovery mechanisms authorized by the respective PSCs that allow us to recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.
Unregulated Energy Segment
Our propane operations are exposed to commodity price risk as a result of the competitive nature of retail pricing offered to our customers. In order to mitigate this risk, we utilize propane storage activities and forward contracts for supply.
We can store up to approximately 8.5 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.
Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers in order to fulfill our natural gas purchase requirements.
The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2024 to September 30, 2025:

(in millions) | Balance at December 31, 2024 |  | Increase in Fair Market Value |  | Less Amounts Settled |  | Balance at September 30, 2025
Sharp | $ | 0.6 |  |  | $ | — |  |  | $ | (0.8) |  |  | $ | (0.2) |

There were no changes in methods of valuations during the nine months ended September 30, 2025.
The following is a summary of fair market value of financial derivatives as of September 30, 2025, by method of valuation and by maturity for each fiscal year period.

(in millions) | 2025 |  | 2026 |  | 2027 |  | 2028 |  | Total Fair Value
Price based on Mont Belvieu - Sharp | $ | (0.1) |  |  | $ | (0.1) |  |  | $ | — |  |  | $ | — |  |  | $ | (0.2) |

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W HOLESALE C REDIT R ISK
The Risk Management Committee reviews credit risks associated with counterparties to commodity derivative contracts prior to such contracts being approved.
Additional information about our derivative instruments is disclosed in Note 12, Derivative Instruments, in the condensed consolidated financial statements.
I NFLATION
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. To help cope with the effects of inflation on our capital investments and returns, we periodically seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated energy business operations. To compensate for fluctuations in propane gas prices, we adjust propane sales prices to the extent allowed by the market.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2025. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2025.
Changes in Internal Control over Financial Reporting
During the quarter ended September 30, 2025, there has been no change in the design or operations of our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
Item 1. Legal Proceedings
As disclosed in Note 7, Other Commitments and Contingencies, of the condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our consolidated results of operations, financial position or cash flows.
Item 1A. Risk Factors
Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, Item 1A., Risk Factors, in our Annual Report on Form 10-K, for the year ended December 31, 2024, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating Chesapeake Utilities, our business and the forward-looking statements contained in this Quarterly Report on Form 10-Q.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
Company Purchases of Equity Securities
Share repurchases during the three months ended September 30, 2025 were as follows:

|  | Total Number of Shares |  | Average Price Paid |  | Total Number of Shares Purchased as Part of Publicly Announced Plans |  | Maximum Number of Shares That May Yet Be Purchased Under the Plans
Period |  | Purchased |  | per Share |  | or Programs (2) |  | or Programs (2)
July 1, 2025 through July 31, 2025 (1) |  | 712 |  |  | $ | 122.44 |  |  | — |  |  | — |
August 1, 2025 through August 31, 2025 |  | — |  |  | — |  |  | — |  |  | — |
September 1, 2025 through September 30, 2025 |  | — |  |  | — |  |  | — |  |  | — |
Total |  | 712 |  |  | $ | 122.44 |  |  | — |  |  | — |

(1) Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts for certain directors and senior executives under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2024.
(2) Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares.
Item 3. Defaults upon Senior Securities
None.
Item 5. Other Information
During the three months ended September 30, 2025, no director or officer of the Company adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.
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Item 6. Exhibits

10.1 |  | Note Purchase Agreement, dated August 1, 2025, by and among Chesapeake Utilities Corporation and the purchasers thereto (incorporated by reference to the Company's Current Report in Form 8-K filed with the SEC on August 7, 2025).
31.1* |  | Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2* |  | Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1** |  | Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
32.2** |  | Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
101.INS* |  | XBRL Instance Document.
101.SCH* |  | XBRL Taxonomy Extension Schema Document.
101.CAL* |  | XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF* |  | XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB* |  | XBRL Taxonomy Extension Label Linkbase Document.
101.PRE* |  | XBRL Taxonomy Extension Presentation Linkbase Document.
104 |  | Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101

* Filed herewith
** Furnished, not filed
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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

C HESAPEAKE U TILITIES C ORPORATION
/S/ B ETH W. C OOPER
Beth W. Cooper Executive Vice President, Chief Financial Officer, Treasurer and Assistant Corporate Secretary

Date: November 6, 2025
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