10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, 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: March 31, 2026

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 

CHESAPEAKE UTILITIES CORPORATION

(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	☐

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 — 24,004.761 shares outstanding as of May 4, 2026.

Table of Contents

PART I—FINANCIAL INFORMATION		1
ITEM 1.	FINANCIAL STATEMENTS	1
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	27
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	49
ITEM 4.	CONTROLS AND PROCEDURES	50
PART II—OTHER INFORMATION		50
ITEM 1.	LEGAL PROCEEDINGS	50
ITEM 1A.	RISK FACTORS	51
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	51
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	51
ITEM 5.	OTHER INFORMATION	51
ITEM 6.	EXHIBITS	52
SIGNATURES		53

GLOSSARY OF DEFINITIONS

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/DSPP: 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 are 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

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

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

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

	Three Months Ended
	March 31,
	2026		2025
(in millions, except shares (thousands) and per share data)
Operating Revenues
Regulated Energy	$	249.3	$	199.6
Unregulated Energy	113.7		106.7
Other Businesses and Eliminations	(9.9)		(7.6)
Total Operating Revenues	353.1		298.7
Operating Expenses
Regulated natural gas and electric costs	101.6		71.5
Unregulated propane and natural gas costs	45.3		44.8
Operations	67.3		58.0
Maintenance	8.0		5.4
Depreciation and amortization	21.5		22.5
Other taxes	10.0		9.4
FCG transaction and transition-related expenses	—		0.3
Total Operating Expenses	253.7		211.9
Operating Income	99.4		86.8
Other income, net	—		0.6
Interest charges	18.7		18.1
Income Before Income Taxes	80.7		69.3
Income taxes	21.4		18.4
Net Income	$	59.3	$	50.9
Weighted Average Common Shares Outstanding:
Basic	23,937		22,957
Diluted	24,053		23,041
Earnings Per Share of Common Stock:
Basic	$	2.48	$	2.22
Diluted	$	2.47	$	2.21

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

1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended
	March 31,
	2026		2025
(in millions)
Net Income	$	59.3	$	50.9
Other Comprehensive Income (Loss), net of tax:
Cash Flow Hedges, net of tax:
Net gain on commodity contract cash flow hedges, net of tax of $0.4 and $0.2, respectively	1.1		0.7
Reclassifications of net (gain) loss on commodity contract cash flow hedges, net of tax of $0.0 and $(0.2), respectively	0.1		(0.5)
Net loss on interest rate swap cash flow hedges, net of tax of $0.0 and $(0.2), respectively	—		(0.7)
Reclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $0.0 and $0.0, respectively	—		(0.1)
Total Other Comprehensive Income (Loss), net of tax	1.2		(0.6)
Comprehensive Income	$	60.5	$	50.3

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

2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	March 31, 2026		December 31, 2025
(in millions, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	3,009.0	$	2,941.6
Unregulated Energy	507.2		492.4
Other Businesses and Eliminations	39.3		38.3
Total property, plant and equipment	3,555.5		3,472.3
Less: Accumulated depreciation and amortization	(652.1)		(637.6)
Plus: Construction work in progress	320.5		283.7
Net property, plant and equipment	3,223.9		3,118.4
Current Assets
Cash and cash equivalents	4.7		1.8
Trade and other receivables	120.7		106.9
Less: Allowance for credit losses	(6.8)		(5.4)
Trade and other receivables, net	113.9		101.5
Accrued revenue	49.0		50.1
Propane inventory, at average cost	8.2		8.8
Other inventory, at average cost	17.1		17.9
Regulatory assets	24.5		29.7
Storage gas prepayments	0.7		4.5
Prepaid expenses	17.0		19.7
Derivative assets, at fair value	0.8		—
Other current assets	3.2		3.0
Total current assets	239.1		237.0
Deferred Charges and Other Assets
Goodwill	507.5		507.5
Other intangible assets, net	12.9		13.2
Investments, at fair value	16.4		17.2
Derivative assets, at fair value	0.1		—
Operating lease right-of-use assets	9.4		9.9
Regulatory assets	73.7		74.3
Receivables and other deferred charges	12.9		17.3
Total deferred charges and other assets	632.9		639.4
Total Assets	$	4,095.9	$	3,994.8

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

3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	March 31, 2026		December 31, 2025
(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 75,000,000 shares)	11.7		11.6
Additional paid-in capital	972.2		962.8
Retained earnings	669.3		626.8
Accumulated other comprehensive loss	(1.5)		(2.7)
Deferred compensation obligation	17.4		12.6
Treasury stock	(17.4)		(12.6)
Total stockholders’ equity	1,651.7		1,598.5
Long-term debt, net of current maturities	1,325.3		1,327.1
Total capitalization	2,977.0		2,925.6
Current Liabilities
Current portion of long-term debt	134.6		134.6
Short-term borrowing	199.6		158.0
Accounts payable	101.1		115.2
Customer deposits and refunds	41.8		45.1
Accrued interest	17.6		8.7
Dividends payable	16.4		16.4
Accrued compensation	10.5		21.6
Regulatory liabilities	11.6		14.5
Derivative liabilities, at fair value	0.2		0.8
Other accrued liabilities	20.3		15.0
Total current liabilities	553.7		529.9
Deferred Credits and Other Liabilities
Deferred income taxes	333.7		313.3
Regulatory liabilities	188.8		188.1
Environmental liabilities	3.0		2.9
Other pension and benefit costs	13.1		14.0
Derivative liabilities, at fair value	0.5		0.6
Operating lease - liabilities	7.5		7.9
Deferred investment tax credits and other liabilities	18.6		12.5
Total deferred credits and other liabilities	565.2		539.3
Environmental and other commitments and contingencies (Notes 6 and 7)
Total Capitalization and Liabilities	$	4,095.9	$	3,994.8

    

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

4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2026		2025
(in millions)
Operating Activities
Net income	$	59.3	$	50.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21.5		22.5
Depreciation and accretion included in other costs	4.3		4.0
Deferred income taxes	20.0		16.5
Realized loss on commodity contracts and sale of assets	—		(1.1)
Unrealized loss on investments and commodity contracts	0.4		0.4
Employee benefits and compensation	0.1		—
Share-based compensation	3.5		2.3
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(11.3)		(13.9)
Propane inventory, storage gas and other inventory	5.2		1.6
Regulatory assets and liabilities, net	1.4		3.6
Prepaid expenses and other current assets	1.3		1.6
Accounts payable and other accrued liabilities	9.4		2.9
Income taxes receivable	5.0		1.9
Customer deposits and refunds	(3.2)		(3.7)
Accrued compensation	(11.5)		(14.6)
Accrued interest	8.9		11.4
Other assets and liabilities, net	3.7		(1.3)
Net cash provided by operating activities	118.0		85.0
Investing Activities
Property, plant and equipment expenditures	(141.9)		(113.8)
Proceeds from sale of assets	0.1		0.6
Environmental expenditures	0.1		0.1
Net cash used in investing activities	(141.7)		(113.1)
Financing Activities
Common stock dividends	(16.2)		(14.5)
Proceeds from issuance of common stock, net of expenses	5.2		19.8
Tax withholding payments related to net settled stock compensation	(2.0)		(1.0)
Change in cash overdrafts due to outstanding checks	(0.4)		(1.7)
Net borrowings under line of credit agreements	42.0		20.3
Repayment of long-term debt and finance lease obligation	(2.0)		(2.0)
Net cash provided by financing activities	26.6		20.9
Net Increase (Decrease) in Cash and Cash Equivalents	2.9		(7.2)
Cash and Cash Equivalents—Beginning of Period	1.8		7.9
Cash and Cash Equivalents—End of Period	$	4.7	$	0.7

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

5

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 December 31, 2024	22,899	$	11.1	$	830.5	$	550.3	$	(1.7)	$	9.8	$	(9.8)	$	1,390.2
Net income	—	—		—		50.9		—		—		—		50.9
Other comprehensive loss	—	—		—		—		(0.6)		—		—		(0.6)
Dividends declared ($0.640 per share)	—	—		—		(14.8)		—		—		—		(14.8)
Issuance under various plans (3)	161	0.1		19.7		—		—		—		—		19.8
Share-based compensation and tax benefit (4) (5)	29	—		1.8		—		—		—		—		1.8
Treasury stock activities (2)	—	—		—		—		—		2.4		(2.4)		—
Balance at March 31, 2025	23,089	$	11.2	$	852.0	$	586.4	$	(2.3)	$	12.2	$	(12.2)	$	1,447.3
Balance at December 31, 2025	23,896	$	11.6	$	962.8	$	626.8	$	(2.7)	$	12.6	$	(12.6)	$	1,598.5
Net income	—	—		—		59.3		—		—		—		59.3
Other comprehensive loss	—	—		—		—		1.2		—		—		1.2
Dividends declared ($0.685 per share)	—	—		—		(16.8)		—		—		—		(16.8)
Issuance under various plans and ATM program (3)	55	0.1		6.9		—		—		—		—		7.0
Share-based compensation and tax benefit (4) (5)	52	—		2.5		—		—		—		—		2.5
Treasury stock activities (2)	—	—		—		—		—		4.8		(4.8)		—
Balance at March 31, 2026	24,003	$	11.7	$	972.2	$	669.3	$	(1.5)	$	17.4	$	(17.4)	$	1,651.7

(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 158 thousand, 129 thousand, 126 thousand, and 114 thousand shares at March 31, 2026, December 31, 2025, March 31, 2025 and December 31, 2024, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

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

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

(5)The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended March 31, 2026 and 2025, we withheld 15 thousand and 8 thousand shares, respectively, for employee taxes.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

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, 2025. 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

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.

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

Interim Reporting (ASC 270) - In December 2025, the FASB issued ASU 2025-11, Narrow-Scope Improvements. The update clarifies the scope and content requirements for interim financial reporting. It will not fundamentally change

7

existing interim disclosure requirements but improves the navigability of the guidance. ASU 2025-11 will be effective for our interim and annual financial statements beginning January 1, 2028. ASU 2025-11 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

Federal Statute Updates

In July 2025, the One Big Beautiful Bill Act (referred to as the "OBBBA") was signed into law. The comprehensive legislative package includes, among other topics, significant tax law changes and regulatory compliance updates with various effective dates, including provisions related to the reinstatement of bonus depreciation for non-regulated qualified property, limitations of interest expense deductions, and modified provisions of the inflation Reduction Act related to production and investment tax credits. The Company expects the provisions of the OBBBA to have a net favorable impact on its income tax position over the long term, primarily due to accelerated tax benefits associated with qualifying capital investments.

2.    Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2026		2025
(dollars in millions, shares in thousands (except per share data))
Calculation of Basic Earnings Per Share:
Net Income	$	59.3	$	50.9
Weighted average shares outstanding	23,937		22,957
Basic Earnings Per Share	$	2.48	$	2.22
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic	23,937		22,957
Effect of dilutive securities—Share-based compensation	116		84
Adjusted denominator—Diluted	24,053		23,041
Diluted Earnings Per Share	$	2.47	$	2.21

3.     Acquisitions

There were no acquisitions completed during 2025 or during the three months ended March 31, 2026. The Company’s consolidated results include certain transaction and transition-related expenses for the three months ended March 31, 2025 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, 2025 for additional details on the FCG acquisition.

8

4.     Revenue Recognition

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following tables display our revenue by major source based on product and service type for the three months ended March 31, 2026 and 2025:

	Three Months Ended March 31, 2026								Three Months Ended March 31, 2025
(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 distribution	$	54.1	$	—	$	—	$	54.1	$	42.3	$	—	$	—	$	42.3
FPU natural gas distribution	58.9		—		—		58.9		51.3		—		—		51.3
Florida City Gas	65.6		—		—		65.6		43.6		—		—		43.6
FPU electric distribution	27.6		—		—		27.6		23.2		—		—		23.2
Maryland natural gas distribution (1)	28.4		—		—		28.4		25.3		—		—		25.3
Total energy distribution	234.6		—		—		234.6		185.7		—		—		185.7
Energy transmission
Aspire Energy	—		26.3		—		26.3		—		19.2		—		19.2
Aspire Energy Express	0.4		—		—		0.4		0.4		—		—		0.4
Eastern Shore	24.2		—		—		24.2		22.7		—		—		22.7
Peninsula Pipeline	16.8		—		—		16.8		10.0		—		—		10.0
Total energy transmission	41.4		26.3		—		67.7		33.1		19.2		—		52.3
Energy generation
Eight Flags	—		5.9		—		5.9		—		4.7		—		4.7
Propane operations
Propane delivery operations	—		73.3		—		73.3		—		74.7		—		74.7
CNG / RNG Services
Marlin Gas Services	—		7.4		—		7.4		—		7.2		—		7.2
Other RNG	—		0.9		—		0.9		—		1.0		—		1.0
Total CNG / RNG Services	—		8.3		—		8.3		—		8.2		—		8.2
Other Businesses and Eliminations
Eliminations	(26.7)		(0.1)		(9.9)		(36.7)		(19.2)		(0.1)		(7.6)		(26.9)
Total operating revenues (2)	$	249.3	$	113.7	$	(9.9)	$	353.1	$	199.6	$	106.7	$	(7.6)	$	298.7

(1) In accordance with the Maryland PSC approval of our natural gas base rate proceeding, effective April 2025, our natural gas distribution businesses in Maryland (Maryland natural gas division, Sandpiper 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 March 31, 2026 include other revenue (revenues from sources other than contracts with customers) of $1.5 million loss and $0.1 million for our Regulated Energy and Unregulated Energy segments, respectively, and $0.5 million loss and $0.1 million for our Regulated Energy and Unregulated Energy segments, respectively, for the three months ended March 31, 2025. 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, 2025 and March 31, 2026 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in millions)
Balance at 12/31/2025	$	92.2	$	—	$	2.9	$	1.3
Balance at 3/31/2026	108.6		—		2.8		1.0
Increase (Decrease)	$	16.4	$	—	$	(0.1)	$	(0.3)

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

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the condensed consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective customer retail program on a ratable basis. For the three months ended March 31, 2026 and 2025, the amounts recognized in revenue were not material.

Remaining Performance Obligations

Certain of our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations, at March 31, 2026, are expected to be recognized as follows:

(in millions)	2026		2027		2028		2029		2030		2031		2032 and thereafter
Eastern Shore and Peninsula Pipeline	$	29.5	$	36.5	$	34.1	$	31.4	$	25.3	$	18.4	$	142.5
Natural gas distribution operations	9.3		9.7		9.8		9.7		9.7		4.9		24.7
FPU electric distribution	0.7		0.9		0.9		0.9		0.9		0.9		—
Total revenue contracts with remaining performance obligations	$	39.5	$	47.1	$	44.8	$	42.0	$	35.9	$	24.2	$	167.2

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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. In connection with the application we sought approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective in October 2024. A settlement among all interested parties 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 and approved tariff-related changes including rate design were 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 September 2024, the Maryland Public Utility Judge approved a $2.6 million increase in annual base rates, which was followed by the Company submitting 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. In March 2025 the 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.

Florida

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

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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 Florida Supreme Court has yet to rule on the case.

The RSAM was recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM was calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve month regulatory base net operating income, which primarily included the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items was adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. At December 31, 2024, the RSAM reserve was 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. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets.

Florida City Gas Rate Case: In April 2026, FCG filed a petition with the Florida PSC. In connection with the application, we are seeking approval of the following: (i) interim rate relief of approximately $16.2 million, subject to refund, pending the outcome of the rate case proceeding; (ii) general base rate increase of $46.9 million with a ROE of 11.25 percent based on a 2027 projected test year; (iii) reclassification of approximately $16.4 million in the existing SAFE program revenues from surcharge recovery to base rates; (iv) authorization to retain the unamortized portion of the previously approved acquisition adjustment; and (v) further implementation of the advanced metering infrastructure (“AMI”). The outcome of the application will be subject to review and approval by the Florida PSC.

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 enable FCG to accelerate remediation related to problematic pipe and facilities consisting of obsolete and exposed pipe. These modifications will improve the safety and reliability of service to FCG's customers and result in an estimated additional $50.0 million in capital expenditures associated with the SAFE Program, increasing the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.

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

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

Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operation’s initial SPP plan was filed 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.

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. This settlement which was approved by the Florida PSC in July 2025, provided 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 to be completed in December 2026.

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 second quarter of 2026.

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

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

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

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Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements. The projects are underway and are estimated to be completed in the second half of 2026.

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

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.

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.

In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025. Construction commenced shortly after approval and is well underway. The weather during the first quarter resulted in several brief slowdowns which had a cumulative impact on the overall timeline. Project construction and commissioning are expected to be complete in the latter part of the year with the FERC approval process to immediately follow. The Company expects to receive full approval for in-service of the facility by the beginning of 2027.

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

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

In March 2026, 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 a slight decrease to the revenue requirement of the currently effective surcharge as a result of the true-up. The FERC issued an order approving the surcharge as filed effective April 1, 2026.

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

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taxes (“ADIT”) associated with the TCJA amounted to $83.1 million and $83.4 million at March 31, 2026 and December 31, 2025, respectively. With the exception of the ADIT balance of $34.2 million attributable to Eastern Shore, such amounts are being amortized in accordance with approvals received from the Delaware, Maryland, and Florida PSCs in 2018 and 2019. The ADIT balance attributable to Eastern Shore will be addressed in its next rate case filing.

6. Environmental Commitments and Contingencies

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

MGP Sites

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

As of March 31, 2026 and December 31, 2025, we had approximately $3.3 million and $3.1 million, respectively, in environmental liabilities related to the former MGP sites, and related regulatory assets of approximately $0.2 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 and west parcels of our West Palm Beach, Florida, site. These properties were sold to another party in December 2025, and no additional costs associated with remediation of the sites are anticipated.

7.     Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

In March 2026, 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 2026 and expire in March 2029.

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

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

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this standard, it must provide an Adequate Assurance of Performance which can include an irrevocable letter of credit, a prepayment, a security interest in an asset or a performance bond or guaranty. As of March 31, 2026, FPU was in compliance with all of the requirements of its supply contracts.

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

Corporate Guarantees

The 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 March 31, 2026 was $81.0 million. The aggregate amount guaranteed related to our subsidiaries at March 31, 2026 was $52.4 million with the guarantees expiring on various dates through March 2027. In addition, the BOD has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at March 31, 2026 was $4.0 million.

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

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 regulated 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 unregulated 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.

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The following tables present information about our reportable segments:

	Three Months Ended March 31,
	2026								2025
(in millions)	Regulated		Unregulated		Other Businesses and Eliminations (1)		Total		Regulated		Unregulated		Other Businesses and Eliminations (1)		Total
Operating revenues, unaffiliated customers	$	248.7	$	104.4	$	—	$	353.1	$	199.2	$	99.5	$	—	$	298.7
Intersegment revenues (2)	0.6		9.3		(9.9)		—		0.4		7.2		(7.6)		—
	249.3		113.7		(9.9)		353.1		199.6		106.7		(7.6)		298.7
Less:
Natural gas, propane and electric costs	101.6		55.1		(9.8)		146.9		71.5		52.2		(7.4)		116.3
Operations and maintenance expenses	52.0		23.5		(0.2)		75.3		41.7		21.8		(0.1)		63.4
Depreciation and amortization	16.1		5.4		—		21.5		17.6		4.9		—		22.5
Other segment items (3)	8.5		1.4		0.1		10.0		8.3		1.5		(0.1)		9.7
Operating income	$	71.1	$	28.3	$	—	99.4		$	60.5	$	26.3	$	—	86.8
Other income, net							—								0.6
Interest charges							18.7								18.1
Income before income taxes							80.7								69.3
Income taxes							21.4								18.4
Net income							$	59.3							$	50.9
Capital expenditures	$	94.1	$	13.5	$	14.3	$	121.9	$	96.1	$	14.8	$	2.0	$	112.9

(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.

(in millions)	March 31, 2026		December 31, 2025
Identifiable Assets
Regulated Energy segment	$	3,509.9	$	3,425.3
Unregulated Energy segment	497.4		495.0
Other businesses and eliminations	88.6		74.5
Total identifiable assets	$	4,095.9	$	3,994.8

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/DSPP 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/DSPP 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, subject to an effective shelf registration statement. For the three months ended March 31, 2026 and 2025, we received net proceeds of $5.1 million and $19.8 million, respectively, associated with shares issued under the DRIP/DSPP 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

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agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the three months ended March 31, 2026 and 2025. 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, 2025	$	(1.7)	$	(0.5)	$	(0.5)	$	(2.7)
Other comprehensive loss before reclassifications	—		1.1		—		1.1
Amounts reclassified from accumulated other comprehensive loss	—		0.1		—		0.1
Net current-period other comprehensive loss	—		1.2		—		1.2
As of March 31, 2026	$	(1.7)	$	0.7	$	(0.5)	$	(1.5)

As of December 31, 2024	$	(2.1)	$	0.4	$	—	$	(1.7)
Other comprehensive income (loss) before reclassifications	—		0.7		(0.7)		—
Amounts reclassified from accumulated other comprehensive loss	—		(0.5)		(0.1)		(0.6)
Net prior-period other comprehensive income (loss)	—		0.2		(0.8)		(0.6)
As of March 31, 2025	$	(2.1)	$	0.6	$	(0.8)	$	(2.3)

Deferred gains or losses for our commodity contract and interest rate swap cash flow hedges are recognized in earnings upon settlement and are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details. Amortization of the net loss related to the defined benefit pension plan and postretirement plans is included in the computation of net periodic cost (benefits). See Note 10, Employee Benefit Plans, for additional details.

10.    Employee Benefit Plans

Net periodic costs for our pension and postretirement benefit plans were not material for the three months ended March 31, 2026 and 2025. In addition, total amounts reclassified from accumulated other comprehensive income (loss) and regulatory assets related to all pension and postretirement benefit plans were not material during the three months ended March 31, 2026 and 2025.

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 months ended March 31, 2026, there were no material contributions to our pension and postretirement plans and we do not expect to contribute to our pension and postretirement plans during 2026. 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. The Company has committed to terminating its FPU pension plan and is actively evaluating alternatives to settle the plan's obligations. As a result, the investment strategy of the plan was adjusted in January 2026 to emphasize capital preservation and asset/liability matching.

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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 $16.4 million and $17.2 million at March 31, 2026 and December 31, 2025, 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. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted, and the number of shares to be issued at the end of the service period.

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2026 and 2025:

	Three Months Ended
	March 31,
	2026		2025
(in millions)
Awards to key employees	$	3.3	$	2.1
Awards to non-employee directors	0.2		0.2
Total compensation expense	3.5		2.3
Less: tax benefit	(0.9)		(0.6)
Share-based compensation amounts included in net income	$	2.6	$	1.7

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 generally 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.

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The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2026: 

(in thousands, except per share data)	Number of Shares	Weighted Average Fair Value/Share
Outstanding—December 31, 2025	290	$	115.63
Granted	124	$	130.41
Vested	(67)	$	125.90
Expired	(11)	$	121.68
Outstanding—March 31, 2026	336	$	118.77

During the three months ended March 31, 2026, we granted awards of 124 thousand shares of common stock to officers and key employees under the SICP. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2028.

In March 2026, 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 2026 for the performance period ended December 31, 2025. 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 15 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 $2.0 million.

At March 31, 2026, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $42.4 million. At March 31, 2026, there was approximately $13.3 million of unrecognized compensation cost related to these awards, which will be recognized through 2028.

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 or were appointed during 2025 each received approximately 1 thousand shares of common stock, respectively, with a weighted average fair value of $134.05 per share.

At March 31, 2026, there was $0.1 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May 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 March 31, 2026, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

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Volume of Derivative Activity

As of March 31, 2026, 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	9.4	Cash flow hedges	September 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 April 2026 through September 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 March 31, 2027 is $0.8 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. This swap expired in September 2025. In August 2024, we entered into an additional interest rate swap through August 2029, at a notional amount of $50.0 million and pricing of 3.97 percent. Our interest rate swaps are cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate.

We designate and account for interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses associated with the interest rate 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 $2.3 million and $2.4 million as of March 31, 2026 and December 31, 2025, respectively.

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk related contingency. Fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2026 and December 31, 2025, are as follows: 

	Derivative Assets
		Fair Value As Of
(in millions)	Balance Sheet Location	March 31, 2026		December 31, 2025
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	$	0.9	$	—
Total Derivative Assets (1)		$	0.9	$	—

 (1) Derivative assets, at fair value, include $0.8 million in current assets in the condensed consolidated balance sheet at March 31, 2026, with the remainder of the balances classified as long-term. There were no current derivative asset at December 31, 2025,

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	Derivative Liabilities
		Fair Value As Of
(in millions)	Balance Sheet Location	March 31, 2026		December 31, 2025
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	$	—	$	0.7
Interest rate swap agreements	Derivative liabilities, at fair value	0.7		0.7
Total Derivative Liabilities (1)		$	0.7	$	1.4

(1) Derivative liabilities, at fair value, include $0.2 million in current liabilities in the condensed consolidated balance sheet at March 31, 2026 and $0.8 million at December 31, 2025, with the remainder of the balances classified as long-term.

The effects of gains and losses from derivative instruments on the condensed consolidated statements of income are as follows:

		Amount of Gain (Loss) on Derivatives
	Location of Gain		For the Three Months Ended March 31,
(in millions)	(Loss) on Derivatives		2026		2025
Derivatives designated as cash flow hedges
Propane swap agreements	Unregulated propane and natural gas costs		$	(0.1)	$	0.7
Interest rate swap agreements	Interest expense		—		0.1
Total			$	(0.1)	$	0.8

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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 March 31, 2026 and December 31, 2025:

			Fair Value Measurements Using:
As of March 31, 2026	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	$	0.8	$	—	$	—	$	0.8
Investments—mutual funds and other	15.6		15.6		—		—
Total investments	16.4		15.6		—		0.8
Derivative assets	0.9		—		0.9		—
Total assets	$	17.3	$	15.6	$	0.9	$	0.8
Liabilities:
Derivative liabilities	$	0.7	$	—	$	0.7	$	—

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			Fair Value Measurements Using:
As of December 31, 2025	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in millions)
Assets:
Investments—guaranteed income fund	$	0.9	$	—	$	—	$	0.9
Investments—mutual funds and other	16.3		16.3		—		—
Total assets	$	17.2	$	16.3	$	—	$	0.9
Liabilities:
Derivative liabilities	$	1.4	$	—	$	1.4	$	—

The changes in the fair value of Level 3 investments for the three months ended March 31, 2026 and 2025 were not material. Investment income from the Level 3 investments is reflected in other income, net in the condensed consolidated statements of income.

At March 31, 2026, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At March 31, 2026 and December 31, 2025, long-term debt, which includes current maturities but excludes debt issuance costs, had both a carrying value and estimated fair value of approximately $1.5 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: 

	March 31,		December 31,
(in millions)	2026		2025
Uncollateralized Senior Notes:
5.68% notes, due June 2026	$	2.9	$	2.9
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		2.1
4.88% notes, due August 2028	60.0		60.0
3.73% notes, due December 2028	6.0		6.0
6.45% notes, due December 2028	100.0		100.0
3.88% notes, due May 2029	20.0		20.0
5.20% notes, due November 2029	100.0		100.0
5.02% notes, due September 2030	50.0		50.0
6.62% notes, due December 2030	100.0		100.0
5.16% notes, due August 2031	90.0		90.0
3.25% notes, due April 2032	43.8		45.5
6.71% notes, due December 2033	100.0		100.0
2.98% notes, due December 2034	63.0		63.0
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	5.6		5.8
Less: debt issuance costs	(3.5)		(3.6)
Total long-term debt	1,459.9		1,461.7
Less: current maturities	(134.6)		(134.6)
Total long-term debt, net of current maturities	$	1,325.3	$	1,327.1

    

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.

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, however neither of such lenders have any obligation to purchase debt thereunder. We amended these agreements with Prudential and MetLife in February 2026 and June 2025, respectively, to expand the total borrowing capacity and extend the term of the agreements. At March 31, 2026, a total of $343.3 million of borrowing capacity was available under these agreements with terms that extend through February 2029 and June 2030, respectively.

15.    Short-Term Borrowings

As of March 31, 2026, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At March 31, 2026 and December 31, 2025, we had $199.6 million and $158.0 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.66 percent and 4.73 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at March 31, 2026.

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 March 31, 2026, we were in compliance with this covenant.

Our total available credit under the Revolver at March 31, 2026 was $245.6 million. As of March 31, 2026, we had issued $4.8 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

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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, 2025, 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 2025 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 within expected times, 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 tax regulations and rates;

•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. Within our 2025 Annual Report to Shareholders, we continued to highlight our ongoing efforts related to these commitments. We encourage our investors to review the 2025 Annual Report to Shareholders, as well as our prior micro and consolidated sustainability reports, which can be accessed on our website.

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 months ended March 31, 2026 and 2025:

Adjusted Gross Margin

	For the Three Months Ended March 31, 2026
(in millions)	Regulated Energy		Unregulated Energy		Other Businesses and Eliminations		Total
Operating Revenues	$	249.3	$	113.7	$	(9.9)	$	353.1
Cost of Sales:
Natural gas, propane and electric costs	(101.6)		(55.1)		9.8		(146.9)
Depreciation & amortization	(16.1)		(5.4)		—		(21.5)
Operations & maintenance expenses (1)	(16.7)		(10.9)		0.1		(27.5)
Gross Margin (GAAP)	114.9		42.3		—		157.2
Operations & maintenance expenses (1)	16.7		10.9		(0.1)		27.5
Depreciation & amortization	16.1		5.4		—		21.5
Adjusted Gross Margin (Non-GAAP)	$	147.7	$	58.6	$	(0.1)	$	206.2

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	For the Three Months Ended March 31, 2025
(in millions)	Regulated Energy		Unregulated Energy		Other Businesses and Eliminations		Total
Operating Revenues	$	199.6	$	106.7	$	(7.6)	$	298.7
Cost of Sales:
Natural gas, propane and electric costs	(71.5)		(52.2)		7.4		(116.3)
Depreciation & amortization	(17.6)		(4.9)		—		(22.5)
Operations & maintenance expenses (1)	(13.3)		(9.7)		0.3		(22.7)
Gross Margin (GAAP)	97.2		39.9		0.1		137.2
Operations & maintenance expenses (1)	13.3		9.7		(0.3)		22.7
Depreciation & amortization	17.6		4.9		—		22.5
Adjusted Gross Margin (Non-GAAP)	$	128.1	$	54.5	$	(0.2)	$	182.4

(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.

2026 to 2025 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for the three months ended March 31, 2026 was $114.9 million, an increase of $17.7 million, or 18.2 percent, compared to the same period in 2025. 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.

2026 to 2025 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for the three months ended March 31, 2026 was $42.3 million, an increase of $2.4 million, or 6.0 percent, compared to the same period in 2025. The increase in gross margin was primarily attributable to higher results from our propane distribution business largely attributable to increased customer consumption from colder year-over-year weather in our Delmarva service areas, and increased performance from Aspire Energy.

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Adjusted Net Income and Adjusted EPS

	Three Months Ended
	March 31,
(dollars in millions, shares in thousands (except per share data))	2026		2025
Net Income (GAAP)	$	59.3	$	50.9
FCG transaction and transition-related expenses, net (1)	—		0.2
Adjusted Net Income (Non-GAAP)	$	59.3	$	51.1
Weighted average common shares outstanding - diluted	24,053		23,041
Earnings Per Share - Diluted (GAAP)	$	2.47	$	2.21
FCG transaction and transition-related expenses, net (1)	—		0.01
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	2.47	$	2.22

(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.

2026 to 2025 Net Income (GAAP) Variance

Net income (GAAP) for the three months ended March 31, 2026 was $59.3 million, or $2.47 per share, compared to $50.9 million, or $2.21 per share, for the same quarter of 2025. Net income for the three months ended March 31, 2025 included $0.2 million of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $8.2 million or 16.0 percent compared to the prior-year period.

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Results of Operations for the Three Months Ended March 31, 2026

Operational Highlights

Our adjusted net income for the three months ended March 31, 2026 was $59.3 million, or $2.47 per share, compared to $51.1 million, or $2.22 per share, for the same period in 2025. Operating income for the first three months of 2026 was $99.4 million, an increase of $12.6 million compared to the same period in 2025. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $12.3 million or 14.1 percent compared to the prior-year period. The increase in adjusted gross margin in the first quarter of 2026 was primarily driven by incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects and natural gas organic growth, increased customer consumption resulting from year-over-year colder temperatures largely in the Company's Delmarva service areas, and improved performance at Aspire Energy. Higher operating expenses were driven largely by increased payroll, benefits and other employee-related expenses and higher facilities, maintenance costs and outside services compared to the prior-year period. Depreciation and amortization expense for the current period includes decreases related to certain regulatory items including the absence of recovered costs associated with Hurricane Michael and the impact of the FCG depreciation study. These amounts were largely offset by additional depreciation, amortization and property taxes associated with growth.

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	Three Months Ended
	March 31,				Increase
	2026		2025		(Decrease)
(in millions, except shares (thousands) and per share data)
Adjusted Gross Margin
Regulated Energy segment	$	147.7	$	128.1	$	19.6
Unregulated Energy segment	58.6		54.5		4.1
Other Businesses and Eliminations	(0.1)		(0.2)		0.1
Total Adjusted Gross Margin	$	206.2	$	182.4	$	23.8
Operating Income
Regulated Energy segment	$	71.1	$	60.5	$	10.6
Unregulated Energy segment	28.3		26.3		2.0
Other Businesses and Eliminations	—		—		—
Total Operating Income	99.4		86.8		12.6
Other income, net	—		0.6		(0.6)
Interest charges	18.7		18.1		0.6
Income Before Income Taxes	80.7		69.3		11.4
Income taxes	21.4		18.4		3.0
Net Income	$	59.3	$	50.9	$	8.4
Weighted Average Common Shares Outstanding:
Basic	23,937		22,957		980
Diluted	24,053		23,041		1,012
Earnings Per Share of Common Stock
Basic	$	2.48	$	2.22	$	0.26
Diluted	$	2.47	$	2.21	$	0.26
Adjusted Net Income and Adjusted Earnings Per Share
Net Income (GAAP)	$	59.3	$	50.9	$	8.4
FCG transaction and transition-related expenses, net (1)	—		0.2		(0.2)
Adjusted Net Income (Non-GAAP)	$	59.3	$	51.1	$	8.2
Earnings Per Share - Diluted (GAAP)	$	2.47	$	2.21	$	0.26
FCG transaction and transition-related expenses, net (1)	—		0.01		(0.01)
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	2.47	$	2.22	$	0.25

(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 three months ended March 31, 2025 and March 31, 2026 included: 

(in millions, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Three Months Ended March 31, 2025 Adjusted Results (1)	$	69.7	$	51.1	$	2.22
Change in Adjusted Gross Margins:
Natural gas transmission service expansions, including interim services (2)	6.9		5.1		0.21
Contributions from regulated infrastructure programs (2)	5.5		4.0		0.17
Changes in customer consumption	4.5		3.3		0.14
Rate changes associated with recent rate case activities (2)	4.1		3.0		0.13
Natural gas growth including conversions (excluding service expansions)	2.0		1.5		0.06
Increased Aspire Energy performance - rate changes and gathering fees	1.4		1.0		0.04
Change in off-system natural gas capacity sales	1.1		0.8		0.03
Absence of recovered costs associated with Hurricane Michael (3)	(2.0)		(1.5)		(0.06)
	23.5		17.2		0.72
Increased Operating Expenses (Excluding Natural Gas, Propane, and Electric Costs):
Payroll, benefits and other employee-related expenses	(6.6)		(4.9)		(0.20)
Facilities expenses, maintenance costs and outside services	(3.1)		(2.2)		(0.09)
Depreciation, amortization and property taxes	(1.5)		(1.1)		(0.05)
Credit, collections and customer service costs	(1.4)		(1.1)		(0.04)
Absence of amortization of costs associated with Hurricane Michael recovery (3)	2.0		1.5		0.06
	(10.6)		(7.8)		(0.32)
Interest charges	(0.6)		(0.4)		(0.02)
Increase in shares outstanding due to 2025 and 2026 equity offerings (4)	—		—		(0.09)
Net other changes	(1.3)		(0.8)		(0.04)
	(1.9)		(1.2)		(0.15)
Three Months Ended March 31, 2026 Adjusted Results (1)	$	80.7	$	59.3	$	2.47

    

(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) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of

recovered costs associated with Hurricane Michael.

(4) Reflects the impact of approximately 0.8 million common shares issued under the DRIP/DSSP 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				Year Ended		Estimate for
	March 31,				December 31,		Fiscal
(in millions)	2026		2025		2025		2026		2027
Pipeline Expansions:
St. Cloud / Twin Lakes Expansion	$	1.0	$	0.1	$	2.9	$	3.8	$	3.8
Wildlight	1.1		0.5		2.6		4.3		4.3
Worcester Resiliency Upgrade	0.4		—		0.3		1.5		17.1
Boynton Beach	0.9		0.5		3.0		3.4		3.4
New Smyrna Beach	0.6		—		1.6		2.6		2.6
Central Florida Reinforcement	1.1		0.3		2.6		4.3		4.3
Renewable Natural Gas Supply Projects	1.3		—		2.5		5.4		6.4
Miami Inner Loop	1.9		—		2.8		7.6		7.6
Duncan Plains	—		—		—		—		1.1
Total Pipeline Expansions	8.3		1.4		18.3		32.9		50.6
Regulatory Initiatives:
Florida GUARD program	2.4		1.5		7.1		10.1		13.0
FCG SAFE Program	2.8		1.7		8.4		12.7		16.4
Capital Cost Surcharge Programs	2.3		1.5		5.7		9.0		10.1
Electric Storm Protection Plan	3.3		1.1		6.4		10.7		11.0
Florida Mandatory Relocates	0.5		—		—		1.5		1.5
Maryland Rate Case (1)	1.3		—		1.5		3.5		3.5
Delaware Rate Case (1)	2.1		0.8		4.7		6.1		6.1
Electric Rate Case (1)	2.2		0.7		7.3		8.6		9.1
Florida City Gas Rate Case	—		—		—		TBD		TBD
Total Regulatory Initiatives	16.9		7.3		41.1		62.2		70.7
Total	$	25.2	$	8.7	$	59.4	$	95.1	$	121.3

(1) Includes adjusted gross margin attributable to interim and permanent rates. 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. We expect this extension to generate annual adjusted gross margin of approximately $0.6 million in 2026 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

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project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the second quarter of 2026. For the three months ended March 31, 2026, these projects generated incremental adjusted gross margin of $0.9 million. We expect this expansion to generate approximately $3.2 million in 2026 and 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 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 petition was approved by the Florida PSC in November 2022. The various phases of the project commenced in the first quarter of 2023, and construction was completed in 2025. The project generated incremental adjusted gross margin of $0.6 million for the three months ended March 31, 2026, and is expected to contribute adjusted gross margin of approximately $4.3 million in 2026 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.

In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025. Construction commenced shortly after approval and is well underway. The weather during the first quarter resulted in several brief slowdowns which had a cumulative impact on the overall timeline. Project construction and commissioning are expected to be complete in the latter part of the year with the FERC approval process to immediately follow. The Company expects to receive full approval for in-service of the facility by the beginning of 2027. The project generated adjusted gross margin of $0.4 million for the three months ended March 31, 2026. The project is expected to contribute adjusted gross margin of approximately $1.5 million in 2026 and $17.1 million in 2027 and annually 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 support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that have experienced an increase in population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the second quarter of 2026. The projects generated incremental adjusted gross margin of $1.0 million for the three months ended March 31, 2026, and are expected to contribute adjusted gross margin of approximately $6.0 million in 2026 and annually thereafter.

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. The projects are driven by the need for increased supply to communities in central Florida that are experiencing significant population growth. Peninsula Pipeline's extensions support FPU’s distribution system around the Plant City and Lake Mattie area's of Florida with an additional 5,000 Dts/d and 8,700 Dts/d, respectively. The Florida PSC approved the projects in March 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project went into service in July 2025. The projects generated incremental adjusted gross margin of $0.8 million for the three months ended March 31, 2026, and both projects are expected to contribute total adjusted gross margin of approximately $4.3 million in 2026 and annually thereafter.

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Renewable Natural Gas Supply Projects

In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition at its July 2024 meeting. In October 2025, the Florida PSC approved amendments to the Transportation Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements. The projects are underway and are estimated to be completed in the second half of 2026. These three renewable projects generated adjusted gross margin of $1.3 million for the three months ended March 31, 2026, and are projected to generate total adjusted gross margin of approximately $5.4 million in 2026 and $6.4 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 gas infrastructure in Miami-Dade County. The proposed expansion consists of the development of several pipeline projects to support growth and FCG's distribution system, as well as enhance FCG's access to gas from various points in the Miami-Dade County area. The expansion was approved in February 2025 and interim services began in August 2025 with permanent facilities expected to be in service by the second quarter of 2026. The project generated adjusted gross margin of $1.9 million for the three months ended March 31, 2026 and is expected to contribute adjusted gross margin of approximately $7.6 million in 2026 and annually thereafter.

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 and is expected to contribute adjusted gross margin of approximately $1.1 million in 2027 and approximately $2.1 million annually thereafter.

Regulatory Initiatives (with recent regulatory actions)

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 the three months ended March 31, 2026, there was $0.9 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $10.1 million of adjusted gross margin in 2026 and $13.0 million in 2027.

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 the three months ended March 31, 2026, there was $1.1 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $12.7 million of adjusted gross margin in 2026 and $16.4 million in 2027.

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 enable FCG to accelerate remediation related to problematic pipe and facilities consisting of obsolete and exposed pipe. These modifications will improve the safety and reliability of service to FCG's customers and result in an estimated additional $50.0 million in capital expenditures associated with the SAFE Program, increasing 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 2025 Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2025. The combined revised surcharge became effective January 1, 2026.

In March 2026, 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 a slight decrease to the revenue requirement of the currently effective surcharge as a result of the true-up. The FERC issued an order approving the surcharge as filed effective April 1, 2026. For the three months ended March 31, 2026, there was $0.8 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to generate adjusted gross margin of approximately $9.0 million in 2026 and $10.1 million in 2027 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 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. For the three months ended March 31, 2026, this initiative generated additional adjusted gross margin of $2.2 million and is expected to generate $10.7 million of adjusted gross margin in 2026 and $11.0 million in 2027. We expect continued investment under the SPP going forward.

Florida Mandatory Relocates

In October 2025, FPU and FCG filed a joint petition for approval to establish a recovery surcharge for actual, estimated and projected relocation costs pursuant to the Florida Administrative Code which enables companies to recover the costs associated with relocating or reconstructing facilities that have been required by governmental entities. The Florida PSC approved the petition in February 2026, with the surcharge effective in March 2026. For the three months ended March 31, 2026, there was $0.5 million of adjusted gross margin generated. The projected total revenue for both 2026 and 2027 is $0.5 million for FPU and $1.0 million for FCG.

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 September 2024, the Maryland Public Utility Judge approved a $2.6 million increase in annual base rates, which was followed by the Company submitting 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. In March 2025 the 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 the three months ended March 31, 2026, there was $1.3 million of incremental adjusted gross margin generated and the proceeding is expected to result in additional adjusted gross margin of approximately $3.5 million in 2026 and 2027.

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)

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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 all interested parties 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 and approved tariff-related changes including rate design were effective as of October 15, 2025. For the three months ended March 31, 2026, there was $1.3 million of incremental adjusted gross margin generated and final rates are expected to generate approximately $6.1 million of adjusted gross margin in 2026 and 2027.

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. This settlement which was approved by the Florida PSC in July 2025, provides for a total base rate increase of approximately $8.6 million on an annual basis, with $1.0 million of the increase deferred from the first year's base rate increase and recovered over three years. A step-up rate increase was also approved for up to $0.7 million, upon completion of the purchase and refurbishment of certain substations, which is expected to be completed in December 2026. For the three months ended March 31, 2026, there was $1.5 million of incremental adjusted gross margin generated and final rates are expected to generate approximately $8.6 million of adjusted gross margin in 2026 and $9.1 million in 2027.

FCG Rate Case

In April 2026, Florida City Gas filed a petition with the Florida PSC. In connection with the application, we are seeking approval of the following: (i) interim rate relief of approximately $16.2 million, subject to refund, pending the outcome of the rate case proceeding; (ii) general base rate increase of $46.9 million with a ROE of 11.25 percent based on a 2027 projected test year; (iii) reclassification of approximately $16.4 million in the existing SAFE program revenues from surcharge recovery to base rates; (iv) authorization to retain the unamortized portion of the previously approved acquisition adjustment; and (v) further implementation of the advanced metering infrastructure (“AMI”). The outcome of the application will be subject to review and approval by the Florida PSC.

FCG Depreciation Study

In February 2025, FCG filed a depreciation study with the Florida PSC. The application requested approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets.

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Other Major Factors Influencing Adjusted Gross Margin

Weather Impact

For the three months ended March 31, 2026, increased customer consumption, which includes the effects of colder weather conditions, largely in our Delmarva service areas, compared to the prior-year period resulted in a $4.5 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 months ended March 31, 2026 and 2025.

	Three Months Ended
	March 31,
	2026	2025	Variance
Delmarva Peninsula
Actual HDD	2,348	2,210	138
10-Year Average HDD ("Normal")	2,085	2,146	(61)
Variance from Normal	263	64
Florida
Actual HDD	594	580	14
10-Year Average HDD ("Normal")	471	483	(12)
Variance from Normal	123	97
Florida City Gas
Actual HDD	357	300	57
10-Year Average HDD ("Normal")	229	221	8
Variance from Normal	128	79
Ohio
Actual HDD	3,022	3,087	(65)
10-Year Average HDD ("Normal")	2,751	2,801	(50)
Variance from Normal	271	286
Florida
Actual CDD	226	189	37
10-Year Average CDD ("Normal")	220	217	3
Variance from Normal	6	(28)

Natural Gas Distribution Growth

The average number of residential customers served on the Delmarva Peninsula, by FPU and by FCG increased by approximately 3.3 percent, 2.2 percent, and 2.0 percent, respectively, for the three months ended March 31, 2026.

The details of the adjusted gross margin increase are provided in the following table:

	Three Months Ended
	March 31, 2026
(in millions)	Delmarva Peninsula		Florida
Customer Growth:
Residential	$	0.5	$	0.8
Commercial and industrial	—		0.7
Total Customer Growth	$	0.5	$	1.5

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Regulated Energy Segment

For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025:

	Three Months Ended
	March 31,
	2026		2025		Change
(in millions)
Revenue	$	249.3	$	199.6	$	49.7
Regulated natural gas and electric costs	101.6		71.5		30.1
Adjusted gross margin (1) (2)	147.7		128.1		19.6
Operations & maintenance	49.3		39.4		(9.9)
Depreciation, amortization and property taxes (2)	25.0		25.9		0.9
Other taxes	2.3		2.0		(0.3)
FCG transaction and transition-related expenses (3)	—		0.3		0.3
Total operating expenses	76.6		67.6		(9.0)
Operating income	$	71.1	$	60.5	$	10.6

(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.

(2) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael. See Key variances table above for additional information.

(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 first quarter of 2026 was $71.1 million, an increase of $10.6 million, over the same period in 2025. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $10.3 million, or 16.9 percent, compared to the same period in 2025. 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 $9.3 million was largely attributable to higher expenses associated with payroll, benefits and other employee related expenses, higher facilities, maintenance costs and outside services, and increased costs related to credit, collections and customer service. Depreciation and amortization expense for the current period includes decreases related to certain regulatory items including the absence of recovered costs associated with Hurricane Michael and the impact of the FCG depreciation study. These amounts were largely offset by additional depreciation, amortization and property taxes associated with growth.

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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	$	6.9
Contributions from regulated infrastructure programs	5.5
Rate changes associated with recent rate case activities (1)	4.1
Natural gas growth including conversions (excluding service expansions)	2.0
Changes in customer consumption	1.7
Adjusted gross margin from off-system natural gas capacity sales	1.1
Absence of recovered costs associated with Hurricane Michael (2)	(2.0)
Other variances	0.3
Quarter-over-quarter increase in adjusted gross margin	$	19.6

(1) Includes adjusted gross margin contributions from permanent base rates. Refer to Major Projects discussion for additional information.

(2) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael.

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 $6.9 million for the three months ended March 31, 2026 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 $5.5 million for the three months ended March 31, 2026. 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 $4.1 million for the three months ended March 31, 2026. 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 $2.0 million from natural gas customer growth. Adjusted gross margin increased by $1.5 million for our Florida natural gas distribution service territories and $0.5 million on the Delmarva Peninsula for the three months ended March 31, 2026, as compared to the same period in 2025, due to residential customer growth in these service areas, 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 $1.7 million for the three months ended March 31, 2026.

Adjusted Gross Margin from Off-system Natural Gas Capacity Sales

Off-system natural gas capacity sales increased adjusted gross margin by $1.1 million for the three months ended March 31, 2026.

Absence of Recovered Costs Associated with Hurricane Michael

There is no impact to earnings as this $2.0 million decrease in adjusted gross margin for the three months ended March 31, 2026, is offset by a corresponding decrease in depreciation and amortization expense for the period.

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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	$	(5.0)
Facilities expenses, maintenance costs and outside services	(2.7)
Credit, collections and customer service costs	(1.4)
Depreciation, amortization and property tax costs	(1.1)
Absence of amortization of costs associated with Hurricane Michael recovery (1)	2.0
Other variances	(0.8)
Quarter-over-quarter increase in operating expenses	$	(9.0)

(1) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael.

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Unregulated Energy Segment

For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025:

 

	Three Months Ended
	March 31,
	2026		2025		Change
(in millions)
Revenue	$	113.7	$	106.7	$	7.0
Unregulated propane and natural gas costs	55.1		52.2		2.9
Adjusted gross margin (1)	58.6		54.5		4.1
Operations & maintenance	23.6		21.9		(1.7)
Depreciation, amortization and property tax costs	5.8		5.5		(0.3)
Other taxes	0.9		0.8		(0.1)
Total operating expenses	30.3		28.2		(2.1)
Operating income	$	28.3	$	26.3	$	2.0

(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 three months ended March 31, 2026 reflect a $2.0 million increase compared to the same period in 2025. The increase in adjusted gross margin in the Unregulated Energy segment during the first quarter of 2026 was primarily due to increased consumption in our propane distribution business which was impacted by colder weather in the Delmarva service areas as well as improved performance from Aspire Energy. 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.

Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table:

(in millions)
Propane Operations
Increased propane customer consumption	$	2.4
Aspire Energy
Increased performance from Aspire Energy - rate changes and gathering fees	1.4
Increased customer consumption	0.4
Other variances	(0.1)
Quarter-over-quarter increase in adjusted gross margin	$	4.1

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 $2.4 million due to increased customer consumption resulting primarily from colder year-over-year weather in our Delmarva service areas.

Aspire Energy

•Increased performance from Aspire Energy - Adjusted gross margin increased by $1.4 million compared to the prior-year period due to negotiated rate changes and increased gathering fees.

•Increased customer consumption - Adjusted gross margin increased by $0.4 million due to increased customer consumption during the current year primarily related to year-over-year colder weather in our Ohio service area.

Operating Expenses

Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table:

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(in millions)
Payroll, benefits and other employee-related expenses	$	(1.6)
Facilities expenses, maintenance costs and outside services	(0.4)
Other variances	(0.1)
Quarter-over-quarter increase in operating expenses	$	(2.1)

OTHER INCOME, NET

For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025

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, was not material in the first quarter of 2026 compared to $0.6 million during the prior-year period.

INTEREST CHARGES

For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025

Interest charges for the quarter ended March 31, 2026 increased by $0.6 million compared to the same period in 2025, attributable primarily to the Senior Notes issued in August and September 2025. Interest expense on Revolver borrowings slightly offset the interest charges increase due to lower average outstanding borrowings and a steady weighted-average interest rate of 5.1 percent for the quarters ended March 31, 2026 and 2025. Increased interest charges were also offset by higher capitalized interest during the current period of $1.4 million associated with capital projects.

INCOME TAXES

For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025

Income tax expense was $21.4 million and $18.4 million for the quarters ended March 31, 2026 and March 31, 2025, respectively, resulting in an effective income tax rate of 26.5 percent and 26.6 percent, respectively, during the periods then ended.

FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES

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/DSPP and ATM program. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may consider issuing additional shares under the direct share purchase component of the DRIP/DSPP and/or under our ATM equity program.

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 $121.9 million for the three months ended March 31, 2026.

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In the table below, we have provided the range of our forecasted capital expenditures for 2026:

	2026
(in millions)	Low		High
Regulated distribution	$	110.0	$	120.0
Regulated transmission	135.0		145.0
Regulated infrastructure	90.0		100.0
Unregulated business	25.0		35.0
Technology	90.0		100.0
Total 2026 Forecasted Capital Expenditures	$	450.0	$	500.0

The 2026 projection excludes potential acquisitions due to their opportunistic nature.

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 2025 Annual Report on Form 10-K. 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 March 31, 2026 and December 31, 2025:

	March 31, 2026				December 31, 2025
(in millions)
Long-term debt, net of current maturities	$	1,325.3	45	%	$	1,327.1	45	%
Stockholders’ equity	1,651.7		55	%	1,598.5		55	%
Total capitalization, excluding short-term debt	$	2,977.0	100	%	$	2,925.6	100	%
	March 31, 2026				December 31, 2025
(in millions)
Short-term debt	$	199.6	6	%	$	158.0	5	%
Long-term debt, including current maturities	1,459.9		44	%	1,461.7		45	%
Stockholders’ equity	1,651.7		50	%	1,598.5		50	%
Total capitalization, including short-term debt	$	3,311.2	100	%	$	3,218.2	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 50 percent as of March 31, 2026.

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. We may, from time to time, allow our capital structure to fall below the target range to align the completion of large capital projects with the respective permanent financing.

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, subject to an effective shelf registration statement. For the three months ended March 31, 2026 and 2025, we received net proceeds of $5.1 million and $19.8 million, respectively, associated with shares issued under the DRIP/DSPP as well as shares issued under our ATM program.

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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 March 31, 2026, a total of $343.3 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 March 31, 2026, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At March 31, 2026 and December 31, 2025, we had $199.6 million and $158.0 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.66 percent and 4.73 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at March 31, 2026.

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 March 31, 2026, we were in compliance with this covenant.

Our total available credit under the Revolver at March 31, 2026 was $245.6 million. As of March 31, 2026, we had issued $4.8 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

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.

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Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2026 and 2025:

	Three Months Ended
	March 31,
(in millions)	2026		2025
Net cash provided by (used in):
Operating activities	$	118.0	$	85.0
Investing activities	(141.7)		(113.1)
Financing activities	26.6		20.9
Net increase (decrease) in cash and cash equivalents	2.9		(7.2)
Cash and cash equivalents—beginning of period	1.8		7.9
Cash and cash equivalents—end of period	$	4.7	$	0.7

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 three months ended March 31, 2026, net cash provided by operating activities was $118.0 million. Operating cash flows were primarily impacted by the following:

•Net income, adjusted for non-cash adjustments, provided a $89.1 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 $20.0 million; and

•Working capital changes resulted in a $8.8 million source of cash.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $141.7 million during the three months ended March 31, 2026, primarily attributable to $141.9 million related to new capital expenditures.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $26.6 million during the three months ended March 31, 2026 and was largely impacted by the following:

•Net borrowings under the Revolver of $42.0 million; and

•A $16.2 million use of cash for dividend payments in 2026.

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 March 31, 2026 was $81.0 million. The aggregate amount guaranteed related to our subsidiaries at March 31, 2026 was $52.4 million, with the guarantees expiring on various dates through March 2027. In addition, the BOD authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at March 31, 2026 was $4.0 million.

As of March 31, 2026, we have issued letters of credit totaling $4.8 million related to various transportation, transmission, capacity and storage agreements as well as our primary insurance carriers. These letters of credit have various expiration dates through October 2026 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Note 7, Other Commitments and Contingencies, in the condensed consolidated financial statements.

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Contractual Obligations

There has been no material change in the contractual obligations presented in our 2025 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.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

INTEREST RATE RISK

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.

COMMODITY PRICE RISK

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 8.4 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.

49

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2025 to March 31, 2026:

(in millions)	Balance at December 31, 2025		Increase in Fair Market Value		Less Amounts Settled		Balance at March 31, 2026
Sharp	$	(0.7)	$	1.5	$	0.1	$	0.9

There were no changes in methods of valuations during the three months ended March 31, 2026.

The following is a summary of fair market value of financial derivatives as of March 31, 2026, by method of valuation and by maturity for each fiscal year period.

(in millions)	2026		2027		2028		2029		Total Fair Value
Price based on Mont Belvieu - Sharp	$	0.7	$	0.2	$	—	$	—	$	0.9

WHOLESALE CREDIT RISK

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.

INFLATION

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 March 31, 2026. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2026.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2026, 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

50

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, 2025, 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.

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

Company Purchases of Equity Securities

Share repurchases during the three months ended March 31, 2026 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)
January 1, 2026 through January 31, 2026 (1)	720	$	122.34	—	—
February 1, 2026 through February 28, 2026	—	—		—	—
March 1, 2026 through March 31, 2026	—	—		—	—
Total	720	$	122.34	—	—

(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 15, Employee Benefit Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2025.

(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 March 31, 2026, 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.

51

Item 6.     Exhibits

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

52

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.

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President and Chief Financial Officer

Date: May 6, 2026

53

EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Jeffry M. Householder, certify that:

1.I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2026 of Chesapeake Utilities Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2026

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder
President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1.I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2026 of Chesapeake Utilities Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a.designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2026

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Jeffry M. Householder, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2026, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder

May 6, 2026

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Executive Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2026, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ BETH W. COOPER

Beth W. Cooper

May 6, 2026

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

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Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2026	May 04, 2026
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2026
Document Transition Report	false
Entity File Number	001-11590
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0064146
Entity Address, Address Line One	500 Energy Lane
Entity Address, City or Town	Dover
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19901
City Area Code	302
Local Phone Number	734-6799
Title of 12(b) Security	Common Stock - par value per share $0.4867
Trading Symbol	CPK
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		24,004,761
Entity Central Index Key	0000019745
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2026
Document Fiscal Period Focus	Q1
Amendment Flag	false

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Condensed Consolidated Statements of Income (Unaudited) - USD ($) shares in Thousands, $ in Thousands		3 Months Ended
		Mar. 31, 2026	Mar. 31, 2025
Operating Revenues
Regulated Energy		$ 249,300	$ 199,600
Unregulated Energy		113,700	106,700
Total Operating Revenues		353,100	298,700
Operating Expenses
Regulated natural gas and electric costs		101,600	71,500
Unregulated propane and natural gas costs		45,300	44,800
Operations		67,300	58,000
Transaction-related expenses		0	300
Maintenance		8,000	5,400
Depreciation and amortization		21,500	22,500
Other taxes		10,000	9,400
Total Operating Expenses		253,700	211,900
Total operating income		99,400	86,800
Other income, net		0	600
Interest charges		18,700	18,100
Income Before Income Taxes		80,700	69,300
Income taxes		21,400	18,400
Net Income		$ 59,300	$ 50,900
Weighted Average Common Shares Outstanding:
Basic (shares)	[1]	23,937	22,957
Diluted (shares)		24,053	23,041
Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share		$ 2.48
Basic (in dollars per share)		2.48	$ 2.22
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share		2.47	2.21
Diluted (in dollars per share)		$ 2.47	$ 2.21
Other Operating Revenue		$ (9,900)	$ (7,600)

[1]

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Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2026	Mar. 31, 2025
Statement of Comprehensive Income [Abstract]
Net Income	$ 59.3	$ 50.9
Other comprehensive income (loss)	1.2	(0.6)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	60.5	50.3
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.1	(0.6)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.1)	0.6
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1.1	0.0
Net Income	59.3	50.9
Other comprehensive income (loss)	1.2	(0.6)
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	60.5	50.3
Unrealized Gain (Loss) On Cash Flow Hedging Instruments, Tax	0.4	0.2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	0.0	(0.2)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Statement of Comprehensive Income [Abstract]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.1	(0.5)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.1)	0.5
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	1.1	0.7
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	0.0	(0.2)
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges [Member]
Statement of Comprehensive Income [Abstract]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(0.1)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		0.1
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0.0	(0.7)
Accumulated Gain (Loss), Net, Cash Flow Hedge, Parent
Statement of Comprehensive Income [Abstract]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.0	(0.1)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.0	0.1
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	$ 0.0	$ 0.0

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2026	Mar. 31, 2025
Statement of Other Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	$ 0.0	$ (0.2)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	0.0	(0.2)
Unrealized Gain (Loss) On Cash Flow Hedging Instruments, Tax	0.4	0.2
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	$ 0.0	$ (0.2)

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2026	Dec. 31, 2025
Property, Plant and Equipment
Regulated Energy	$ 3,009,000	$ 2,941,600
Unregulated Energy	507,200	492,400
Other Businesses and Eliminations	39,300	38,300
Total property, plant and equipment	3,555,500	3,472,300
Less: Accumulated depreciation and amortization	(652,100)	(637,600)
Property, Plant, and Equipment, after Accumulated Depreciation, Depletion, and Amortization	3,223,900	3,118,400
Current Assets
Cash and cash equivalents	4,700	1,800
Trade and other receivables	113,900	101,500
Accounts Receivable, Allowance for Credit Loss, Current	(6,763)	(5,412)
Accounts Receivable, before Allowance for Credit Loss, Current	120,700	106,900
Accrued revenue	49,000	50,100
Propane inventory, at average cost	8,200	8,800
Other inventory, at average cost	17,100	17,900
Regulatory assets	24,500	29,700
Storage gas prepayments	700	4,500
Prepaid expenses	17,000	19,700
Derivative assets, at fair value	800	0
Other current assets	3,200	3,000
Total current assets	239,100	237,000
Deferred Charges and Other Assets
Goodwill	507,500	507,500
Other intangible assets, net	12,900	13,200
Investments, at fair value	16,400	17,200
Operating Lease, Right-of-Use Asset	9,400	9,900
Regulatory assets	73,700	74,300
Receivables and other deferred charges	12,900	17,300
Total deferred charges and other assets	632,900	639,400
Total Assets	4,095,900	3,994,800
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	0	0
Common stock, par value $0.4867 per share (authorized 75,000,000 shares)	11,700	11,600
Additional paid-in capital	972,200	962,800
Retained earnings	669,300	626,800
Accumulated other comprehensive loss	(1,500)	(2,700)
Deferred compensation obligation	17,400	12,600
Treasury stock	(17,400)	(12,600)
Total stockholders’ equity	1,651,700	1,598,500
Total capitalization	2,977,000	2,925,600
Current Liabilities
Less: current maturities	134,600	134,600
Short-term borrowing	199,600	158,000
Accounts payable	101,100	115,200
Customer deposits and refunds	41,800	45,100
Accrued interest	17,600	8,700
Dividends payable	16,400	16,400
Accrued compensation	10,500	21,600
Regulatory liabilities	11,600	14,500
Derivative liabilities, at fair value	200	800
Other accrued liabilities	20,300	15,000
Total current liabilities	553,700	529,900
Deferred Credits and Other Liabilities
Deferred income taxes	333,700	313,300
Regulatory liabilities	188,800	188,100
Environmental liabilities	3,000	2,900
Other pension and benefit costs	13,100	14,000
Operating Lease, Liability, Noncurrent	7,500	7,900
Deferred investment tax credits and other liabilities	18,600	12,500
Total deferred credits and other liabilities	565,200	539,300
Total Capitalization and Liabilities	4,095,900	3,994,800
Other Businesses and Eliminations	39,300	38,300
Property, Plant, and Equipment, before Accumulated Depreciation, Depletion, and Amortization	3,555,500	3,472,300
Construction Work in Progress	320,500	283,700
Property, Plant, and Equipment, after Accumulated Depreciation, Depletion, and Amortization	3,223,900	3,118,400
Trade and other receivables	113,900	101,500
Other current assets	3,200	3,000
Assets, Current	239,100	237,000
Receivables and other deferred charges	12,900	17,300
Deferred Charges And Other Assets	632,900	639,400
Total identifiable assets	4,095,900	3,994,800
Regulated Energy	3,009,000	2,941,600
Unregulated Energy	507,200	492,400
Property, Plant, and Equipment, Accumulated Depreciation, Depletion, and Amortization	652,100	637,600
Cash and cash equivalents	4,700	1,800
Accounts Receivable, before Allowance for Credit Loss, Current	120,700	106,900
Allowance for uncollectible accounts	6,763	5,412
Accrued revenue	49,000	50,100
Propane inventory, at average cost	8,200	8,800
Other inventory, at average cost	17,100	17,900
Regulatory assets	24,500	29,700
Storage gas prepayments	700	4,500
Prepaid expenses	17,000	19,700
Derivative assets, at fair value	800	0
Goodwill	507,500	507,500
Other intangible assets, net	12,900	13,200
Investments, at fair value	16,400	17,200
Operating Lease, Right-of-Use Asset	9,400	9,900
Regulatory assets	73,700	74,300
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	0	0
Stockholders' Equity Attributable to Parent	1,651,700	1,598,500
Capitalization, Long-term Debt and Equity	2,977,000	2,925,600
Accounts payable	101,100	115,200
Other accrued liabilities	20,300	15,000
Liabilities, Current	553,700	529,900
Regulatory liabilities	188,800	188,100
Operating Lease, Liability, Noncurrent	7,500	7,900
Deferred investment tax credits and other liabilities	18,600	12,500
Deferred Credits and Other Liabilities	565,200	539,300
Liabilities and Equity	4,095,900	3,994,800
Common stock, par value $0.4867 per share (authorized 75,000,000 shares)	11,700	11,600
Additional paid-in capital	972,200	962,800
Retained earnings	669,300	626,800
Accumulated other comprehensive loss	(1,500)	(2,700)
Deferred compensation obligation	17,400	12,600
Treasury Stock, Value	17,400	12,600
Long-term Debt and Capital Lease Obligations, Net of Current Maturities	1,325,300	1,327,100
Less: current maturities	134,600	134,600
Short-term borrowing	199,600	158,000
Customer deposits and refunds	41,800	45,100
Accrued interest	17,600	8,700
Dividends payable	16,400	16,400
Accrued compensation	10,500	21,600
Regulatory liabilities	11,600	14,500
Energy Marketing Contract Liabilities, Current	200	800
Deferred income taxes	333,700	313,300
Environmental liabilities	3,000	2,900
Other pension and benefit costs	13,100	14,000
Energy Marketing Contracts Assets, Noncurrent	100	0
Energy Marketing Contract Liabilities, Noncurrent	500	$ 600
Accrued compensation	$ (11,500)

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2026	Dec. 31, 2025
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 6,763	$ 5,412
Common stock, par value (in dollars per share)	$ 486.7	$ 0.4867
Common stock, shares authorized (shares)	75,000,000,000	75,000,000,000
Preferred Stock, Shares Authorized	2,000,000.0	2,000,000,000
Preferred Stock, Par or Stated Value Per Share	$ 10.00	$ 10.00
Preferred Stock, Shares Issued	0	0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2026	Mar. 31, 2025
Operating Activities
Net Income	$ 59.3	$ 50.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	21.5	22.5
Depreciation and accretion included in other costs	4.3	4.0
Deferred income taxes	20.0	16.5
Realized loss on commodity contracts and sale of assets	0.0	(1.1)
Unrealized loss on investments and commodity contracts	0.4	0.4
Employee benefits and compensation	0.1	0.0
Share-based compensation	3.5	2.3
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(11.3)	(13.9)
Propane inventory, storage gas and other inventory	5.2	1.6
Regulatory assets and liabilities, net	1.4	3.6
Prepaid expenses and other current assets	1.3	1.6
Accounts payable and other accrued liabilities	9.4	2.9
Income taxes receivable	5.0	1.9
Customer deposits and refunds	(3.2)	(3.7)
Accrued compensation	(11.5)	(14.6)
Other assets and liabilities, net	3.7	(1.3)
Net cash provided by operating activities	118.0	85.0
Investing Activities
Property, plant and equipment expenditures	(141.9)	(113.8)
Proceeds from sale of assets	0.1	0.6
Environmental expenditures	(0.1)	(0.1)
Net cash used in investing activities	(141.7)	(113.1)
Financing Activities
Common stock dividends	(16.2)	(14.5)
Proceeds from issuance of common stock, net of expenses	5.2	19.8
Tax withholding payments related to net settled stock compensation	(2.0)	(1.0)
Change in cash overdrafts due to outstanding checks	(0.4)	(1.7)
Net borrowings under line of credit agreements	42.0	20.3
Repayment of long-term debt and finance lease obligation	(2.0)	(2.0)
Net cash provided by financing activities	26.6	20.9
Net Increase (Decrease) in Cash and Cash Equivalents	2.9	(7.2)
Cash and Cash Equivalents—Beginning of Period	1.8	7.9
Accrued compensation	(11.5)	(14.6)
Net Income	59.3	50.9
Depreciation and amortization	21.5	22.5
Depreciation and accretion included in other costs	4.3	4.0
Deferred Income Tax Expense (Benefit)	20.0	16.5
Gain (Loss) on Disposition of Property Plant Equipment, Excluding Oil and Gas Property and Timber Property	0.0	1.1
Unrealized Gain (Loss) on Commodity Contracts	(0.4)	(0.4)
Employee benefits and compensation	0.1	0.0
Share-based compensation	3.5	2.3
Increase (Decrease) in Accounts Receivable	11.3	13.9
Increase (Decrease) in Inventories	(5.2)	(1.6)
Increase (Decrease) in Regulatory Assets and Liabilities	(1.4)	(3.6)
Increase (Decrease) in Prepaid Expense and Other Assets	(1.3)	(1.6)
Accounts payable and other accrued liabilities	9.4	2.9
Increase (Decrease) in Income Taxes Receivable	(5.0)	(1.9)
Customer deposits and refunds	(3.2)	(3.7)
Increase (Decrease) in Interest Payable, Net	8.9	11.4
Increase (Decrease) in Other Operating Assets and Liabilities, Net	(3.7)	1.3
Cash Provided by (Used in) Operating Activity, Including Discontinued Operation	118.0	85.0
Payments to Acquire Property, Plant, and Equipment	141.9	113.8
Proceeds from sale of assets	0.1	0.6
Environmental expenditures	(0.1)	(0.1)
Net cash used in investing activities	(141.7)	(113.1)
Payments of Ordinary Dividends, Common Stock	16.2	14.5
Proceeds from issuance of common stock, net of expenses	5.2	19.8
Payment, Tax Withholding, Share-based Payment Arrangement	2.0	1.0
Change in cash overdrafts due to outstanding checks	(0.4)	(1.7)
Net borrowings under line of credit agreements	42.0	20.3
Repayments of Long-term Debt	2.0	2.0
Net cash provided by financing activities	26.6	20.9
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect	2.9	(7.2)
Cash and cash equivalents	$ 4.7	$ 0.7

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Millions	Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock, Common
Increase (Decrease) in Stockholders' Equity [Roll Forward]