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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549



FORM 10-K

(Mark One)

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the Fiscal Year Ended: December 31, ~~2024~~2025

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

Commission File Number: 001-11590



CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)


State of Delaware						51-0064146
(State or other jurisdiction of						(I.R.S. Employer
incorporation or organization)						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	Name of each exchange on which registered
Common Stock—par value per share $0.4867	CPK	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

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 the 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by a check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☒

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, ~~2024~~2025, the last business day of its most recently completed second fiscal quarter, based on the last sale price on that date, as reported by the New York Stock Exchange, was approximately $2.38 billion.

The number of shares of Chesapeake Utilities Corporation's common stock outstanding as of February 2423, ~~2025~~2026 was 2223,~~982~~936,~~417~~406.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chesapeake Utilities Corporation Proxy Statement for the ~~2025~~2026 Annual Meeting of Stockholders are incorporated by reference in Part II and Part III hereof.

Table of Contents

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, ~~2024~~2025

TABLE OF CONTENTS

			Page
Part I			1
Item 1. Business			3
Item 1A. Risk Factors			1615
Item 1B. Unresolved Staff Comments			24
Item 1C. Cybersecurity			24
Item 2. Properties			2625
Item 3. Legal Proceedings			2726
Item 4. Mine Safety Disclosures			2726
Part II			2726
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities			2726
Item 6. Reserved			29
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations			29
Item 7A. Quantitative and Qualitative Disclosures About Market Risk			5354
Item 8. Financial Statements and Supplementary Data			5556
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure			104
Item 9A. Controls and Procedures			104
Item 9B. Other Information			~~105~~104
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspection			105
Part III			105
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance			105
Item 11. Executive Compensation			105
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters			105
Item 13. Certain Relationships and Related Transactions, and Director Independence			105
Item 14. Principal Accounting Fees and Services			105
Part IV			106
Item 15. Exhibits, Financial Statement Schedules			106
Item 16. Form 10-K Summary			111
Signatures			111

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GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification issued by the FASB

Adjusted Gross Margin: aA 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

CFG: Central Florida Gas Company, a division of Chesapeake Utilities

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 (from 10:00 am to 10:00 am) falls above (CDD) or below (HDD) 65 degrees Fahrenheit

Delmarva Peninsula: A peninsula on the east coast of the U.S. occupied by Delaware and portions of Maryland and Virginia

Diversified Energy: anAn entity from whom we acquired certain propane operating assets in North Carolina, South Carolina, Virginia, and Pennsylvania

DRIP: Dividend Reinvestment and Direct Stock Purchase Plan

Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value

Dts/d: Dekatherms per day

Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake Utilities

Eight Flags: Eight Flags Energy, LLC, a wholly-owned subsidiary of Chesapeake Utilities

Elkton Gas: Elkton Gas Company, a wholly-owned subsidiary of Chesapeake Utilities

FASB: Financial Accounting Standards Board

FCG or Florida City Gas: Pivotal Utility Holdings, Inc., doing business as Florida City Gas, a wholly-owned subsidiary of Chesapeake Utilities that was acquired from Florida Power & Light Company on November 30, 2023

FERC: Federal Energy Regulatory Commission

FGT: Florida Gas Transmission Company, an unaffiliated pipeline network that supplies natural gas to FPU ~~and FCG~~

Florida Natural Gas: Refers to the Company’s legacy Florida natural gas distribution operations (excluding FCG) that were consolidated under FPU, for both rate-making and operations purposes

Florida OPC: The Office of Public Counsel, an agency established by the Florida legislature who advocates on behalf of Florida's utility consumers prior to actions or rule changes

FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities

GAAP: Generally Accepted Accounting Principles ~~in the U.S.~~

Gross Margin: A term which is the excess of sales over costs of goods sold

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~~GRIP~~GUARD: Gas ~~Reliability~~Utility ~~Infrastructure~~Access ~~Program~~and Replacement Directive, ~~with~~a ~~spending~~PSC ~~completed~~approved ~~during~~capital ~~2023~~infrastructure program to enhance the safety, reliability and accessibility of portions of FPU's natural gas distribution system

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 the Company’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

MW: Megawatt, which is a unit of measurement for electric power or capacity

NOL: Net operating loss(es)

Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake Utilities

Peoples Gas: Peoples Gas System, an Emera Incorporated subsidiary

PHMSA: United States Department of Transportation Pipeline and Hazardous Materials Safety Administration

Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have previously issued Senior Notes and which is a party to the current Prudential Shelf Agreement, as amended

PSC: Public Service Commission, which is the state agency that regulates utility rates and/or services in certain of our jurisdictions

Revolver: Our $450.0 million unsecured revolving credit facility with certain lenders

RNG: Renewable natural gas

ROE: Return on equity

RSAM: Reserve surplus amortization mechanism which was approved by the Florida PSC and was applicable to FCG prior to being completely utilized by December 31, 2024.

Sandpiper Energy: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities

SAFE: Safety, Access, and Facility Enhancement, a PSC approved capital infrastructure 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

TETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline

~~Table~~Transco: ofTranscontinental ~~Contents~~Gas Pipe Line Company, LLC, an interstate pipeline interconnected with Eastern Shore's pipeline

Transco: Transcontinental Gas Pipe Line Company, LLC

U.S.: The United States of America

Table of Contents

PART I

References in this document to “Chesapeake,” “Chesapeake Utilities,” the “Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.

Safe Harbor for Forward-Looking Statements

We make statements in this Annual Report on Form 10-K (this "Annual 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, 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 timeframes, and whether the related costs are adequately covered by insurance or recoverable in rates;

•the impact of climate change, including the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change;

•the impact of significant changes to ~~current~~ tax regulations and rates;

•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 effect that a new 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) 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;

•our ability to access the credit and capital markets to execute our business strategy, including our ability to obtain increased amounts of debt and equity 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;

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 1

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•the impact on our costs and funding obligations, under our pension and other post-retirement 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.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 2

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ITEM 1. Business.

Corporate Overview and Strategy

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, the Company’s 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.

Operating Segments

We conduct operations within two reportable segments: Regulated Energy and Unregulated Energy. The remainder of our operations are presented as "Other businesses and eliminations" which were not material to our earnings or our financial position at December 31, ~~2024~~2025. These segments are described below in detail.

Regulated Energy

Overview

Our regulated energy businesses are comprised of natural gas and electric distribution, as well as natural gas transmission services.

On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement, pursuant to the previously disclosed stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment. FCG currently serves approximately ~~123~~125,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. ~~Its natural gas system includes approximately 3,982 miles of distribution main and 80 miles of transmission pipe.~~ Results for FCG are included within our consolidated results from the acquisition date.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 3

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The following table presents net income for the year ended December 31, ~~2024~~2025 and total assets as of December 31, ~~2024~~2025, by operation and area served:

Operations

Areas Served

Net Income

Total Assets

(in millions)

Natural Gas Distribution

Florida Natural Gas

Florida

26.4

617.1

FPU

Florida

33.2

702.9

Florida City Gas

Florida

13.5

1,106.9

FCG

Florida

5.2

1,133.7

Delmarva Natural Gas (1)

Delaware/Maryland

1218.1

~~449~~490.52

Natural Gas Transmission

Eastern Shore

Delaware/Maryland/Pennsylvania

2528.20

~~508~~599.93

Peninsula Pipeline

Florida

1425.76

~~165~~275.57

Aspire Energy Express

Ohio

0.96

6.8.6

Electric Distribution

FPU

Florida

59.10

~~188~~214.29

Total Regulated Energy

97119.97

3,~~042~~425.93

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

Revenues in the Regulated Energy segment are based on rates regulated by the PSC in the states in which we operate or, in the case of Eastern Shore which is an interstate business, by the FERC. The rates are designed to generate revenues to recover all prudent operating and financing costs and provide a reasonable return for our stockholders. Each of our distribution and transmission operations has a rate base, which generally consists of the original cost of the operation's plant (less accumulated depreciation), working capital and other assets. For Delmarva Natural Gas and Eastern Shore, rate base also includes deferred income tax liabilities and other additions or deductions. The ~~Florida~~FPU ~~Natural~~natural ~~Gas~~gas, FCG, and FPU electric regulated energy operations do not include deferred income tax liabilities in their rate base.

Our natural gas and electric distribution operations bill customers at standard rates approved by their respective state PSC. Each state PSC allows us to negotiate rates, based on approved methodologies, for large customers that can switch to other fuels. Some of our customers in Maryland receive propane through underground distribution systems in Worcester County. We bill these customers under PSC-approved rates and include them in the natural gas distribution results and customer statistics.

Our natural gas and electric distribution operations earn profits on the delivery of natural gas or electricity to customers. The cost of natural gas or electricity that we deliver is passed through to customers under PSC-approved fuel cost recovery mechanisms. The mechanisms allow us to adjust our rates on an ongoing basis without filing a rate case to recover changes in the cost of the natural gas and electricity that we purchase for customers. Therefore, while our distribution operating revenues fluctuate with the cost of natural gas or electricity we purchase, our distribution adjusted gross margin is generally not impacted by fluctuations in the cost of natural gas or electricity.

Our natural gas transmission operations bill customers under rate schedules approved by the FERC or at rates negotiated with customers.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 4

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Operational Highlights

The following table presents operating revenues, volumes and the average number of customers by customer class for our natural gas and electric distribution operations for the year ended December 31, ~~2024~~2025:

	Delmarva Natural Gas Distribution				FloridaNatural Gas Distribution				~~FloridaCity Gas Distribution~~				FPUElectricDistribution	~~FPUElectricDistribution~~
Operating Revenues (in millions)
Residential	$	79101.46	6261	%	$	48112.83	2931	%	$	~~52.4~~	37	%		$	5049.39	5448	%
Commercial and Industrial	4754.72		3732	%	~~107~~194.41		6354	%	~~69.1~~		49	%		4844.15		5243	%
Other (1)	111.79		17	%	1455.18		815	%	~~18.8~~		14	%		(59.8)5		~~(6)~~9	%
Total Operating Revenues	$	~~128~~167.87	100	%	$	~~170~~362.32	100	%	$	~~140.3~~	~~100~~	%		$	92103.69	100	%
Volumes (in Dts for natural gas/MW Hours for electric)
Residential	45,~~502~~408,~~823~~011		2934	%	24,~~315~~172,~~717~~387		57	%	~~1,805,825~~		10	%		~~311~~318,~~628~~748		4446	%
Commercial and Industrial	10,~~559~~300,~~929~~217		6964	%	3847,~~377~~550,~~357~~094		9082	%	~~11,260,037~~		59	%		~~396~~366,~~393~~853		5654	%
Other	~~280~~293,~~468~~693		2	%	26,~~139~~346,~~372~~023		511	%	~~5,938,383~~		31	%		—		—	%
Total Volumes	1516,~~343~~001,~~220~~921		100	%	4258,~~832~~068,~~446~~504		100	%	~~19,004,245~~		~~100~~	%		~~708~~685,~~021~~601		100	%
Average Number of Customers (2)
Residential	~~101~~105,~~610~~737		9293	%	91211,~~839~~478		92	%	~~113,917~~		93	%		2526,~~756~~026		78	%
Commercial and Industrial	8,~~379~~482		87	%	817,~~517~~340		8	%	~~8,561~~		7	%		7,~~350~~490		22	%
Other	2526		—	%	—131		—	%	~~113~~		~~<1%~~			—		—	%
Total Average Number of Customers	~~110~~114,~~014~~245		100	%	~~100~~228,~~356~~949		100	%	~~122,591~~		~~100~~	%		33,~~106~~516		100	%

(1) Operating Revenues from "Other" sources include revenue, unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges, fees for billing services provided to third parties, and adjustments for pass-through taxes.

(2) Average number of customers is based on the twelve-month average for the year ended December 31, ~~2024~~2025.

The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, ~~2024~~2025, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, ~~2024~~2025. Aspire Energy Express has been excluded from the table below and had operating revenue of $1.5 million and firm transportation capacity of 300,000 Dts/d for the year ended December 31, ~~2024~~2025:

	Eastern Shore				Peninsula Pipeline
Operating Revenues (in millions)
Local distribution companies - affiliated (1)	$	3538.24	4344	%	$	3250.30	9495	%
Local distribution companies - non-affiliated	2223.31		2726	%	—		—	%
Commercial and industrial - affiliated	—		—	%	1.12		32	%
Commercial and industrial - non-affiliated	2324.9		29	%	0.5		1	%
Other (2)	0.35		1	%	01.61		2	%
Total Operating Revenues	$	8186.79	100	%	$	3452.58	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	167,~~595~~795		52	%	~~907~~1,~~501~~080,571		99	%
Local distribution companies - non-affiliated	56,576		18	%	—		—	%
Commercial and industrial - affiliated	—		—	%	1,500		—<1%	%
Commercial and industrial - non-affiliated	96,040		30	%	5,100		1	%
Total Contracted firm transportation capacity	320,~~211~~411		100	%	~~914~~1,~~101~~087,171		100	%
Design day capacity (in Dts/d)	320,~~211~~411		100	%	~~914~~1,~~101~~087,171		100	%

Chesapeake Utilities Corporation 2025 Form 10-K Page 5

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(1) Eastern Shore's and Peninsula Pipeline's service to our local distribution affiliates is based on the respective regulator's approved rates and is an integral component of the cost associated with providing natural gas supplies to the end users of those affiliates. We eliminate operating revenues of these entities against the natural gas costs of those affiliates in our consolidated financial information; however, our local distribution affiliates include this amount in their purchased fuel cost and recover it through fuel cost recovery mechanisms.

(2) Operating revenues from "Other" sources include the rental of gas properties.

Chesapeake Utilities Corporation 2024 Form 10-K Page 5

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Regulatory Overview

The following table highlights key regulatory information that was effective for each of our principal Regulated Energy operations at December 31, ~~2024~~2025. Peninsula Pipeline and Aspire Energy Express are not regulated with regard to cost of service by either the Florida PSC, the Ohio PUC or the FERC and are therefore excluded from the table. See Item 8, Financial Statements and Supplementary Data (Note 1817, Rates and Other Regulatory Activities, in the consolidated financial statements) for further discussion on the impact of this legislation on our regulated businesses.

Natural Gas Distribution

Delmarva

Florida

~~Florida~~Electric Distribution

Natural Gas Transmission

~~Electric Distribution~~

~~Natural Gas Transmission~~

Operation/Division

Delaware ~~(1)~~

Maryland ~~(2)~~

~~Sandpiper (2)~~FPU

~~Elkton~~FCG ~~Gas~~ (21) ~~(3)~~

~~Florida Natural Gas~~FPU

~~Florida~~Eastern ~~City Gas~~Shore

~~FPU (4)~~

~~Eastern Shore~~

Regulatory Agency

Delaware PSC

Maryland PSC

Florida PSC

~~Florida PSC~~

FERC

~~FERC~~

Effective date - Last Rate Order

015/011/~~2017~~2025

124/0119/~~2007~~2025

1203/01/~~2019~~2023

0206/0709/~~2019~~2023

033/0120/~~2023~~2025

0608/0901/~~2023~~2017

~~10/08/2020~~

~~08/01/2017~~

Rate Base (in Rates) (in millions)

Not stated

~~Not stated~~$453.7

~~Not stated~~$487.3

~~$453.7~~Not stated

~~$487.3~~Not stated

~~$24.9~~

~~Not stated~~

Annual Rate Increase Approved (in millions)

$26.31

$03.65

~~N/A(5)~~$17.2

$014.1

$178.26

$149.18

~~$3.4 base rate and $7.7 from storm surcharge~~

~~$9.8~~

Capital Structure (in rates) (6)*

Not stated

LTD: 42% STD: 5% Equity: 53%

Not stated

LTD: 50% Equity: 50%

LTD: 33%STD: 5% Equity: 45% Other: 17%

LTD: 31% STD: 4% Equity: 53% Other: 12%

LTD: 22% STD: 23% Equity: 55%

Not stated

Capital Structure (in rates) (2)*

Not stated

LTD: 33%STD: 5% Equity: 45% Other: 17%

LTD: 31% STD: 4% Equity: 53% Other: 12%

LTD: Not statedSTD: Not statedEquity: 50.04%

Not stated

Allowed ROE (7)

9.75%

10.75%

Not stated (8)

9.80%

10.25%

9.50%

10.25% (9)

Not stated

Allowed ROE (3)

9.60%

6.88% (4)

10.25%

9.50%

10.20%

Not stated

TJCA Refund Status associated with customer rates

Refunded

~~Refunded~~Retained

~~N/A~~Refunded

~~Retained~~Refunded

Refunded

~~Refunded~~

(1) In ~~August~~See ~~2024,~~additional ~~our~~information ~~Delaware~~below ~~natural~~regarding ~~gas~~FCG's ~~division~~February ~~filed~~2026 annotice ~~application~~to ~~for~~the aFlorida ~~natural~~PSC ~~gas~~of ~~rate~~its ~~case~~intent ~~with~~to ~~the~~file ~~Delaware~~a ~~PSC.~~petition ~~Additional~~seeking ~~details~~a ~~related~~general torate ~~the~~base ~~filing are disclosed below~~increase.

(2) InOther ~~January~~components ~~2024,~~of ~~our~~capital ~~natural~~structure ~~gas~~include ~~distribution~~customer ~~businesses in Maryland~~deposits, ~~CUC-Maryland~~deferred ~~Division,~~income ~~Sandpiper~~taxes ~~Energy, Inc.,~~ and ~~Elkton~~tax Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC additional details regarding the filing are disclosed belowcredits.

(3) ~~The~~Allowed ~~rate~~after-tax ~~increase and allowed~~ ROE ~~for Elkton Gas were approved by the Maryland PSC before we acquired the company~~.

(4) InAllowed ~~August~~rate ~~2024,~~of ~~our~~return ~~Florida~~as ~~Electric~~stated ~~division filed a petition with the Florida PSC. Additional details~~ in ~~connection~~final ~~with the petition are disclosed below~~order.

(5) The terms of the agreement include revenue neutral rates for the first year (December 1, 2016 through November 30, 2017), followed by a schedule of rate reductions in subsequent years based upon the projected rate of propane to natural gas conversions.

(6) Other components of capital structure include customer deposits, deferred income taxes and tax credits.

(7) Allowed after-tax ROE.

(8) The Maryland PSC approved a declining ROE.

(9) The terms of the settlement agreement for the FPU electric division limited proceeding with the Florida PSC prescribed an authorized ROE range of 9.25 to 11.25 percent, with a mid-point of 10.25 percent.

* LTD-Long-term debt; STD-Short-term debt.

In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we ~~are~~sought ~~seeking~~ 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 which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. InA August 2024, the Maryland natural gas distribution businesses, the Maryland Office of Peoples' Counsel ("OPC") and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. ~~In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million~~ increase in annual base rates was approved, and the Company filed ~~the~~a Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The ~~discovery~~hearing ~~process~~was ~~for~~held in March 2025, during which Phase II ~~has~~was ~~commenced~~approved, ~~and~~including ~~the~~an ~~hearing~~additional ~~has~~$0.9 ~~been~~million ~~scheduled~~in revenue requirement for ~~March~~a ~~2025.~~total ~~The~~cumulative ~~outcome~~increase of ~~the~~$3.5 ~~application~~million. isA ~~subject~~final toorder ~~review~~was issued in April 2025 and included approval byof the consolidation of the operations and the assets of CUC-Maryland ~~PSC~~Division, Sandpiper Energy, and Elkton Gas into one entity, which was renamed and operates as Chesapeake Utilities of Maryland, Inc.

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

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6

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~~effective~~In asAugust 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of ~~January~~$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, ~~2023~~were approved and became effective in November 2024. ~~The~~In March 2025, the Florida PSC approved ~~depreciation~~the ~~resulted~~permanent inrate anincrease, ~~annual~~but ~~reduction~~the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to resolve all outstanding issues. This settlement which was approved by the Florida PSC in ~~depreciation~~July ~~expense~~2025, provides for a total revenue increase of approximately $8.6 million on an annual basis, with $1.20 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.

In August 2024, our ~~Florida~~Delaware ~~Electric~~natural gas division filed an application for a ~~petition~~natural gas rate case with the ~~Florida~~Delaware PSC seeking aapproval ~~general~~of ~~base~~the following: (i) permanent rate ~~increase~~relief of approximately $12.61 million with a ROE of 11.35 percent; ~~based~~(ii) onproposed changes to depreciation rates which were part of a ~~2025~~depreciation ~~projected~~study ~~test~~also ~~year~~submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates ofwere ~~approximately~~approved by the Delaware PSC in the amount of $12.85 million, ~~were approved~~ and became effective in ~~November~~October 2024. ~~The~~A ~~outcome~~settlement ofamong the ~~application~~Company, isPSC ~~subject~~staff toand ~~review~~the Delaware Division of the Public Advocate was reached and ~~approval~~approved by the ~~Florida~~Delaware PSC. ~~The~~in ~~hearings~~June ~~for~~2025 ~~the~~providing ~~approval~~an annual revenue increase of $6.1 million, as well as dividing the ~~revenue~~rate ~~requirement~~case ~~and~~into ~~rates~~two ~~are~~phases. ~~scheduled~~Rates set to ~~occur~~recover the approved components of the increase were effective in March 2025. In October 2025, a settlement was reached for Phase II of the rate case addressing tariff-related changes including rate design and approved by the Delaware Public Service Commission with rates effective as of October 15, 2025.

In ~~August~~May ~~2024~~2022, ~~our~~FCG ~~Delaware~~filed ~~natural~~a ~~gas~~general ~~division~~base ~~filed~~rate anincrease ~~application~~with ~~for~~the aFlorida ~~natural~~PSC ~~gas~~based ~~rate~~on ~~case~~a ~~with~~projected ~~the~~2023 ~~Delaware~~test ~~PSC~~year. In ~~connection~~June ~~with~~2023, the ~~application,~~Florida wePSC ~~are~~issued ~~seeking~~an ~~approval~~order approving a single total base revenue increase of ~~the~~$23.3 ~~following:~~million (i)which ~~permanent~~included ~~rate~~an ~~relief~~incremental increase of ~~approximately~~ $1214.1 million, ~~with~~a ~~ROE~~previously approved increase of 11$3.8 million for a liquefied natural gas facility, and $5.3 ~~percent;~~million ~~(ii)~~to ~~proposed~~transfer ~~changes~~the SAFE investments from a rider clause to ~~depreciation~~base rates), ~~which~~with ~~were~~new ~~part~~rates becoming effective as of aMay ~~depreciation~~1, ~~study~~2023. The Commission also ~~submitted~~approved FCG's proposed RSAM with ~~the~~a ~~filing;~~$25.0 million reserve amount, continuation and ~~(iii)~~expansion ~~authorization~~of tothe ~~make~~capital ~~certain~~SAFE ~~changes~~program, toimplementation ~~tariffs.~~of ~~Annualized~~an ~~interim~~automated ~~rates~~metering ~~approved~~infrastructure bypilot, and continuation of the ~~Delaware~~storm ~~PSC~~damage inreserve ~~the~~with ~~amount~~a target reserve of $20.58 million. ~~became~~The ~~effective~~RSAM inwas ~~October~~recorded ~~2024.~~as ~~The~~either ~~discovery~~an ~~process~~increase ~~has~~or ~~commenced~~decrease ~~and~~to ~~the~~accrued ~~hearing~~removal ~~for~~costs on the ~~proceeding~~balance ~~has~~sheet, ~~been~~with ~~scheduled~~a ~~for~~corresponding ~~May~~increase ~~2025~~or decrease to depreciation and amortization expense. At December 31, 2024, the RSAM reserve had been completely utilized. The ~~outcome~~Florida OPC filed a notice of appeal with the ~~application~~Florida Supreme Court in July 2023, which is ~~subject~~pending. toThe ~~review~~Florida ~~and~~OPC ~~approval~~filed bytheir ~~the~~initial ~~Delaware~~brief ~~PSC~~in January 2024 with answer briefs filed in April 2024. Oral arguments in the case were held in December 2024.

In ~~May~~February ~~2022~~2025, ~~our~~FCG ~~legacy natural gas distribution businesses~~ filed a ~~consolidated~~depreciation ~~natural~~study ~~gas rate case~~ with the Florida PSC. The application ~~included~~is arequesting ~~request~~approval ~~for the following: (i) permanent rate relief~~ of ~~approximately~~revised ~~$24.1~~annual ~~million, effective in January 2023; (ii) a~~ depreciation ~~study also submitted with the filing; (iii) authorization to make certain changes to tariffs to include the consolidation of~~ rates, ~~and~~as ~~rate~~well ~~structure~~as ~~across~~a ~~the~~reduction ~~businesses~~related ~~and~~ to ~~unify~~a ~~the~~reserve ~~Florida~~imbalance ~~natural~~that ~~gas~~would ~~distribution~~be ~~businesses~~amortized ~~under~~over ~~FPU;~~a ~~(iv)~~two-year ~~authorization~~period. toThe ~~retain~~outcome ~~the acquisition adjustment recorded at the time~~ of the ~~FPU~~application ~~merger~~was insubject ~~our~~to ~~revenue~~review ~~requirement;~~ and ~~(v)~~approval ~~authorization to establish an environmental remediation surcharge for the purposes of addressing future expected remediation costs for FPU MGP sites. In August 2022, interim rates were approved~~ by the Florida PSC ~~in the amount of approximately $7~~.7 ~~million on an annualized basis, effective for all meter readings in September 2022.~~ In ~~January~~February ~~2023~~2026, the Florida PSC approved ~~the~~a ~~application for consolidation and permanent rate relief of approximately~~ $176.28 million onreserve animbalance ~~annual~~to ~~basis.~~be ~~Actual~~amortized ~~rates~~over ~~were~~the ~~approved~~remaining bylife of the ~~Florida~~assets, ~~PSC~~with inthe ~~February~~revised ~~2023~~depreciation ~~which~~rates ~~became~~ effective inas ~~March~~of ~~2023.~~January 1, 2025.

In ~~May~~February ~~2022~~2026, FCG ~~filed~~provided anotice ~~general~~to ~~base rate increase with~~ the Florida PSC ~~based~~of onits aintent ~~projected~~to ~~2023~~file ~~test~~a ~~year.~~petition Inseeking ~~June 2023, the Florida PSC issued an order approving~~ a ~~single~~general ~~total~~rate base ~~revenue~~ increase ofbased ~~$23.3~~on ~~million (which included an incremental increase of $14.1 million,~~ a ~~previously~~2027 ~~approved~~projected ~~increase~~test ~~of $3~~year.8 ~~million~~The ~~for~~rate acase ~~liquefied~~filing ~~natural~~is ~~gas~~expected ~~facility, and $5.3 million~~ to ~~transfer~~be ~~the~~submitted ~~SAFE~~in ~~investments~~April ~~from~~2026 a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed reserve surplus amortization mechanism ("RSAM") with a $25.0 million reserve amount, continuation and ~~expansion of~~ the ~~capital~~outcome ~~SAFE program, implementation~~ of ~~an automated metering infrastructure pilot, and continuation of~~ the ~~storm~~application ~~damage~~will ~~reserve~~be ~~with~~subject ato ~~target~~review ~~reserve~~and ofapproval ~~$0.8~~by ~~million. In June 2023,~~ the Florida ~~OPC filed a motion for reconsideration of the~~ PSC~~’s approval of RSAM, which was denied in September 2023~~. In July 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, 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.

InThe ~~February~~following ~~2025,~~table ~~FCG~~presents ~~filed~~margin astability ~~depreciation~~mechanisms ~~study~~that ~~with~~have been approved by the ~~Florida~~respective PSC for our regulated energy distribution businesses at December 31, 2025. ~~The~~These ~~application~~include: isDelaware ~~requesting~~surcharges ~~approval~~to ofexpand ~~revised~~natural ~~annual~~gas ~~depreciation~~service ~~rates,~~in its service territory as well as afor ~~reduction~~the ~~related~~conversion of propane distribution systems to anatural ~~reserve~~gas; ~~imbalance~~Maryland’s ~~that~~surcharges ~~would~~to befund ~~amortized~~natural ~~over~~gas aconversions ~~two-year~~and ~~period. The~~system ~~outcome~~improvements in Worcester County; Florida’s GUARD surcharge which provides accelerated recovery of the ~~application~~costs isof ~~subject~~replacing older portions of the natural gas distribution system to ~~review~~improve safety and ~~approval~~reliability; byFCG's SAFE surcharge which provides accelerated recovery of the costs of replacing older portions of that natural gas distribution system to improve safety and reliability; and the Florida ~~PSC~~electric distribution operation's limited proceeding which allowed recovery of storm-related costs and the Storm Protection Plan ("SPP") which provides recovery of storm hardening costs.

~~The~~ ~~following~~Chesapeake ~~table~~Utilities ~~presents~~Corporation ~~margin~~2025 ~~stability~~Form mechanisms that have been approved by the respective PSC for our regulated energy distribution businesses at December 31, 2024. These include: Delaware surcharges to expand natural gas service in its service territory as well as for the conversion of propane distribution systems to natural gas; Maryland’s surcharges to fund natural gas conversions and system improvements in Worcester County; Elkton's Strategic Infrastructure Development and Enhanced (STRIDE) plan for accelerated pipeline replacement for older portions of the natural gas distribution system; Florida’s GUARD surcharge which provides accelerated recovery of the costs of replacing older portions of the natural gas distribution system to improve safety and reliability; FCG's SAFE surcharge which provides accelerated recovery of the costs of replacing older portions of that natural gas distribution system to improve safety and reliability; and the Florida electric distribution operation's limited proceeding which allowed recovery of storm10-~~related~~K ~~costs~~Page ~~and the Storm Protection Plan ("SPP") which provides recovery of storm hardening costs.~~7

Chesapeake Utilities Corporation 2024 Form 10-K Page 7

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Operation(s)/Division(s)

Jurisdiction

Infrastructure mechanism

Margin stability mechanism (1)

Delaware division

Delaware

Yes

Maryland division

Maryland

Yes

Maryland division (2)

Maryland

Yes

Sandpiper Energy

Maryland

Yes

FPU natural gas

Florida

Yes

Elkton Gas

Maryland

Yes

FCG (3)

Florida

Yes

Florida Natural Gas

Florida

Yes

Florida City Gas (2)

Florida

Yes

FPU electric division

Florida

Yes

(1) Margin stability mechanisms reduce variability due to rate design, revenue normalization clauses, and other riders.

(2) ~~See~~In ~~Item~~accordance 8,with ~~Financial~~the ~~Statements~~Maryland ~~and~~PSC ~~Supplementary~~approval ~~Data~~of our natural gas base rate proceeding, ~~Note~~effective 18April 2025, ~~Rates~~our ~~and~~natural ~~Other~~gas ~~Regulatory~~distribution ~~Activities~~business in Maryland (Maryland natural gas division, Sandpiper Energy and Elkton Gas) are now consolidated for ~~additional~~rate-making ~~information~~and ~~related~~other topurposes ~~FCG's~~and ~~RSAM~~are ~~that~~reflected ~~was~~on ~~approved~~a asconsolidated ~~part~~basis offor ~~its~~all periods presented consistent with the final rate ~~case~~order. ~~effective~~See asNote of17, ~~May~~Rates 1and Other Regulatory Activities, ~~2023~~for additional information.

(3) See Item 8, Financial Statements and Supplementary Data, Note 17, Rates and Other Regulatory Activities, for additional information related to FCG's RSAM that was approved as part of its rate case effective as of May 1, 2023.

Weather

Weather variations directly influence the volume of natural gas and electricity sold and delivered to residential and commercial customers for heating and cooling and changes in volumes delivered impact the revenue generated from these customers. Natural gas volumes are highest during the winter months, when residential and commercial customers use more natural gas for heating. Demand for electricity is highest during the summer months, when more electricity is used for cooling. We measure the relative impact of weather using degree-days. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature falls above or below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one HDD, and each degree of temperature above 65 degrees Fahrenheit is counted as one CDD. Normal heating and cooling degree-days are based on the most recent 10-year average.

Competition

Natural Gas Distribution

While our natural gas distribution operations do not compete directly with other distributors of natural gas for residential and commercial customers in our service areas, we do compete with other natural gas suppliers and alternative fuel providers for sales to industrial customers. Large customers could bypass our natural gas distribution systems and connect directly to intrastate or interstate transmission pipelines, and we compete in all aspects of our natural gas business with alternative energy sources, including electricity, oil, propane and renewables. The most effective means to compete against alternative fuels are lower prices, superior reliability and flexibility of service. Natural gas historically has maintained a price advantage in the residential, commercial and industrial markets, and reliability of natural gas supply and service has been excellent. In addition, we provide flexible pricing to our large customers to minimize fuel switching and protect these volumes and their contributions to the profitability of our natural gas distribution operations.

Chesapeake Utilities Corporation 2024 Form 10-K Page 8

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Natural Gas Transmission

Our natural gas transmission business competes with other interstate and intrastate pipeline companies to provide service to large industrial, generation and distribution customers, primarily in the northern portion of the Delmarva Peninsula and in Florida. Our transmission business in Ohio, Aspire Energy Express, services one customer, Guernsey Power Station, to which it is the sole supplier.

Electric Distribution

While our electric distribution operations do not compete directly with other distributors of electricity for residential and commercial customers in our service areas, we do compete with other electricity suppliers and alternative fuel providers for sales to industrial customers. Some of our large industrial customers may be capable of generating their own electricity, and we structure rates, service offerings and flexibility to retain these customers in order to retain their business and contributions to the profitability of our electric distribution operations.

Chesapeake Utilities Corporation 2025 Form 10-K Page 8

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Supplies, Transmission and Storage

Natural Gas Distribution

Our natural gas distribution operations purchase natural gas from marketers and producers and maintain contracts for transportation and storage with several interstate pipeline companies to meet projected customer demand requirements. We believe that our supply and capacity strategy will adequately meet our customers’ needs over the next several years and we will continue to adapt our supply strategy to meet projected growth in customer demand within our service territories.

The Delmarva Natural Gas distribution systems are directly connected to Eastern Shore’s pipeline, which has connections to other pipelines that provide us with transportation and storage. These operations can also use propane-air and liquefied natural gas peak-shaving equipment to serve customers. Our Delmarva Peninsula natural gas distribution operations maintain asset management agreements with a third party to manage their natural gas transportation and storage capacity. The current agreements were effective as of April 2023 and expire in March 2026. Our Delmarva operations receive a fee, which we share with our customers, from the asset manager, who optimizes the transportation, storage and natural gas supply for these operations.

Our ~~Florida~~FPU ~~Natural~~natural ~~Gas~~gas distribution business uses Peninsula Pipeline and Peoples Gas system (a subsidiary of Emera Incorporated) to transport natural gas where there is no direct connection with FGT. FPU natural gas distribution and Eight Flags entered into separate 10-year asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity, each of which expires in November 2030. An agreement with Florida Southeast Connection LLC for additional service to Palm Beach County is also in place for an initial term through December 2044. FCG utilizes FGT and Peninsula Pipeline to transport natural gas.

Chesapeake Utilities Corporation 2024 Form 10-K Page 9

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A summary of our pipeline capacity contracts follows:

		Maximum Daily Firm Transportation Capacity (Dts)	Contract Expiration Dates
Division	Pipeline
Delmarva Natural Gas Distribution	Eastern Shore	~~161~~167,~~595~~795	~~2025~~2026-2044
	Columbia Gas (1)	5,246	~~2025-~~2029-2032
	Transco (1)	30,~~419~~439	~~2025~~2026-~~2028~~2032
	TETLP (1)	50,000	2027
Florida Natural Gas	Gulfstream (2)	10,000	2032
FPU natural gas	Gulfstream (2)	10,000	2032
	FGT	4748,~~409~~716 - 7882,~~817~~317	~~2029~~2026-2041
	Peninsula Pipeline	~~362~~399,~~500~~600	2033-2048
	Peoples Gas	12,160	2025-2027
	Peoples Gas system	12,160	2026
	Florida Southeast Connection LLC	5,000	2044
	Southern Natural Gas Company	1,500	2029
Florida City Gas	FGT	32,235 - 68,955	2030
FCG	FGT	32,235 - 68,955	2030
	Peninsula Pipeline	15,000	2033 - 2043

(1) Transco, Columbia Gas and TETLP are interstate pipelines interconnected with Eastern Shore's pipeline.

(2) Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under this agreement has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge.

Eastern Shore has three agreements with Transco for a total of 7,292 Dts/d of firm daily storage injection and withdrawal entitlements and total storage capacity of 288,003 Dts. These agreements expire in March 2028. Eastern Shore retains these firm storage services in order to provide swing transportation service and firm storage service to customers requesting such services.

Aspire Energy Express, our Ohio intrastate pipeline subsidiary, has an agreement to provide natural gas transportation capacity to Guernsey Power Station. ~~Aspire Energy Express completed construction of the gas transmission facilities in the fourth quarter of 2021 and began billing for transportation services in the first quarter of 2022.~~

Chesapeake Utilities Corporation 2025 Form 10-K Page 9

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Electric Distribution

Our Florida electric distribution operation purchases wholesale electricity under the power supply contracts summarized below:


Area Served by Contract	Counterparty	Contracted Amount (MW)	Contract Expiration Date
Northwest Florida	Florida Power & Light Company	Full Requirement*	2032
Northeast Florida	Florida Power & Light Company	Full Requirement*	2032
Northeast Florida	Eight Flags	21	2036
Northeast Florida	Rayonier	1.7 to 3.0	2036
Northeast Florida	WestRock Company	As-available	N/A

*The counter party is obligated to provide us with the electricity to meet our customers’ demand, which may vary.

Chesapeake Utilities Corporation 2024 Form 10-K Page 10

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Unregulated Energy

Overview

The following table presents net income for the year ended December 31, ~~2024~~2025 and total assets as of December 31, ~~2024~~2025, for our Unregulated Energy segment by operation and area served:

Operations	Area Served	Net Income (Loss)		Total Assets
(in millions)
Propane Operations (Sharp, Diversified Energy, FPU and Flo-gas)	Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina, Florida	$	1112.37	$	~~188~~192.41
Energy Transmission (Aspire Energy)	Ohio	45.0		~~146~~150.25
Energy Generation (Eight Flags)	Florida	2.1.7		3130.70
Marlin Gas Services	The Entire U.S.	3.5.1		5966.16
Sustainable investments and other (1)	Various	0(3.12)		6155.08
Total		$	21.03	$	~~486~~495.40

(1) Includes our renewable natural gas projects that are in various stages of development.

Propane Operations

Our propane operations sell propane to residential, commercial/industrial, wholesale and AutoGas customers, in the Mid-Atlantic region, North Carolina, South Carolina and Florida, through Sharp Energy, Inc., Sharpgas, Inc., Diversified Energy, FPU and Flo-gas. We deliver to and bill our propane customers based on two primary customer types: bulk delivery customers and metered customers. Bulk delivery customers receive deliveries into tanks at their location. We invoice and record revenues for these customers at the time of delivery. Metered customers are either part of an underground propane distribution system or have a meter installed on the tank at their location. We invoice and recognize revenue for these customers based on their consumption as dictated by scheduled meter reads. As a member of AutoGas Alliance, we install and support propane vehicle conversion systems for vehicle fleets and provide on-site fueling infrastructure.

Chesapeake Utilities Corporation 2025 Form 10-K Page 10

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Propane Operations - Operational Highlights

For the year ended December 31, ~~2024~~2025, operating revenues, volumes sold and average number of customers by customer class for our propane operations were as follows:

	Operating Revenues (in millions)				Volumes (in thousands of gallons)			Average Number of Customers (1)
Residential bulk	$	4754.69	3032	%	1517,~~842~~538	22	%	6167,~~166~~604	7273	%
Residential metered	1417.92		910	%	45,~~545~~220	67	%	1615,~~479~~320	1917	%
Commercial bulk	4044.40		26	%	2223,~~013~~549	30	%	79,~~761~~095	910	%
Commercial metered	1.76		1	%	~~571~~538	1	%	~~214~~218	<1%
Wholesale	2426.1		15	%	2426,~~513~~645	34	%	3148	<1%
AutoGas	7.69		54	%	5,~~168~~134	76	%	87117	<1%
Other (2)	2119.69		1412	%	—	—	%	—	—	%
Total	$	~~157~~171.96	100	%	7278,~~652~~624	100	%	8592,~~738~~402	100	%

(1) Average number of customers is based on a twelve-month average for the year ended December 31, ~~2024~~2025.

(2) Operating revenues from "Other" sources include revenues from customer loyalty programs; delivery, service and appliance fees; and unbilled revenues.

Chesapeake Utilities Corporation 2024 Form 10-K Page 11

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Competition

Our propane operations compete with national and local independent companies primarily on the basis of price and service. Propane is generally a lower cost fuel alternative for home heating compared to oil and electricity but more expensive than natural gas. Our propane operations are largely concentrated in areas that are not currently served by natural gas distribution systems.

Supplies, Transportation and Storage

We purchase propane from major oil companies and independent natural gas liquids producers. Propane is transported by truck and rail to our bulk storage facilities in Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina and Florida which have a total storage capacity of 8.54 million gallons. Deliveries are made from these facilities by truck to tanks located on customers’ premises or to central storage tanks that feed our underground propane distribution systems. While propane supply has traditionally been adequate, significant fluctuations in weather, closing of refineries and disruption in supply chains, could cause temporary reductions in available supplies.

Weather

Propane revenues are affected by seasonal variations in temperature and weather conditions, which directly influence the volume of propane used by our customers. Our propane revenues are typically highest during the winter months when propane is used for heating. Sustained warmer-than-normal temperatures will tend to reduce propane use, while sustained colder-than-normal temperatures will tend to increase consumption.

Unregulated Energy Transmission and Supply (Aspire Energy)

Aspire Energy owns approximately 2,800 miles of natural gas pipeline systems in 40 counties in Ohio. The majority of Aspire Energy’s revenues are derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative ("CGC"), which together serve more than 23,000 end-use customers. Aspire Energy purchases natural gas to serve these customers from conventional producers in the Marcellus and Utica natural gas production areas. In addition, Aspire Energy's Noble Road Landfill RNG pipeline transports RNG generated from the landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In ~~2024~~2025, the RNG volumes represented approximately 10 percent of Aspire Energy’s gas gathering volumes and are anticipated to continue at such rate in ~~2024~~2025 and beyond. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

~~For~~ ~~the~~Chesapeake ~~year~~Utilities ~~ended~~Corporation ~~December 31,~~2025 ~~2024,~~Form ~~Aspire~~10-K ~~Energy's~~Page ~~operating revenues and deliveries by customer type were as follows:~~11

	Operating revenues				Deliveries
	(in millions)		% of Total		(in thousands Dts)	% of Total
Supply to Columbia Gas of Ohio	$	12.5	35	%	2,463	36	%
Supply to CGC	14.6		42	%	1,784	26	%
Supply to Marketers	5.0		14	%	2,500	37	%
Other (including natural gas gathering and processing)	3.0		9	%	42	1	%
Total	$	35.1	100	%	6,789	100	%

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For the year ended December 31, 2025, Aspire Energy's operating revenues and deliveries by customer type were as follows:


	Operating revenues				Deliveries
	(in millions)		% of Total		(in thousands Dts)	% of Total
Supply to Columbia Gas of Ohio	$	17.3	34	%	2,716	35	%
Supply to CGC	21.2		42	%	2,164	27	%
Supply to Marketers	9.6		19	%	2,890	37	%
Other (including natural gas gathering and processing)	2.3		5	%	54	1	%
Total	$	50.4	100	%	7,824	100	%

Energy Generation (Eight Flags)

Eight Flags generates electricity and steam at its CHP plant located on Amelia Island, Florida. The plant is powered by natural gas transported by Peninsula Pipeline and our ~~Florida~~FPU ~~Natural~~natural ~~Gas~~gas distribution business and produces approximately 21 MW of electricity and 75,000 pounds per hour of steam. Eight Flags sells the electricity generated from the plant to our Florida electric distribution operation and sells the steam to the customer who owns the site on which the plant is located, both under separate 20-year contracts.

Marlin Gas Services

Marlin Gas Services is a supplier of mobile CNG/RNG and virtual pipeline solutions, primarily to utilities, pipelines, and ~~pipelines~~RNG producers. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. These services are provided by a highly trained staff of drivers and maintenance technicians who are all certified to meet/exceed PHMSA standards to safely perform ~~these~~pipeline functions throughout the United States. Marlin Gas Services maintains a fleet of CNG trailers, mobile compression equipment, LNG tankers and vaporizers, and an internally developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas. Marlin Gas Services continues to actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to serve LNG and RNG market needs.

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actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to serve LNG and RNG market needs.

Sustainable Investments

Our sustainable investments are comprised primarily of our renewable natural gas projects that are in various stages of development. Included in these are the assets and intellectual property of Planet Found that we acquired during the fourth quarter of 2022, whose farm scale anaerobic digestion pilot system and technology produces biogas from poultry litter. In addition, we constructed a dairy manure RNG facility that we own and operate at Full Circle Dairy in Madison County, Florida. The project consists of a facility converting dairy manure to RNG and transportation assets to bring the gas to market~~, with capital expenditures totaling $27~~.5 ~~million through December 31, 2024.~~ The facility became operational ~~in 2024,~~ with the first injection of RNG during the second quarter of 2024.

Environmental Matters

See Item 8, Financial Statements and Supplementary Data (Note 1918, Environmental Commitments and Contingencies, in the consolidated financial statements).

Human Capital Initiatives

Our tradition of serving employees, customers, investors, partners and communities is at the core of our special culture. Our unique culture is grounded in a solid foundation of regulated businesses, but enhanced by an entrepreneurial, innovative and competitive market mindset. Among the ongoing initiatives across our enterprise, we highlight below the importance of our culture of safety, our team, and our commitment to supporting a more sustainable future.

Workplace Health and Safety

We are committed to ensuring safety is at the center of our culture and the way we do business. The importance of safety is exhibited throughout the entire organization, with the direction and tone set by both the ~~Board~~BOD ~~of Directors~~ and our President and CEO, and evidenced through required attendance at monthly safety meetings, routine safety training and the inclusion of safety moments at key team meetings. Additionally, we remain committed to providing products and services to our customers in a safe and reliable manner.

ToChesapeake ~~maintain~~Utilities ~~safety~~Corporation as2025 aForm priority, our employees remain committed and work together to ensure that our plans, programs, policies and behaviors are aligned with our aspirations as a Company. The achievement of superior safety performance is both an important short10-~~term~~K ~~and~~Page long-term strategic initiative in managing our operations. Our state-of-the art training facilities called, Safety Towns, located in Dover, Delaware and DeBary Florida, now serve as resources for training our employees who build, maintain and operate our natural gas infrastructure, offering hands-on training and fully immersive, on-the-job field experiences. First responders and other community partners also benefit from the simulated environment and conditions they could encounter as they enter homes in the community. 12

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Maintaining safety as a priority requires shared responsibility. Our employees remain committed and work together to ensure that our plans, programs, policies, and behaviors are aligned with our aspirations as a Company. The achievement of superior safety performance is both an important short-term and long-term strategic initiative in managing our operations. To support this commitment, the Company has invested heavily in safety and simulation training programs.

Our state-of-the art training facilities known as Safety Towns, located in Dover, Delaware and DeBary Florida, now serve as resources for training our employees who build, maintain and operate our natural gas infrastructure. The facilities offer hands-on training and fully immersive, on-the-job field experiences. The Company conducts live simulations and has adopted the National Incident Management Systems ("NIMS") approach to emergency response. First responders and other community partners also benefit from the realistic scenario-based training based on conditions they could encounter as they enter homes in the community.

Our Team Drives Our Performance

Our employees are the key to our success. Our leadership and human resources teams are responsible for attracting and retaining top talent and as an equal opportunity employer committed to creating a diverse workforce, we consider all qualified applicants without regard to race, religion, color, sex, national origin, age, sexual orientation, gender identity, disability or veteran status, among other factors. Our senior management team includes a Chief Human Resources Officer, with expertise in diverse candidate recruitment, to ensure that we continue to expand our candidate pools to better reflect the diverse demographics of the communities we serve.

Throughout our organization, we seek to promote from within, reviewing strategic positions regularly and identifying potential internal candidates to fill those positions, evaluating critical job skill sets to identify competency gaps and creating developmental plans to facilitate employee professional growth, as well as succession plans for key positions throughout the organization. We provide training and development programs, including many forms of training on our internal learning platform, as well as tuition reimbursement to promote continued professional growth.

We had more than 1,~~200~~300 employees at December 31, ~~2024~~2025, ~~194~~186 of whom are union employees represented by two labor unions: the International Brotherhood of Electrical Workers ("IBEW") and the United Food and Commercial Workers Union. The collective bargaining agreements covering our employees with these labor unions expire in ~~late~~2027 ~~2025~~and 2028, respectively. We consider our relationships with employees, including those covered by collective bargaining agreements, to be in good standing. We provide a competitive Total Rewards package for our employees including health insurance coverage, wellness initiatives, retirement savings benefits, paid time off, employee assistance programs, educational and tuition reimbursement, competitive pay, career growth opportunities, paid volunteer time, and a culture of recognition.

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retirement savings benefits, paid time off, employee assistance programs, educational and tuition reimbursement, competitive pay, career growth opportunities, paid volunteer time, and a culture of recognition.

We listen to our employees and actively seek their input and feedback. Many of the initiatives we have in place are driven by feedback from our employees during an annual survey process or through regular employee engagement. We have also been purposeful in wanting to provide adequate recognition of our employees and their many efforts. We maintain an internal recognition platform which enables employees to be recognized in real-time for their contributions.

We have a values-driven culture that supports diversity and inclusion across our enterprise including within our employee resource groups ("ERGs").

Our first ERG was established in 2019, and as of December 31, ~~2024~~2025, there were 12 active ERGs meeting throughout the Company. ERGs are voluntary, employee-led groups that focus on shared identities, affinities and experiences and seek to apply those perspectives to initiatives that create value throughout the Company. The ERGs support their members' personal growth and professional development, and help develop learning programs and community service opportunities throughout the Company. ERGs also help foster a sense of belonging by creating a deep and intentional community that extends beyond an employee’s day-to-day team and colleagues into a companywide network.

Driving Sustainability across the Company

Consistent with our culture of teamwork, the focus on sustainability is supported and shared across our organization by the dedication and efforts of our ~~Board~~BOD ~~of Directors~~ and its Committees, as well as through the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, the ~~Board~~BOD ~~of Directors~~ is committed to overseeing the sustainability of the Company, its environmental stewardship initiatives, and its safety and operational compliance practices. ~~Throughout the year,~~ Chesapeake Utilities ~~drove~~continues to drive numerous initiatives in support of its sustainability focus, including but not limited to:

•~~Completed~~Construction ~~construction~~and operation of our first full scale RNG production facility in Lee, Florida utilizing dairy waste ~~and progressed on construction to upgrade raw biogas produced at our Planet Found poultry anaerobic digester facility in Worcester County, Maryland, to pipeline quality RNG~~;

•~~Received~~Production ~~FERC~~of ~~approval~~raw ~~for~~biogas, ~~the~~that ~~Worcester~~is ~~Resiliency~~pipeline ~~Upgrade~~quality ~~project~~RNG, anat ~~LNG~~our ~~storage~~Planet ~~facility~~Found ~~project~~poultry onanaerobic ~~Delmarva~~digester ~~that~~facility ~~received~~in ~~letters~~Worcester ofCounty, ~~support from many stakeholders~~Maryland;

~~•Established~~ aChesapeake ~~Methane~~Utilities ~~Emissions~~Corporation ~~Reduction~~2025 ~~Committee~~Form to10-K ~~focus~~Page ~~on identifying and recommending ways to further reduce methane emissions for our transmission and gathering operations;~~13

•Received Delaware PSC approval to establish a first-of-its-kind energy efficiency program in Delaware focused on natural gas;

•Received approval to expand FCG’s SAFE program to more closely align with FPU’s GUARD program; and

•Donated recycled benches from our Pipe Recycling Project to various organizations.

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~~Information~~•FERC ~~About~~approval ~~Executive~~and ~~Officers~~construction advancing for the Worcester Resiliency Upgrade project, an LNG storage facility project on Delmarva;

•Transportation of RNG produced from multiple third-party waste facilities and injected into multiple interconnection points across our various pipeline systems;

•Continued internal team engagement focused on identifying and recommending ways to further reduce methane emissions for our transmission and gathering operations;

•Implementation of various energy efficiency programs in several of our service territories;

•Alignment of FCG’s SAFE program to more closely align with FPU’s GUARD program; and

•Continued recycling of used pipe into benches, many of which have been donated to various organizations.

Information about our Executive Officers

Set forth below are the names, ages, and positions of our executive officers with their recent business experience. The age of each officer is as of the filing date of this Annual Report.

Name	Age	Executive Officer Since	Offices Held During the Past Five Years
Jeffry M. Householder	6768	2010	Chair of the Board of Directors (May 2023 - present) President (January 2019 - present) Chief Executive Officer (January 2019 - present) Director (January 2019 - present)President of FPU (June 2010 - February 2019)
Beth W. Cooper	5859	2005	Executive Vice President (February 2019 - present)Chief Financial Officer (September 2008 - present) Senior Vice President (September 2008 - February 2019)Treasurer (January 2022 - present) Assistant Corporate Secretary (March 2015 - present)
James F. Moriarty	6768	2015	Executive Vice President (February 2019 - present) General Counsel & Corporate Secretary (March 2015 - present) Chief Policy and Risk Officer (February 2019 - present) Senior Vice President (February 2017 - February 2019) Vice President (March 2015 - February 2017)
Kevin J. Webber	6667	2010	Chief Development Officer (January 2022 - present)Senior Vice President (February 2019 - present) President FPU (February 2019 - December 2019) Vice President Gas Operations and Business Development Florida Business Units (July 2010 - February 2019)
Jeffrey S. Sylvester	5556	2019	Chief Operating Officer (January 2022 - present)Senior Vice President (December 2019 - present) Vice President Black Hills Energy (October 2012 - December 2019)

Available Information on Corporate Governance Documents

Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments to these reports that we file with or furnish to the SEC at their website, www.sec.gov, are also available free of charge at our website, www.chpk.com, as soon as reasonably practicable after we electronically file these reports with, or furnish these reports to the SEC. The content of this website is not part of this Annual Report.

In addition, the following documents are available free of charge on our website, www.chpk.com:

•Business Code of Ethics and Conduct applicable to all employees, officers and directors;

•Code of Ethics for Financial Officers;

•Corporate Governance Guidelines; and

•Charters for the Audit Committee, Compensation Committee, Investment Committee, and Corporate Governance Committee of the ~~Board of Directors~~BOD.

Any of these reports or documents may also be obtained by writing to: ~~Corporate~~Shareholders ~~Secretary~~Services; c/o Chesapeake Utilities Corporation, 500 Energy Lane Suite 100, Dover, DE 19901.

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ITEM 1A. RISK FACTORS.

The risks described below fall into three broad categories related to (1) financial risks, (2) operational risks, and (3) regulatory, legal and environmental risks, all of which may affect our operations and/or the financial performance of our regulated and unregulated energy businesses. These are not the only risks we face but are considered to be the most material. There may be other unknown or unpredictable risks or other factors that could have material adverse effects on our future results. Refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report for an additional discussion of these and other related factors that affect our operations and/or financial performance.

FINANCIAL RISKS

Our financial results may fluctuate significantly and may not fully reflect the underlying performance of our business.

Our operating results, including our revenues, operating margin, profitability, and cash flow, may vary significantly in the future and period-to-period comparisons of our operating results may not be meaningful. Accordingly, the results of any one quarter or year should not be relied upon as an indication of future performance. Our financial results may fluctuate as a result of a variety of factors, many of which are outside of our control, and such fluctuations and related impacts to any capital or earnings guidance we may issue from time to time, or any modification or withdrawal thereof, may negatively impact the value of our securities.

Our access to the capital markets at competitive rates, which could be impacted by instability and volatility in the financial markets as well as our credit ratings, could negatively impact access to capital at competitive rates which could affect our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth.

Our business strategy includes the continued pursuit of growth and requires capital investment in excess of cash flow from operations. As a result, the successful execution of our strategy is dependent upon access to equity and debt on acceptable terms and at reasonable costs. Our ability to issue new debt and equity capital and the cost of equity and debt are greatly affected by our financial performance and the conditions of the financial markets. In addition, our ability to obtain adequate and cost-effective debt depends on our credit ratings. A downgrade in our current credit ratings could negatively impact our access to and cost of debt. If we are not able to readily access capital at competitive rates and on terms that are acceptable to us, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.

Fluctuations in propane gas prices could negatively affect results of operations.

The combination of high demand and lower-than-average inventory is always a common driver for higher propane gas prices. We adjust the price of the propane we sell based on changes in our cost of purchasing propane. However, if the market does not allow us to increase propane sales prices to compensate fully for fluctuations in purchased propane costs, our results of operations and cash flows could be negatively affected.

If we fail to comply with our debt covenant obligations, we could experience adverse financial consequences that could affect our liquidity and ability to borrow funds.

Our long-term debt obligations and our Revolver contain financial covenants related to debt-to-capital ratios and interest-coverage ratios. Failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations, the inability to borrow under certain credit agreements and terms, or the inability to access capital from other sources. Any such default could cause a material adverse change in our financial condition, results of operations and cash flows. As of December 31, ~~2024~~2025, we were in compliance with all of our debt covenants.

Increases in interest rates may adversely affect our results of operations and cash flows.

Increases in interest rates could increase the cost of future debt issuances. To the extent we are not able to fully recover higher debt costs in the rates we charge our utility customers, or the timing of such recovery is not certain, our earnings could be adversely affected. Increases in short-term interest rates could negatively affect our results of operations, ~~which~~we ~~depend~~rely on short-term debt to finance accounts receivable and storage gas inventories and to temporarily finance capital expenditures. Reference should be made to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.

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Continuing or worsening inflationary and/or supply chain issues may adversely impact our financial condition and results of operations.

Our business is dependent on the supply chain to ensure that equipment, materials and other resources are available to both expand and maintain our services in a safe and reliable manner. Pricing of equipment, materials and other resources have increased steadily in recent years and may continue to do so in the future. Failure to secure equipment, materials and other resources on economically acceptable terms, including failure to eliminate or manage the constraints in the supply chain, may impact the availability of items that are necessary to support normal operations as well as materials that are required for continued infrastructure growth, and as a result, may adversely impact our financial condition and results of operations.

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impact the availability of items that are necessary to support normal operations as well as materials that are required for continued infrastructure growth, and as a result, may adversely impact our financial condition and results of operations.

Furthermore, change or uncertainty in U.S. policies or the policies of other countries and regions, including any changes or uncertainty with respect to U.S. or international trade policies or tariffs, could also disrupt our key suppliers’ operations. The presidential administration has taken action to impose substantial new or increased tariffs, which could increase the cost of imported materials and equipment, disrupt supply chains, drive economic volatility, and create adverse capital and credit market conditions. For example, the cost of pipes, meters, transformers, and specialized equipment we use in our capital projects may materially increase thus increasing our overall investment in and cost of these projects. Any widespread imposition of new or increased tariffs could have an adverse effect on our results of operations, cash flow and financial condition. Additionally, the current presidential administration has directed various federal agencies to further evaluate key aspects of U.S. trade policy and there has been ongoing discussion, commentary and actions regarding potential significant changes to U.S. trade policies, treaties and tariffs. In 2025, the President indicated that the United States would impose retaliatory measures with respect to jurisdictions that have or are likely to put in place tax rules that are extraterritorial or disproportionately affect U.S. companies. The likelihood of these changes being enacted or implemented is unclear. We are currently unable to predict whether such changes will occur and, if so, their ultimate impact on our businesses. We are also unable to reasonably estimate the effects of the rapidly evolving trade tariff landscape, which could include project delays, cost increases, and obstacles to the Company’s strategic plan execution.

In addition, it may become more costly for us to recruit and retain key employees, particularly specialized/technical personnel, in the face of competitive market conditions and increased competition for specialized and experienced workers in our industry.

Disruptions, uncertainty or volatility in the credit and capital markets may exert downward pressure on the market price of the Company’s common stock.

The market price and trading volume of the Company’s common stock is subject to fluctuations as a result of, among other factors, general credit and capital market conditions and changes in market sentiment regarding the operations, business and financing strategies of the Company and its subsidiaries. As a result, disruptions, uncertainty or volatility in the credit and capital markets may, amongst other things, have a material adverse effect on the market price of the Company’s common stock.

~~Current~~Fluctuations ~~market~~in ~~conditions~~propane ~~could~~gas ~~adversely~~prices ~~impact~~could ~~the~~negatively ~~return~~affect onresults ~~plan~~of ~~assets for our Company sponsored defined benefit plans, which may require significant additional funding~~operations.

The ~~Company’s~~combination ~~primary~~of ~~defined~~high ~~benefit~~demand ~~pension~~and ~~plan,~~lower-than-average ~~the~~inventory ~~FPU pension plan,~~ is always a ~~funded~~common ~~plan~~driver ~~that~~for ishigher ~~closed~~propane togas ~~new employees and the future benefits are frozen~~prices. AtWe ~~December~~adjust ~~31, 2024,~~ the ~~FPU~~price ~~pension plan benefit obligation was $45.5 million but was fully funded at that date. The costs~~ of ~~providing benefits and related funding requirements of~~ the ~~FPU~~propane ~~plan~~we issell ~~subject~~based toon changes in ~~the~~our ~~market~~cost ~~value~~ of ~~the~~purchasing ~~assets that fund the plan and the discount rates used to estimate the pension benefit obligations~~propane. ~~The~~However, ~~funded~~if ~~status of~~ the ~~plans~~market ~~and~~does ~~the~~not ~~related~~allow ~~costs~~us ~~reflected in our financial statements are affected by various factors that are subject~~ to anincrease ~~inherent~~propane ~~degree~~sales ofprices ~~uncertainty, particularly in the current economic environment. Future losses of asset values and further declines in discount rates may necessitate accelerated funding of the plans~~ to ~~meet~~compensate ~~minimum~~fully ~~federal~~for ~~government~~fluctuations ~~requirements and may result~~ in ~~higher~~purchased ~~pension~~propane ~~expense~~costs, inour ~~future~~results ~~years. Adverse changes in the benefit obligation~~ of ~~the~~operations ~~FPU pension plan may require us to record higher pension expense~~ and ~~fund obligations earlier than originally planned, which would have an adverse impact on our~~ cash flows ~~from~~could ~~operations,~~be ~~decrease~~negatively ~~borrowing capacity and increase interest expense~~affected.

OPERATIONAL RISKS

We must construct new facilities to support future growth in earnings in our natural gas and electric distribution and natural gas transmission operations.

Construction of new facilities required to support future growth is subject to various regulatory and developmental risks, including but not limited to: (i) our ability to obtain timely certificate authorizations, necessary approvals and permits from regulatory agencies and on terms that are acceptable to us; (ii) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (iii) our ~~inability~~ability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; (iv) lack of anticipated future growth in available natural gas and electricity supply and demand; (v) insufficient customer throughput commitments; and (vi) lack of available and qualified third-party contractors which could impact the timely construction of new facilities. Adverse outcomes and/or changes in these risks could limit the future growth of our business and cause a material adverse change in our financial condition, results of operations and cash flows.

We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.

Because we do not own all of the land on which our pipelines and facilities have been constructed, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, easements or other property rights or if such rights or easements lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.

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operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.

We operate in a competitive environment, and we may lose customers to competitors.

Natural Gas. Our natural gas transmission and distribution operations compete with interstate pipelines when our customers are located close enough to a competing pipeline to make direct connections economically feasible. Customers also have the option to switch to alternative fuels, including renewable energy sources. Failure to retain and grow our natural gas customer base would have an adverse effect on our financial condition, results of operations and cash flows.

Electric. Our Florida electric distribution business has remained substantially free from direct competition from other electric service providers but does face competition from other energy sources. Changes in the competitive environment caused by legislation, regulation, market conditions, or initiatives of other electric power providers, particularly with respect to retail electric competition, would adversely affect our financial condition, results of operations and cash flows.

Propane. Our propane operations compete with other propane distributors, primarily on the basis of service and price. Our ability to grow the propane operations business is contingent upon capturing additional market share, expanding into new markets, and successfully utilizing pricing programs that retain and grow our customer base. Failure to retain and grow our customer base in our propane operations would have an adverse effect on our financial condition, results of operations and cash flows.

Fluctuations in weather may cause a significant variance in our earnings.

Our natural gas distribution, propane operations and natural gas transmission operations are sensitive to fluctuations in weather conditions, which directly influence the volume of natural gas and propane we transport, sell and deliver to our customers. A significant portion of our natural gas distribution, propane operations and natural gas transmission revenue is derived from the sales and deliveries to residential, commercial and industrial heating customers during the five-month peak heating season (November through March). Other than our Maryland natural gas distribution ~~businesses~~business ~~(CUC-Maryland division, Sandpiper Energy and Elkton Gas)~~ which ~~have~~has revenue normalization mechanisms, if the weather is warmer than normal, we generally sell and deliver less natural gas and propane to customers, and earn less revenue, which could adversely affect our financial condition, results of operations and cash flows. Conversely, if the weather is colder than normal, we generally sell and deliver more natural gas and propane to customers, and earn more revenue, which could positively affect our financial condition, results of operations and cash flows. Variations in weather from year to year can cause our financial condition, results of operations and cash flows to vary accordingly.

Our electric distribution operation is also affected by variations in weather conditions and unusually severe weather conditions. However, electricity consumption is generally less seasonal than natural gas and propane because it is used for both heating and cooling in our service areas.

Severe weather events (such as a major hurricane, flood, or tornado), natural disasters and acts of terrorism could adversely impact earnings and access to insurance coverage.

Inherent in energy transmission and distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, uncontrollable flows of natural gas, explosions, release of contaminants into the environment, sabotage and mechanical problems. Severe weather events and natural disasters, especially in our service areas that are susceptible to more frequent severe weather events and natural disasters, may damage our assets, cause operational interruptions and result in the loss of human life, all of which could negatively affect our financial condition, results of operations and cash flows.

Acts of terrorism and the impact of retaliatory military and other action by the U.S. and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas, electricity and propane that could negatively affect our operations. Companies in the energy industry may face a heightened risk of exposure to acts of terrorism, which could affect our financial condition, results of operations and cash flows.

The insurance industry may also be affected by severe weather events (such as major hurricanes), natural disasters (such as wildfires) and acts of terrorism. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms, which could adversely affect our financial condition, results of operations and cash flows.

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Operating events affecting public safety and the reliability of our natural gas and electric distribution and transmission systems could adversely affect our operations and increase our costs.

Our natural gas and electric operations are exposed to operational events and risks, such as: major leaks, outages, mechanical failures and breakdown; operations below the expected level of performance or efficiency; and accidents that could affect public safety and the reliability of our distribution and transmission systems, significantly increase costs and cause loss of customer confidence. If we are unable to recover all or some of these costs from insurance and/or customers through the regulatory process, our financial condition, results of operations and cash flows could be adversely affected.

A security breach disrupting our operating systems, facilities, and workforce or exposing confidential information may adversely affect our reputation, disrupt our operations and increase our costs.

The cybersecurity risks associated with the protection of our infrastructure and facilities is evolving and increasingly complex. We continue to heavily rely on technological tools that support our business operations and corporate functions while enhancing our security. There are various risks associated with our information technology infrastructure, including hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, cyber-attacks, cyber-terrorism, data breaches, programming mistakes, and other inadvertent errors or deliberate human acts. Further, the U.S. government has issued public warnings that indicate energy assets might be specific targets of cybersecurity threats and/or attacks.

Many of our employees, service providers, and vendors have been working, and continue to work, from remote locations where cybersecurity protections could be limited and cybersecurity procedures and safeguards could be less effective. As such, we could be subject to a higher risk of cybersecurity breaches than ever before. Therefore, we could be required to expend significant resources to continue to modify or enhance our procedures and controls or to upgrade our digital and operational systems, related infrastructure, technologies and network security. In addition, despite steps we may take to detect, mitigate, and/or eliminate threats and respond to security incidents, the techniques used by those who wish to obtain unauthorized access, and possibly disable or sabotage systems and/or abscond with information and data, change frequently and continue to evolve with the use of artificial intelligence (“AI”) and we may not be able to protect against all such actions.

Any such failure, attack, or security breach could adversely impact our ability to safely and reliably deliver services to our customers through our transmission, distribution, and generation systems, subjecting us to reputational and other harm, and subject us to legal and regulatory proceedings and claims and demands from third parties, any of which could adversely affect our business, our earnings, results of operation, financial condition and cash flows. In addition, the protection of customer, employee and Company data is crucial to our operational security. A breach or breakdown of our systems that results in the unauthorized release of individually identifiable customer information or other sensitive data could have an adverse effect on our reputation, results of operations and financial condition and could also materially increase our costs of maintaining our system and protecting it against future breakdowns or breaches. We take reasonable precautions to safeguard our information systems from cyber-attacks and security breaches; however, there is no guarantee that the procedures implemented to protect against unauthorized access to our information systems are adequate to safeguard against all attacks and breaches. We also cannot assure that any redundancies built into our networks and technology, or the procedures we have implemented to protect against cyber-attacks and other unauthorized access to secured data, are adequate to safeguard against all failures of technology or security breaches.

The Company’s business, results of operations, financial condition and cash flows could be adversely affected by interruption of the Company’s information technology or network systems as well as the Company’s implementation of its technology roadmap.

Currently, we rely on centralized and local information technology networks and systems, some of which are managed or accessible by third parties, to process, transmit and store electronic information, and to otherwise manage or support our business. Additionally, the Company collects and stores certain data, including proprietary business information, and has access to confidential or personal information that is subject to privacy and security laws, regulations and customer-imposed controls. The processing and storage of personal information is increasingly subject to privacy and data security regulations. The interpretation and application of data protection laws in the U.S. are continuing to evolve and may be different across jurisdictions. Violations of these laws could result in criminal or civil sanctions and even the mere allegation of such violations, could harm the Company’s reputation.

Information technology system and/or network disruptions, whether caused by acts of sabotage, employee error, malfeasance or otherwise, could have an adverse impact on the Company’s operations as well as the operations of the Company’s customers and suppliers. As a result, the Company may be subject to legal claims or regulatory proceedings which could result in liability or penalties under privacy laws, disruption in the Company’s operations, and damage to the Company’s reputation, adversely affecting the Company’s business, financial condition, results of operations and cash flows.

~~The~~Chesapeake ~~Company~~Utilities isCorporation ~~also~~2025 ~~implementing~~Form a10-K ~~technology~~Page roadmap that will significantly advance our technological capabilities. The implementation of new software in multiple phases is a complex process that involves several risks. Some of the common risks include:18

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The Company is also implementing a technology roadmap that will significantly advance our technological capabilities. The implementation of new software in multiple phases is a complex process that involves several risks. Some of the common risks include:

•Expectations of what the software can do is not achieved and requires additional spending, resources and time;

•Inadequate planning, including changes in implementation plans, can lead to delays, cost overruns, and poor outcomes;

•Ensuring continued team engagement is critical as technology and systems projects are significant and involve many resources within the Company as well as the use of various third parties;

•Implementing new software can expose the organization to new security risks;

•Integrating new software with existing systems can be challenging, as a result of compatibility issues, data migration and system downtime; and

•The ability to continue to recover appropriate costs as approved by our regulators.

Concerns relating to the responsible use of new and evolving technologies, such as ~~artificial intelligence (~~AI), may result in reputational or financial harm and liability.

While providing significant benefits, AI poses emerging legal, social, and ethical issues and presents risks and challenges. If we utilize AI solutions that have unintended consequences or may be deemed controversial, or if we are unable to develop effective internal policies and frameworks relating to the responsible use of AI, we may experience brand or reputational harm, competitive harm or legal liability. Complying with regulations related to AI could increase our cost of doing business, may change the way that we operate in certain jurisdictions, or may impede our ability to offer services in certain jurisdictions if we are unable to comply with regulations.

Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.

Our ability to implement our business strategy and serve our customers depends upon our continuing ability to attract, develop and retain talented professionals and a technically skilled workforce in a manner competitive with current market conditions, and transfer the knowledge and expertise of our workforce to new employees as our existing employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or the future availability and cost of contract labor could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

A strike, work stoppage or a labor dispute could adversely affect our operations.

We are party to collective bargaining agreements with labor unions at some of our Florida operations. A strike, work stoppage or a labor dispute with a union or employees represented by a union could cause interruption to our operations and our results could be adversely affected.

Our businesses are capital-intensive, and the increased costs and/or delays of capital projects may adversely affect our future earnings.

Our businesses are capital-intensive and require significant investments in ongoing infrastructure projects. These projects are subject to state and federal regulatory oversight and require certain property rights, such as easements and rights-of-way from public and private owners, as well as regulatory approvals, including environmental and other permits and licenses. There is no assurance that we will be able to obtain the necessary property rights, permits and licenses and approvals in a timely and cost-efficient manner, or at all, which may result in the delay or failure to complete a project. In addition, the availability of the necessary materials and qualified vendors could also impact our ability to complete such projects on a timely basis and manage the overall costs. Failure to complete any pending or future infrastructure projects could have a material adverse impact on our financial condition, results of operations and cash flows. Where we are able to successfully complete pending or future infrastructure projects, our revenues may not increase immediately upon the expenditure of funds on a particular project or as anticipated over the life of the project. As a result, there is the risk that new and expanded infrastructure may not achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.

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Our regulated energy business may be at risk if franchise agreements are not renewed, or new franchise agreements are not obtained, which could adversely affect our future results or operating cash flows and financial condition.

Our regulated natural gas and electric distribution operations hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity. Ongoing financial results would be adversely impacted in the event that franchise agreements were not renewed. If we are unable to obtain franchise agreements for new service areas, growth in our future earnings could be negatively impacted.

Slowdowns in customer growth may adversely affect earnings and cash flows.

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Our ability to increase revenues in our natural gas, propane and electric distribution businesses is dependent upon growth in the residential construction market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other energy sources. Slowdowns in growth may adversely affect our financial condition, results of operations and cash flows.

Energy conservation could lower energy consumption, which would adversely affect our earnings.

Federal and state legislative and regulatory initiatives to promote energy efficiency, conservation and the use of alternative energy sources could lower consumption of natural gas and propane by our customers. For example, in August 2022, the Inflation Reduction Act of 2022 was signed into law, with hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, and clean fuels, amongst other provisions. These incentives ~~could~~have ~~further~~continued to accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives and impact demand for our products and services. In addition, increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations including mandatory climate related disclosures, and the aforementioned demand for alternative forms of energy, may result in increased costs and reduced demand for our products and services. While we cannot predict the ultimate effect that the development of alternative energy sources and related laws might have on our operations, we may be subject to reduced profits, increased investigations and litigation against us, and negative impacts on the market price of our common stock and access to capital markets.

In addition, higher costs of natural gas, propane and electricity may cause customers to conserve fuel. To the extent recovery through customer rates of higher costs or lower consumption from energy efficiency or conservation is not allowed, and our propane retail prices cannot be increased due to market conditions, our financial condition, results of operations and cash flows could be adversely affected.

Commodity price increases may adversely affect the operating costs and competitive positions of our natural gas, electric and propane operations, which may adversely affect our financial condition, results of operations and cash flows.

Natural Gas and Electricity. Higher natural gas prices can significantly increase the cost of gas billed to our natural gas customers. Increases in the cost of natural gas and other fuels used to generate electricity can significantly increase the cost of electricity billed to our electric customers. Damage to the production or transportation facilities of our suppliers, which decreases their supply of natural gas and electricity, could result in increased supply costs and higher prices for our customers. Such cost increases generally have no immediate effect on our revenues and earnings because of our regulated fuel cost recovery mechanisms. However, our net income may be reduced by higher expenses that we may incur for uncollectible customer accounts and by lower volumes of natural gas and electricity deliveries when customers reduce their consumption. Therefore, increases in the price of natural gas and other fuels can adversely affect our financial condition, results of operations and cash flows, as well as the competitiveness of natural gas and electricity as energy sources.

Propane. Propane costs are subject to changes as a result of product supply or other market conditions, including weather, economic and political factors affecting crude oil and natural gas supply or pricing. For example, weather conditions could damage production or transportation facilities, which could result in decreased supplies of propane, increased supply costs and higher prices for customers. Such increases in costs can occur rapidly and can negatively affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year-to-year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes due to reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.

Refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.

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Our use of derivative instruments may adversely affect our results of operations.

Fluctuating commodity prices may affect our earnings and financing costs because our propane operations use derivative instruments, including forwards, futures, swaps, puts, and calls, to hedge price risk. While we have risk management policies and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our financial condition, results of operations and cash flows may be adversely affected. In addition, fluctuations in market prices could result in significant unrealized gains or losses, which could require margins to be posted on unsettled positions and impact our financial position, results of operations and cash flows.

A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity or electric transmission capacity may impair our ability to meet customers’ existing and future requirements.

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In order to meet existing and future customer demands for natural gas and electricity, we must acquire sufficient supplies of natural gas and electricity, interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate upstream transmission capacity for our distribution systems while considering the dynamics of the interstate pipeline and storage and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Our financial condition and results of operations would be materially and adversely affected if the future availability of these capacities were insufficient to meet future customer demands for natural gas and electricity. Currently, our natural gas operations in Florida rely primarily on two pipeline systems, FGT and Peninsula Pipeline (our intrastate pipeline subsidiary), for most of their natural gas supply and transmission. Our Florida electric operation secures electricity from external parties. Any continued interruption of service from these suppliers could adversely affect our ability to meet the demands of our customers, which could negatively impact our financial condition, results of operations and cash flows.

Our ability to grow our businesses could be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have completed.

One of our strategies is to grow through acquisitions of complementary businesses. On November 30, 2023, we completed the acquisition of FCG, a regulated natural gas distribution utility serving approximately 123,000 residential and commercial natural gas customers in Florida, for $922.8 million in cash, pursuant to the stock purchase agreement with Florida Power & Light Company. Our acquisitions, ~~including FCG as well as future acquisitions,~~ involve a number of risks including, but not limited to, the following:

•We may fail to realize ~~the~~synergies, benefits and growth ~~prospects~~opportunities anticipated as a result of the acquisition;

•We may not identify all material facts, issues and/or liabilities in due diligence; accurately anticipate required capital expenditures; or design and implement an effective internal control environment with respect to acquired businesses;

•We may experience difficulty in integrating the technology, systems, policies, processes or operations and retaining the employees, including key personnel of the acquired business;

•The historical financial results of acquisitions may not be representative of our future financial condition, results of operations and cash flows, and may not deliver the expected strategic and operational benefits;

•An acquisition may divert management’s attention to integration activities or disrupt ongoing operations; and

•We may overpay for assets, which could result in the recording of excess goodwill and other intangible assets at values that ultimately may be subject to impairment charges.

These factors, amongst others, could impact our ability to successfully grow our business which could have a material adverse effect on our financial condition, results of operations and cash flows.

An impairment of our assets including long-lived assets, goodwill and other intangible assets, could negatively impact our financial condition and results of operations.

In accordance with GAAP, goodwill, intangibles, and other long-lived assets are tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. The testing of assets for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These values may be impacted by significant negative industry or economic trends, changes in technology, regulatory or industry conditions, disruptions to our business, inability to effectively integrate acquired businesses, unexpected significant change or planned changes in use of our assets, changes in the structure of our business, divestitures, market capitalization declines or changes in economic conditions or interest rates. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the applicable asset and the implied fair value in the period the determination is made. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more of our assets, which may result in an impairment charge and could negatively affect our financial condition and results of operations.

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REGULATORY, LEGAL AND ENVIRONMENTAL RISKS

Regulation of our businesses, including changes in the regulatory environment, may adversely affect our financial condition, results of operations and cash flows.

The Delaware, Maryland, Ohio and Florida PSCs regulate our utility operations in those states. Eastern Shore is regulated by the FERC. The PSCs and the FERC set the rates that we can charge customers for services subject to their regulatory jurisdiction. Our ability to obtain timely rate increases and rate supplements to maintain current rates of return depends on regulatory approvals, and there can be no assurance that our regulated operations will be able to obtain such approvals or maintain currently authorized rates of return. When earnings from our regulated utilities exceed the authorized rate of return, the respective regulatory authority may require us to reduce our rates charged to customers in the future.

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We may face certain regulatory and financial risks related to pipeline safety legislation.

We are subject to a number of legislative proposals at the federal and state level to implement increased oversight over natural gas pipeline operations and facilities to inspect pipeline facilities, upgrade pipeline facilities, or control the impact of a breach of such facilities. Additional operating expenses and capital expenditures may be necessary to remain in compliance. If new legislation is adopted and we incur additional expenses and expenditures, our financial condition, results of operations and cash flows could be adversely affected, particularly if we are not authorized through the regulatory process to recover from customers some or all of these costs and earn at an authorized rate of return.

Pipeline integrity programs and repairs may impose significant costs and liabilities on the Company.

The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and to take additional measures to protect pipeline segments located in areas where a leak or rupture could potentially do the most harm. The PHMSA constantly updates its regulations to ensure the highest levels of pipeline safety. As the operator of pipelines, we are required to: perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipelines; improve data collection, integration and analysis; repair and remediate the pipelines as necessary; and implement preventative and mitigating actions. These new and any future regulations adopted by the PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. Moreover, should we fail to comply with the PHMSA rules and regulations, we could be subject to significant penalties and fines which may adversely affect our financial condition, results of operations and cash flows.

We are subject to operating and litigation risks that may not be fully covered by insurance.

Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting, transmitting and delivering natural gas, electricity and propane to end users. From time to time, we are a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance coverage for our general liabilities in the amount of $52 million, which we believe is reasonable and prudent. However, there can be no assurance that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.

Costs of compliance with environmental laws may be significant.

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at our current and former operating sites, especially former MGP sites. To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former MGP sites. However, there is no guarantee that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs, including costs at former MGP sites, could adversely affect our financial condition, results of operations and cash flows.

Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted and applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable. Any such increase in compliance costs could adversely affect our financial condition, results of operations and cash flows. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed administrative, civil, or criminal penalties and fines, imposed with investigatory and remedial obligations, or issued injunctions all of which could impact our financial condition, ~~results of operations and cash flows. See Item 8, Financial Statements and Supplementary Data (Note 19, Environmental Commitments and Contingencies, in the consolidated financial statements).~~

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results of operations and cash flows. See Item 8, Financial Statements and Supplementary Data (Note 18, Environmental Commitments and Contingencies, in the consolidated financial statements).

Unanticipated changes in our tax provisions or exposure to additional tax liabilities could affect our profitability and cash flow.

We are subject to income and other taxes in the U.S. and the states in which we operate. Changes in applicable state or U.S. tax laws and regulations, or their interpretation and application, including the possibility of retroactive effect, could affect our tax expense and profitability. In addition, the final determination of any tax audits or related litigation could be materially different from our historical income tax provisions and accruals. Changes in our tax provision or an increase in our tax liabilities, due to changes in applicable law and regulations, the interpretation or application thereof, future changes in the tax rate or a final determination of tax audits or litigation, could have a material adverse effect on our financial position, results of operations and cash flows.

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Our business may be subject in the future to additional regulatory and financial risks associated with global warming and climate change.

There have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions. The direction of future U.S. climate change regulation is difficult to predict given the potential for policy changes under different Presidential administrations and Congressional leadership. The Environmental Protection Agency, or other Federal agencies, may or may not continue developing regulations to reduce greenhouse gas emissions. Even if federal efforts in this area slow, states, cities and local jurisdictions may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and could reduce demand for our energy delivery services. Federal, state and local legislative initiatives to implement renewable portfolio standards or to further subsidize the cost of solar, wind and other renewable power sources may change the demand for natural gas. We cannot predict the potential impact that such laws or regulations, if adopted, may have on our future business, financial ~~condition~~position, orresults ~~financial~~of ~~results~~operations and cash flows.

Climate changes may impact the demand for our services in the future and could result in more frequent and more severe weather events, which ultimately could adversely affect our financial results.

Significant climate change creates physical and financial risks for us. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of any changes. To the extent that climate change adversely impacts the economic health or weather conditions of our service territories directly, it could adversely impact customer demand or our customers’ ability to pay. Changes in energy use due to weather variations may affect our financial condition through volatility and/or decreased revenues and cash flows. Extreme weather conditions require more system backups and can increase costs and system stresses, including service interruptions. Severe weather impacts our operating territories primarily through thunderstorms, tornadoes, hurricanes, and snow or ice storms. Weather conditions outside of our operating territories could also have an impact on our revenues and cash flows by affecting natural gas prices. To the extent the frequency of extreme weather events increases, this could increase our costs of providing services. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for investigations and lawsuits related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate change, which could impact adversely our business, results of operations and cash flows.

Our certificate of incorporation and bylaws may delay or prevent a transaction that stockholders would view as favorable.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could delay, defer or prevent an unsolicited change in control of Chesapeake Utilities, which may negatively affect the market price of our common stock or the ability of stockholders to participate in a transaction in which they might otherwise receive a premium for their shares over the then current market price. These provisions may also prevent changes in management. In addition, our ~~Board~~BOD ~~of Directors~~ is authorized to issue preferred stock without stockholder approval on such terms as our ~~Board~~BOD ~~of Directors~~ may determine. Our common stockholders will be subject to, and may be negatively affected by, the rights of any preferred stock that may be issued in the future.

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ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

ITEM 1C. CYBERSECURITY.

We recognize the importance of assessing, identifying, and managing material risks associated with cybersecurity threats, as such term is defined in Item 106(a) of Regulation S-K. We face a multitude of increasing cybersecurity threats, including those that target the ~~Nation~~nation’s critical infrastructure sectors. Reliable service and operational continuity are critical to our success and the welfare of those we serve, including our ability to safely and reliably deliver energy to our customers through our transmission, distribution, and generation systems. We are committed to maintaining robust governance and oversight of these risks and to investing in the implementation of mechanisms, controls, technologies, and processes designed to help us assess, identify, and manage these risks in an evolving landscape.

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To mitigate the threat to our business, we take a comprehensive, cross-functional approach to cybersecurity risk management. Our management team is actively involved in the oversight and implementation of our risk management program, of which cybersecurity represents an important component. At least annually, we conduct a cybersecurity risk assessment that evaluates information from internal stakeholders and external sources. The results of the assessment inform our alignment and prioritization of initiatives to enhance our security controls. As described in more detail below, we have established policies, standards, processes and practices for assessing, identifying, and managing material risks from cybersecurity threats which are designed to follow nationally recognized frameworks. These include, among other things: security awareness training for employees; mechanisms to detect and monitor unusual network activity; services that identify cybersecurity threats; conducting scans of the threat environment; evaluating our industry’s risk profile; utilizing internal and external audits; conducting threat and vulnerability assessments; and containment and incident response tools. We also actively engage with industry groups for benchmarking and awareness of best practices. We maintain controls and procedures that are designed for prompt escalation of certain cybersecurity incidents so that decisions regarding public disclosure and reporting of such incidents can be made in a timely manner.

Our approach to cybersecurity risk management includes the following key elements:

•Multi-Layered Defense and Continuous Monitoring: Our approach to cybersecurity involves multiple layers of defense, incorporating detection capabilities, analytics, and real-time monitoring. We utilize data insights to identify potential anomalies, monitor evolving threats, and identify emerging risks. Safeguards are regularly evaluated and refined based on vulnerability assessments, threat intelligence, and insights gained from monitoring activities.

•Information Sharing and Collaboration: We share and receive threat intelligence with industry peers, government agencies, Information Sharing and Analysis Centers ("ISACs"), trade organizations, and cybersecurity forums. These collaborations provide a means for information exchange to improve threat detection and vulnerability mitigation.

•Third-Party Risk Assessments: We engage independent firms to assist with multiple phases of our cybersecurity program. This work includes testing, audits, and consulting to validate and strengthen our cybersecurity posture, and the design and operational effectiveness of our controls.

•Companywide Policies and Procedures: Our companywide cybersecurity policies and procedures cover areas such as encryption standards, endpoint security, remote access protocols, multi-factor authentication, and data protection. These policies undergo regular review to address the latest security standards and operational requirements, and to consider best practices and industry trends.

•Training and Awareness: We provide awareness training to our employees to help identify, avoid and mitigate cybersecurity threats. Our employees routinely participate in simulated phishing campaigns, education that reinforces compliance with our policies, standards and practices, and other awareness training. We also periodically perform tabletops and other exercises with management and incorporate external resources and advisors as needed. Our cybersecurity team collaborates with stakeholders across our business units to further analyze the risk to the Company, and form detection, mitigation and remediation strategies.

•Supplier Engagement: We work collectively with our suppliers to support cybersecurity resiliency in our supply chain. The Company uses a variety of processes to address third-party cybersecurity threats, including reviewing the cybersecurity practices of such provider(s), contractually imposing obligations on the provider(s), notifications in the event of any known or suspected cyber incident, conducting security assessments, and periodic reassessments during the course of the Company’s engagement with such provider(s).

AsChesapeake ofUtilities ~~the~~Corporation ~~date~~2025 ~~of this~~ Form 10-K, ~~there~~Page have not been any cybersecurity incidents that have materially affected our business strategy, critical business operations, results of operations or financial condition. There can be no guarantee that our policies and procedures will be followed or, if followed, will be effective in protecting our systems and information. As such, this could impact, among other considerations, the execution of our business strategy and business operations, our financial condition and/or results of operations, and the security and effectiveness of our information technology systems. For more information regarding the risks we face from cybersecurity threats, please see Item 1A, Risk Factors, which should be read in conjunction with this Item 1C.24

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cybersecurity practices of such provider(s), contractually imposing obligations on the provider(s), notifications in the event of any known or suspected cyber incident, conducting security assessments, and periodic reassessments during the course of the Company’s engagement with such provider(s).

As of the date of this Form 10-K, there have not been any cybersecurity incidents that have materially affected our business strategy, critical business operations, results of operations or financial condition. There can be no guarantee that our policies and procedures will be followed or, if followed, will be effective in protecting our systems and information. As such, this could impact, among other considerations, the execution of our business strategy and business operations, our financial condition and/or results of operations, and the security and effectiveness of our information technology systems. For more information regarding the risks we face from cybersecurity threats, please see Item 1A, Risk Factors, which should be read in conjunction with this Item 1C.

Cybersecurity Risk Governance and Oversight

The Company’s ~~Board~~BOD, in conjunction with its Audit Committee, oversees management’s approach to cybersecurity risk and its alignment with the Company’s enterprise risk management program. The ~~Board~~BOD and Audit Committee receive reports from ~~Management~~management regarding the prevention, detection, and mitigation of cybersecurity incidents, including security risks and vulnerabilities. Additionally, the Audit Committee receives updates on cybersecurity risk assessments, risk mitigation strategies, and relevant cybersecurity matters. The Company’s information technology team is responsible for developing and implementing its information security program and reporting on cybersecurity matters to the ~~Board~~BOD ~~of Directors~~ and Audit Committee.

The Company’s Risk Management Committee ("RMC"), which is chaired by the Chief ~~Policy and~~ Risk Officer, evaluates risks relating to cybersecurity, among other significant risks, and oversees mitigation plans. The RMC is comprised of executive leadership across multiple functions, including individuals with responsibilities and oversight over legal, regulatory, finance and treasury, operations, information technology, business development, and policies and controls. The RMC meets monthly and receives regular updates on security performance metrics, global security risks, security enhancements, and updates on our security posture.

The Company has a cross-functional cybersecurity incident response team (“"CIRT”"). The Company’s CIRT routinely reviews and updates our incident response plans, procedures and protocols, as well as reports to the Company’s RMC on security matters that impact the confidentiality, integrity, or availability of the Company’s data or information systems.

ITEM 2. Properties.

Offices and other operational facilities

We own or lease offices and other operational facilities in our service territories located in Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina, Florida and Ohio.

Regulated Energy Segment

The following table presents a summary of miles of assets operated by our natural gas distribution, natural gas transmission and electric business units as of December 31, ~~2024~~2025:

Operations						Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines)						2,136
Delmarva Natural Gas (Underground propane pipelines)						17
FPU (Natural gas pipelines)						3,216
Florida City Gas (Natural gas pipelines)						3,982
Natural Gas Transmission
Eastern Shore						521
Florida City Gas						79
Peninsula Pipeline						187
Aspire Energy Express (1)						—
Electric Distribution
FPU						924
Total						11,062

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(1) Aspire Energy Express had less than 1 mile of natural gas pipeline at December 31, 2024.

Peninsula Pipeline also has a 50 percent jointly owned intrastate transmission pipeline with Seacoast Gas Transmission, LLC ("Seacoast Gas Transmission") in Nassau County, Florida. The 26-mile pipeline serves demand in both Nassau and Duval Counties.

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Operations						Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines)						2,187
Delmarva Natural Gas (Underground propane pipelines)						17
FPU (Natural gas pipelines)						3,270
FCG (Natural gas pipelines)						4,087
Natural Gas Transmission
Eastern Shore						532
FCG						79
Peninsula Pipeline						197
Aspire Energy Express (1)						—
Electric Distribution
FPU						926
Total						11,295

(1) Aspire Energy Express had less than 1 mile of natural gas pipeline at December 31, 2025.

Unregulated Energy Segment

The following table presents propane storage capacity, miles of underground distribution mains and transmission for our Unregulated Energy Segment operations as of December 31, ~~2024~~2025:

Operations						Gallons or miles
Propane distribution
Propane storage capacity (gallons in millions)						8.54
Underground propane distribution mains (miles)						152
Unregulated Energy Transmission and gathering (Aspire Energy)
Natural gas pipelines (miles)						2,800

ITEM 3. Legal Proceedings.

See Item 8, Financial Statements and Supplementary Data (Note 2019, Other Commitments and Contingencies, in the consolidated financial statements), which is incorporated into Item 3 by reference.

ITEM 4. Mine Safety Disclosures.

Not applicable.

PART II

ITEM 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Common Stock Dividends and Stockholder Information:

Chesapeake Utilities ~~common~~Corporation ~~stock~~2021 isForm ~~traded~~10-K Page on the New York Stock Exchange ("NYSE") under the ticker symbol CPK. As of February 24, 2025, we had 1,930 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $2.510 per share in 2024 and $2.305 per share in 2023, and have paid a cash dividend to holders of our common stock for 64 consecutive years. Future dividend payments and amounts are at the discretion of the Board of Directors and will depend on our financial condition, results of operations, capital requirements, and other factors. 26

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Chesapeake Utilities common stock is traded on the New York Stock Exchange ("NYSE") under the ticker symbol "CPK." As of February 23, 2026, we had 1,874 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $2.695 per share in 2025 and $2.510 per share in 2024, and have paid a cash dividend to holders of our common stock for 65 consecutive years. Future dividend payments and amounts are at the discretion of the BOD and will depend on our financial condition, results of operations, capital requirements, and other factors.

Indentures to our long-term debt contain various restrictions which limit our ability to pay dividends. Refer to Item 8, Financial Statements and Supplementary Data (Note 12, Long-Term Debt, in the consolidated financial statements) for additional information.

Purchases of Equity Securities by the Issuer

The following table sets forth information on purchases by us or on our behalf of shares of our common stock during the quarter ended December 31, ~~2024~~2025:

	TotalNumberof SharesPurchased		AveragePrice Paidper Share				Total Number of SharesPurchased as Part ofPublicly Announced Plansor Programs (2)		Maximum Number ofShares That May Yet BePurchased Under the Plansor Programs (2)
Period		TotalNumberof SharesPurchased			AveragePrice Paidper Share			Total Number of SharesPurchased as Part ofPublicly Announced Plansor Programs (2)		Maximum Number ofShares That May Yet BePurchased Under the Plansor Programs (2)
Period
October 1, 2025 through October 31, 2025 (1)		640			$	137.06		—		—
October 1, 2024 through October 31, 2024 (1)	602		$	120.38			—		—
November 1, 2025 through November 30, 2025		—			—			—		—
November 1, 2024 through November 30, 2024	—		—				—		—
December 1, 2025 through December 31, 2025		—			—			—		—
December 1, 2024 through December 31, 2024	—		—				—		—
Total		640			$	137.06		—		—
Total	602		$	120.38			—		—

(1) In October ~~2024~~2025, we purchased ~~602~~640 shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8, Financial Statements and Supplementary Data (Note 1615, Employee Benefit Plans, in the consolidated financial statements).

Chesapeake Utilities Corporation 2024 Form 10-K Page 27

Table of Contents

(2) Except for the purpose described in footnote (1), we have no publicly announced plans or programs to repurchase our shares.

Information on certain of our equity compensation plans, for which shares of our common stock are authorized for issuance, is included in the section of our Proxy Statement captioned “Equity Compensation Plan Information” and is incorporated herein by reference.

Common Stock Performance Graph

The stock performance graph and table below compares cumulative total stockholder return on our common stock during the five fiscal years ended December 31, ~~2024~~2025, with the cumulative total stockholder return of the Standard & Poor’s 500 Index and the cumulative total stockholder return of select peers, which include the following companies: Atmos Energy Corporation; Black Hills Corporation; New Jersey Resources Corporation; NiSource; Northwest Natural Gas Company; Northwestern Corporation; ONE Gas, Inc.; RGC Resources, Inc.; Spire, Inc.; and Unitil Corporation.

The comparison assumes $100 was invested on December 31, ~~2019~~2020 in our common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of our common stock.

	2019		2020		2021		2022		2023		2024
Chesapeake Utilities	$	100	$	115	$	158	$	130	$	118	$	139
Industry Index	$	100	$	84	$	96	$	104	$	102	$	129
S&P 500 Index	$	100	$	118	$	152	$	125	$	157	$	197

Chesapeake Utilities Corporation 2025 Form 10-K Page 27

Chesapeake Utilities Corporation 2024 Form 10-K Page 28

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	2020		2021		2022		2023		2024		2025
Chesapeake Utilities	$	100	$	137	$	113	$	103	$	121	$	127
Industry Index	$	100	$	115	$	123	$	121	$	153	$	183
S&P 500 Index	$	100	$	129	$	105	$	133	$	166	$	196

Chesapeake Utilities Corporation 2025 Form 10-K Page 28

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ITEM 6. RESERVED.

ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.

This section provides management’s discussion of Chesapeake Utilities and its consolidated subsidiaries, with specific information on results of operations, liquidity and capital resources, as well as discussion of how certain accounting principles affect our financial statements. It includes management’s interpretation of our financial results and our operating segments, the factors affecting these results, the major factors expected to affect future operating results as well as investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto in Item 8, Financial Statements and Supplementary Data.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A, Risk Factors. They should be considered in connection with forward-looking statements contained in this Annual Report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

Earnings per share ("EPS") and Adjusted EPS information is presented on a diluted basis, unless otherwise noted.

Acquisition of FCG

On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement that were settled during the first quarter of 2024, pursuant to the stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment. FCG currently serves approximately ~~123~~125,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. ~~Its natural gas system includes approximately 3,982 miles of distribution main and 80 miles of transmission pipe.~~ Results for FCG are included within our consolidated results from the acquisition date.

In June 2023, FCG received approval from the Florida PSC for a $23.3 million total increase in base revenue in connection with its May 2022 rate case filing. The new rates, which became effective as of May 1, 2023, included the transfer of its SAFE program provisions from a rider clause to base rates, an increase in rates associated with a liquefied natural gas facility, and approval of FCG's proposed ~~reserve surplus amortization mechanism ("~~RSAM") with a $25.0 million reserve amount. The RSAM iswas recorded as either an increase or decrease to accrued removal costs on the balance sheet, with a corresponding increase or decrease to depreciation and amortization expense. At December 31, 2024, the RSAM reserve had been completely utilized.

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

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. We believe 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.~~

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 29

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~~The~~measures ~~following~~in ~~tables~~assessing ~~reconcile~~a ~~Gross~~business ~~Margin,~~unit's ~~Net Income,~~ and ~~EPS,~~the ~~all~~overall asCompany ~~defined~~performance. ~~under~~Other ~~GAAP,~~companies tomay ~~our~~calculate these non-GAAP financial measures ofin ~~Adjusted~~a ~~Gross~~different ~~Margin, Adjusted Net Income and Adjusted EPS for the years ended December 31, 2024, 2023 and 2022:~~ manner.

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 years ended December 31, 2025, 2024 and 2023:

Adjusted Gross Margin


	For the Year Ended December 31, 2025
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	687.8	$	271.9	$	(29.7)	$	930.0
Cost of Sales:
Natural gas, propane and electric costs	(193.8)		(127.3)		29.6		(291.5)
Depreciation & amortization	(70.9)		(20.8)		—		(91.7)
Operations & maintenance expenses (1)	(54.7)		(39.1)		0.1		(93.7)
Gross Margin (GAAP)	368.4		84.7		—		453.1
Operations & maintenance expenses (1)	54.7		39.1		(0.1)		93.7
Depreciation & amortization	70.9		20.8		—		91.7
Adjusted Gross Margin (Non-GAAP)	$	494.0	$	144.6	$	(0.1)	$	638.5


	For the Year Ended December 31, 2024
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	583.4	$	228.4	$	(24.6)	$	787.2
Cost of Sales:
Natural gas, propane and electric costs	(144.2)		(100.2)		24.6		(219.8)
Depreciation & amortization	(48.8)		(16.9)		—		(65.7)
Operations & maintenance expenses (1)	(48.6)		(33.1)		—		(81.7)
Gross Margin (GAAP)	341.8		78.2		—		420.0
Operations & maintenance expenses (1)	48.6		33.1		—		81.7
Depreciation & amortization	48.8		16.9		—		65.7
Adjusted Gross Margin (Non-GAAP)	$	439.2	$	128.2	$	—	$	567.4

	For the Year Ended December 31, 2023
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	473.6	$	223.1	$	(26.1)	$	670.6
Cost of Sales:
Natural gas, propane and electric costs	(140.0)		(102.5)		26.0		(216.5)
Depreciation & amortization	(48.2)		(17.3)		—		(65.5)
Operations & maintenance expenses (1)	(27.5)		(31.5)		0.3		(58.7)
Gross Margin (GAAP)	257.9		71.8		0.2		329.9
Operations & maintenance expenses (1)	27.5		31.5		(0.3)		58.7
Depreciation & amortization	48.2		17.3		—		65.5
Adjusted Gross Margin (Non-GAAP)	$	333.6	$	120.6	$	(0.1)	$	454.1

Chesapeake Utilities Corporation 2025 Form 10-K Page 30

Chesapeake Utilities Corporation 2024 Form 10-K Page 30

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	For the Year Ended December 31, 2022
	For the Year Ended December 31, 2023
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	~~429~~473.46	$	~~280~~223.81	$	(2926.51)	$	~~680~~670.76
Cost of Sales:
Natural gas, propane and electric costs	(~~127~~140.20)		(~~162~~102.75)		2926.40		(~~260~~216.5)
Depreciation & amortization	(5248.72)		(1617.3)		—		(6965.05)
Operations & maintenance expenses (1)	(3527.5)		(2931.85)		—0.3		(6558.37)
Gross Margin (GAAP)	~~214~~257.09		7271.08		(0.1)2		~~285~~329.9
Operations & maintenance expenses (1)	3527.5		2931.85		—(0.3)		6558.37
Depreciation & amortization	5248.72		1617.3		—		6965.05
Adjusted Gross Margin (Non-GAAP)	$	~~302~~333.26	$	~~118~~120.16	$	(0.1)	$	~~420~~454.21

(1) Operations & maintenance expenses within the 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.

2025 to 2024 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for 2025 was $368.4 million, an increase of $26.6 million, or 7.8 percent, compared to 2024. Higher gross margin largely reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects and natural gas organic growth.

2024 to 2023 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for ~~2024~~the ~~was~~year ~~$341.8~~ended ~~million~~December 31, an2024 ~~increase~~compared ofto ~~$83.9~~2023 ~~million,~~is ordescribed ~~32.5~~in ~~percent~~Item 7, ~~compared~~Management's toDiscussion ~~2023.~~and ~~Higher~~Analysis ~~gross~~of ~~margin~~Financial ~~reflects~~Condition ~~contributions~~and ~~attributable~~Results toof ~~the~~Operations ~~acquisition~~in ofour ~~FCG,~~Annual ~~incremental~~Report ~~margin~~on ~~from~~Form ~~regulatory~~10-K ~~initiatives~~for ~~and~~the ~~infrastructure~~year ~~programs~~ended December 31, ~~natural~~2024, ~~gas~~which ~~organic~~is ~~growth~~incorporated ~~and~~herein ~~pipeline~~by ~~expansion projects~~reference.

~~2023~~2025 to ~~2022~~2024 Gross Margin (GAAP) Variance – ~~Regulated~~Unregulated Energy

Gross Margin (GAAP) for the ~~Regulated~~Unregulated Energy segment for ~~the~~2025 ~~year~~was ~~ended~~$84.7 ~~December 31~~million, ~~2023~~an ~~compared~~increase toof ~~2022~~$6.5 ismillion, ~~described~~or in8.3 ~~Item 7~~percent, ~~Management's~~compared ~~Discussion~~to ~~and~~2024. ~~Analysis~~Higher ofgross ~~Financial~~margin ~~Condition~~resulted ~~and~~primarily ~~Results~~from ofincreased ~~Operations~~CNG, inRNG ~~our~~and ~~Annual~~LNG ~~Report on Form 10-K for the year ended December 31~~services, ~~2023,~~and ~~which~~increased iscustomer ~~incorporated herein by reference~~consumption.

2024 to 2023 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for ~~2024~~the ~~was~~year ~~$78.2~~ended ~~million~~December 31, an2024 ~~increase~~compared ofto ~~$6.4~~2023 ~~million,~~is ordescribed ~~8.9~~in ~~percent~~Item 7, ~~compared~~Management's toDiscussion ~~2023.~~and ~~Higher~~Analysis ~~gross~~of ~~margin~~Financial ~~resulted~~Condition ~~from~~and ~~increased~~Results ~~levels~~ of ~~virtual~~Operations ~~pipeline~~in ~~services~~our ~~and~~Annual ~~increased~~Report ~~propane~~on ~~consumption~~Form 10-K for the year ended December 31, ~~margins~~2024, ~~and~~which ~~service~~is ~~fees~~incorporated herein by reference.

~~2023~~Chesapeake toUtilities ~~2022~~Corporation ~~Gross~~2025 ~~Margin~~Form ~~(GAAP)~~10-K ~~Variance~~Page ~~– Unregulated Energy~~31

Gross Margin (GAAP) for the Unregulated Energy segment for the year ended December 31, 2023 compared to 2022 is described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.

Chesapeake Utilities Corporation 2024 Form 10-K Page 31

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Adjusted Net Income and Adjusted EPS

	Year Ended
	December 31,
(dollars in millions, shares in thousands (except per share data))	~~2024~~2025		~~2023~~2024		~~2022~~2023
Net Income (GAAP)	$	~~118~~140.63	$	87118.26	$	8987.82
FCG transaction and transition-related expenses, net (1)	20.98		102.69		—10.6
Adjusted Net Income (Non-GAAP)	$	~~121~~141.51	$	97121.85	$	8997.8
Weighted average common shares outstanding - diluted (2)	2223,~~531~~488		1822,~~435~~531		1718,~~804~~435
Earnings Per Share - Diluted (GAAP)	$	5.2697	$	45.7326	$	54.0473
FCG transaction and transition-related expenses, net (1)	0.1304		0.5813		—0.58
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	56.3901	$	5.3139	$	5.0431

(1) Transaction and transition-related expenses represent non-recurring costs attributable to the acquisition and integration of FCG including, but not limited to transaction costs, transition services, consulting, system integration, rebranding, and legal fees.

(2) Weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 1514 for additional details on the acquisition and related equity offering.

2025 to 2024 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2025 was $140.3 million, or $5.97 per share, compared to $118.6 million, or $5.26 per share in 2024. Net income for the years ended December 31, 2025 and 2024 included $0.8 million and $2.9 million, respectively, of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $19.6 million.

2024 to 2023 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2024 ~~was $118.6 million, or $5.26 per share,~~ compared to ~~$87.2~~2023 ~~million,~~is ordescribed ~~$4.73 per share~~ in ~~2023.~~Item ~~Net income for the years ended December 31~~7, ~~2024~~Management's Discussion and ~~2023~~Analysis ~~included~~of ~~$2.9~~Financial ~~million~~Condition and ~~$10.6~~Results ~~million, respectively,~~ of ~~transaction~~Operations ~~and transition-related expenses~~ in ~~connection~~our ~~with~~Annual ~~the~~Report ~~acquisition~~on ~~and~~Form ~~integration~~10-K offor ~~FCG.~~the ~~Excluding~~year ~~these~~ended ~~costs~~December 31, ~~net~~2024, ~~income~~which ~~increased~~is byincorporated ~~$23.7~~herein ~~million~~by ~~or 24~~reference.~~2 percent compared to the prior year.~~

~~2023~~Chesapeake toUtilities ~~2022~~Corporation ~~Net~~2025 ~~Income~~Form ~~(GAAP)~~10-K ~~Variance~~Page 32

Net income (GAAP) for the year ended December 31, 2023 compared to 2022 is described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.

Chesapeake Utilities Corporation 2024 Form 10-K Page 32

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OVERVIEW AND HIGHLIGHTS

(dollars in millions, shares in thousands (except per share data))					Increase						Increase
For the Year Ended December 31,	~~2024~~2025		~~2023~~2024		(Decrease)		~~2023~~2024		~~2022~~2023		(Decrease)
Operating Income
Regulated Energy	$	~~196~~222.20	$	~~126~~196.2	$	7025.08	$	~~126~~196.2	$	~~115~~126.32	$	1070.90
Unregulated Energy	3133.76		2431.47		71.39		2431.47		2724.54		(37.1)3
Other businesses and eliminations	0.3		0.23		~~0.1~~—		0.23		0.12		0.1
Total Operating Income	~~228~~255.29		~~150~~228.82		7727.47		~~150~~228.82		~~142~~150.98		777.94
Other income, net	29.06		12.40		07.6		12.40		5.1.4		(30.7)6
Interest charges	6872.45		3668.94		314.51		3668.94		2436.49		1231.5
Income from Before Income Taxes	~~161~~193.80		~~115~~161.38		4631.52		~~115~~161.38		~~123~~115.63		(846.3)5
Income taxes	4352.27		2843.12		159.15		2843.12		3328.81		(515.7)1
Net Income	$	~~118~~140.63	$	87118.26	$	3121.47	$	87118.26	$	8987.82	$	(231.6)4
Weighted Average Common Shares Outstanding: (1)
Basic	2223,~~469~~389		1822,~~371~~469		~~4,098~~920		1822,~~371~~469		1718,~~722~~371		~~649~~4,098
Diluted	2223,~~531~~488		1822,~~435~~531		~~4,096~~957		1822,~~435~~531		1718,~~804~~435		~~631~~4,096
Earnings Per Share of Common Stock
Basic	$	56.2800	$	45.7528	$	0.5372	$	45.7528	$	54.0775	$	(0.~~32)~~53
Diluted	$	5.2697	$	45.7326	$	0.5371	$	45.7326	$	54.0473	$	(0.~~31)~~53
Adjusted Net Income and Adjusted Earnings Per Share
Net Income (GAAP)	$	~~118~~140.63	$	87118.26	$	3121.47	$	87118.26	$	8987.82	$	(231.6)4
FCG transaction and transition-related expenses, net (2)	20.98		102.69		(72.71)		102.69		—10.6		10(7.67)
Adjusted Net Income (Non-GAAP)	$	~~121~~141.51	$	97121.85	$	2319.76	$	97121.85	$	8997.8	$	823.07
Earnings Per Share - Diluted (GAAP)	$	5.2697	$	45.7326	$	0.5371	$	45.7326	$	54.0473	$	(0.~~31)~~53
FCG transaction and transition-related expenses, net (2)	0.1304		0.5813		(0.4509)		0.5813		—0.58		(0.5845)
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	56.3901	$	5.3139	$	0.0862	$	5.3139	$	5.0431	$	0.2708

(1) Weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG.

(2) Transaction and transition-related expenses represent costs attributable to the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 33

Table of Contents

~~2024~~2025 compared to ~~2023~~2024

Key variances in operations between ~~2024~~2025 and ~~2023~~2024 included:

(in millions, except per share data)	Pre-taxIncome		NetIncome		EarningsPer Share
Year ended December 31, 2023 Adjusted Results**	$	129.7	$	97.8	$	5.31
Year ended December 31, 2024 Adjusted Results (1)	$	165.8	$	121.5	$	5.39
Non-recurring Items:
Absence of one-time benefit associated with reduction in state tax rate	—		(2.5)		(0.13)
	—		(2.5)		(0.13)
Increased (Decreased) Adjusted Gross Margins:
Contributions from acquisition	89.6		65.7		2.91
Natural gas transmission service expansions, including interim services (2)	18.8		13.7		0.58
Margin from regulated infrastructure programs*	6.2		4.6		0.20
Contributions from regulated infrastructure programs (2)	13.8		10.0		0.43
Natural gas growth (excluding service expansions)	5.8		4.2		0.19
Rate changes associated with recent rate case activities (2)	12.6		9.1		0.39
Natural gas transmission service expansions, including interim services*	5.2		3.8		0.17
Increased CNG/RNG/LNG services (2)	10.7		7.8		0.33
Increased demand for virtual pipeline services	4.5		3.3		0.15
Increased customer consumption	9.5		6.9		0.28
Rate changes associated with Florida natural gas base rate proceeding*	1.6		1.2		0.05
Natural gas growth (excluding service expansions)	7.4		5.4		0.23
Improved Aspire Energy performance - rate changes and gathering fees	1.6		1.1		0.05
Change in propane margins and service fees	(1.4)		(1.0)		(0.04)
Interim rates from recent rate case activities*	0.9		0.7		0.03
	71.4		51.9		2.20
Changes in customer consumption	0.3		0.2		0.01
Increased Other Operating Expenses (Excluding Natural Gas, Electricity and Propane Costs):
Reduced propane margins per gallon and fees	(0.3)		(0.2)		(0.01)
Depreciation, amortization and property taxes	(26.3)		(19.1)		(0.82)
Expiration of regulatory recovery for pandemic-related costs	(1.2)		(0.9)		(0.04)
Facilities expenses, maintenance costs and outside services	(9.2)		(6.7)		(0.28)
	114.2		83.7		3.71
Payroll, benefits and other employee-related expenses	(6.7)		(4.9)		(0.21)
(Increased) Decreased Other Operating Expenses (Excluding Natural Gas, Electricity and Propane Costs):
Credit, collections and customer service costs	(1.5)		(1.1)		(0.05)
FCG operating expenses	(37.8)		(27.7)		(1.23)
Insurance-related costs	(1.1)		(0.8)		(0.03)
Depreciation, amortization and property taxes	(3.2)		(2.3)		(0.10)
Regulatory expenses	(0.9)		(0.7)		(0.03)
Increased insurance-related costs	(1.6)		(1.2)		(0.05)
Vehicle expenses	(0.8)		(0.6)		(0.02)
Facilities expenses, maintenance costs and outside services	(1.4)		(1.0)		(0.05)
	(46.5)		(33.9)		(1.44)
Increased vehicle expenses	(0.9)		(0.7)		(0.03)
Changes in other income	7.6		5.5		0.24
Payroll, benefits and other employee-related expenses	2.0		1.5		0.07
Interest charges	(4.2)		(3.0)		(0.13)
	(42.9)		(31.4)		(1.39)
Increase in shares outstanding due to 2024 and 2025 equity issuances (3)	—		—		(0.22)
Interest charges	(35.5)		(26.0)		(1.15)
Net other changes	—		(0.9)		(0.03)
Increase in shares outstanding due to 2024 and 2023 equity issuances***	—		—		(0.96)
	3.4		1.6		(0.14)
Net other changes	0.3		(0.1)		—
Year ended December 31, 2025 Adjusted Results(1)	$	194.1	$	141.1	$	6.01
Year ended December 31, 2024 Adjusted Results**	$	165.8	$	121.5	$	5.39

* See(1) Transaction and transition-related expenses attributable to the ~~Major~~acquisition ~~Projects~~and integration of FCG have been excluded from the Company’s non-GAAP measures of adjusted net income and ~~Initiatives~~adjusted ~~table~~EPS. See reconciliations above for a detailed comparison to the related GAAP measures.

** Transaction(2) Refer ~~and transition-related expenses attributable~~ to ~~the~~Major ~~acquisition~~Projects and ~~integration~~Initiatives oftable ~~FCG~~for ~~have~~additional ~~been excluded from the Company’s non-GAAP~~information.

~~measures~~(3) Reflects ofthe ~~adjusted~~impact ~~net~~of ~~income~~common ~~and~~shares ~~adjusted~~issued ~~EPS.~~under ~~See reconciliations above for a detailed comparison to~~ the ~~related~~DRIP ~~GAAP~~and ~~measures~~ATM program.

~~***~~Chesapeake ~~Reflects~~Utilities ~~the~~Corporation ~~impact~~2025 ofForm ~~4.4 million~~10-K ~~common~~Page ~~shares issued in November 2023 in connection with the acquisition of FCG and shares also issued in 2024.~~34

Chesapeake Utilities Corporation 2024 Form 10-K Page 34

Table of Contents

SUMMARY OF KEY FACTORS

Recently Completed and Ongoing Major Projects and Initiatives

We constantly 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 the 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
	Year Ended December 31,						Estimate for Calendar Year
(in millions)	~~2022~~2023		~~2023~~2024		~~2024~~2025		~~2025~~2026		~~2026~~2027
Pipeline Expansions:
Southern Expansion	$	—	$	0.6	$	2.3	$	2.3	$	2.3
St. Cloud / Twin Lakes Expansion	$	0.3	$	0.6	$	2.9	$	3.8	$	3.8
Beachside Pipeline Expansions	—		1.8		2.4		2.4		2.4
Wildlight	0.5		1.5		2.6		4.3		4.3
St. Cloud / Twin Lakes Expansion	—		0.3		0.6		2.8		3.8
Newberry	—		1.4		2.6		2.6		2.6
Wildlight	—		0.5		1.5		3.0		4.3
Worcester Resiliency Upgrade	—		—		0.3		10.6		17.1
Lake Wales	—		0.3		0.5		0.5		0.5
Boynton Beach	—		—		3.0		3.4		3.4
Newberry	—		—		1.4		2.6		2.6
New Smyrna Beach	—		—		1.6		2.6		2.6
Worcester Resiliency Upgrade	—		—		—		3.0		13.7
Central Florida Reinforcement	—		0.1		2.6		4.3		4.3
Boynton Beach	—		—		—		3.1		3.4
Warwick	—		0.4		1.9		1.9		1.9
New Smyrna Beach	—		—		—		1.7		2.6
Renewable Natural Gas Supply Projects	—		—		2.5		5.4		6.4
Central Florida Reinforcement	—		—		0.1		2.0		4.3
Miami Inner Loop	—		—		2.8		7.6		7.6
Warwick	—		—		0.4		1.9		1.9
Duncan Plains	—		—		—		—		1.5
Renewable Natural Gas Supply Projects	—		—		—		5.7		6.7
Total Pipeline Expansions	0.8		4.0		22.8		46.5		55.5
Total Pipeline Expansions	—		3.5		9.2		31.0		48.5
CNG/RNG/LNG Transportation and Infrastructure	11.1		16.4		27.3		28.5		29.7
CNG/RNG/LNG Transportation and Infrastructure	11.1		11.1		16.4		20.0		20.7
Regulatory Initiatives:
Florida GUARD Program	—0.4		03.46		37.61		610.31		813.80
FCG SAFE Program	—		—3.8		3.8.4		812.37		1016.94
Capital Cost Surcharge Programs	2.08		23.82		35.27		59.30		610.71
Florida Rate Case (1)	2.5		15.8		17.4		17.2		17.2
Electric Storm Protection Plan	1.3		3.2		6.4		9.1		11.4
Maryland Rate Case (2)	—		—		—		TBD		TBD
Maryland Rate Case	—		—		1.5		3.5		3.5
Delaware Rate Case (3)	—		—		0.6		TBD		TBD
Delaware Rate Case (1)	—		0.6		4.7		6.1		6.1
Electric Rate Case (3)	—		—		0.3		TBD		TBD
Electric Rate Case (1)	—		0.3		7.3		8.6		9.1
Electric Storm Protection Plan	0.5		1.3		3.2		5.6		5.6
Florida Mandatory Relocates	—		—		—		1.5		1.5
Total Regulatory Initiatives	5.0		20.3		32.1		42.7		49.2
Florida City Gas Rate Case	—		—		—		TBD		TBD
Total	$	16.1	$	34.9	$	57.7	$	93.7	$	118.4
Total Regulatory Initiatives	4.5		14.7		41.1		60.6		71.1
Total	$	16.4	$	35.1	$	91.2	$	135.6	$	156.3

(1) Includes adjusted gross margin ~~during~~attributable ~~2023~~to ~~comprised of both~~ interim rates ~~and~~during ~~permanent~~2024 ~~base~~and ~~rates~~2025. ~~which~~See ~~became~~additional ~~effective~~information inprovided ~~March 2023~~below.

~~(2)~~Chesapeake ~~Rate~~Utilities ~~case~~Corporation ~~application~~2025 ~~and~~Form ~~depreciation~~10-K ~~study~~Page ~~filed with the Maryland PSC in January 2024. See additional information provided below.~~35

(3) Includes adjusted gross margin attributable to interim rates during 2024. See additional information provided below.

Chesapeake Utilities Corporation 2024 Form 10-K Page 35

Table of Contents

Discussion of Major Projects and Initiatives

Pipeline Expansions

Southern Expansion

Eastern Shore installed a new natural gas driven compressor skid unit at its existing Bridgeville, Delaware compressor station that provides 7,300 Dts of incremental firm transportation pipeline capacity. The project was placed in service in the fourth quarter of 2023. The project generated additional adjusted gross margin of $1.7 million for the year ended December 31, 2024, and is expected to produce adjusted gross margin of approximately $2.3 million in 2025 and thereafter.

Beachside Pipeline Expansion

In June 2021, Peninsula Pipeline and FCG entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support FCG's growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline constructed approximately 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida. The project went into service in April 2023. Subsequent to the acquisition of FCG, the agreement is now an affiliate agreement. The project generated additional adjusted gross margin of $0.6 million for the year ended December 31, 2024, and is expected to produce adjusted gross margin of approximately $2.4 million in 2025 and thereafter.

St. Cloud / Twin Lakes Expansion

In July 2022, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 2,400 Dts/d of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline constructed a pipeline extension and regulator station for FPU. The extension supports new incremental load due to growth in the area, including providing service, most immediately, to the residential development, Twin Lakes. The expansion also improves reliability and provides operational benefits to FPU’s existing distribution system in the area, supporting future growth. ~~This project was placed into service in July 2023 and generated additional adjusted gross margin of $0.3 million for the year ended December 31, 2024.~~ We expect this extension to generate annual adjusted gross margin of $0.6 million in ~~2025~~2026 and thereafter.

In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to its Transportation Service Agreement with FPU for a project that will support additional supply to communities in the St. Cloud, Florida area. The project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the ~~fourth~~second quarter of ~~2025~~2026. We expect this expansion to generate approximately $23.2 million of adjusted gross margin in ~~2025~~2026 and ~~$3.2 million~~ thereafter.

For the year ended December 31, 2025, these projects generated additional adjusted gross margin of $2.3 million.

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, ~~with~~and construction onwas ~~the~~completed ~~overall~~in ~~project continuing through~~ 2025. The project generated additional adjusted gross margin of $1.01 million for the year ended December 31, ~~2024~~2025, and is expected to contribute adjusted gross margin of approximately $34.03 million in ~~2025~~2026 and ~~$4.3 million~~ thereafter.

Lake Wales Expansion

In February 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 9,000 Dts/d of firm service in the Lake Wales, Florida area. The PSC approved the petition in April 2023 and Peninsula Pipeline completed the acquisition of an existing pipeline in May 2023 that is being utilized to serve both current and new natural gas customers. The project generated additional adjusted gross margin of $0.2 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $0.5 million in 2025 and thereafter.

Chesapeake Utilities Corporation 2024 Form 10-K Page 36

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Newberry Expansion

In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 Dts/d of firm service in the Newberry, Florida area. The petition was approved by the Florida PSC in the third quarter of 2023. Peninsula Pipeline will construct a pipeline extension, which will be used by FPU to support the development of a natural gas distribution system to provide gas service to the City of Newberry. A filing to address the acquisition and conversion of existing Company owned propane community gas systems in Newberry was made in November 2023. The Florida PSC approved it in April 2024,. ~~and~~Conversions ~~conversions~~ of the community gas systems commenced in the second quarter of 2024 and are projected to be complete in the first quarter of 2026. The project generated additional adjusted gross margin of $1.42 million for the year ended December 31, ~~2024~~2025, and is expected to contribute adjusted gross margin of approximately $2.6 million in ~~2025~~2026 and 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, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. In January 2025, the FERC approved the project~~, and construction is expected to be complete in the third quarter of 2025~~. ~~The project is expected to contribute adjusted gross margin of approximately $3.0 million in 2025 and $13.7 million thereafter.~~

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

Chesapeake Utilities Corporation 2025 Form 10-K Page 36

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gross margin of $0.3 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $10.6 million in 2026 and $17.1 million 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. ~~Construction~~New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the second ~~and~~quarter ~~fourth quarters~~ of ~~2025~~2026. ~~for~~The ~~New~~projects ~~Smyrna~~generated ~~Beach~~adjusted ~~and~~gross ~~Boynton~~margin ~~Beach,~~of ~~respectively~~$4.6 ~~The~~million ~~projects~~for the year ended December 31, 2025, and are expected to contribute adjusted gross margin of approximately $~~4.8 million in 2025 and $~~6.0 million in 2026 and 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 ~~will construct several pipeline~~ extensions ~~which will~~ support FPU’s distribution system inaround the ~~areas of~~ 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 May 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project iswent ~~projected~~into toservice bein ~~completed~~July ~~during the fourth quarter of~~ 2025. The ~~completed~~projects ~~project~~ generated additional adjusted gross margin of $02.15 million for the year ended December 31, ~~2024~~2025, and isare expected to contribute adjusted gross margin of approximately $24.03 million in ~~2025~~2026 and ~~$4.3 million~~ thereafter.

Warwick Pipeline Project

In July 2024, we announced plans to extend Eastern Shore's transmission deliverability by constructing an additional 4.4 miles of six inch steel pipeline. The project will reinforce the supply and growth for our Delaware division distribution system and expand natural gas service further into Maryland for anticipated future growth. This project was placed into service during the fourth quarter of 2024, generated additional adjusted gross margin of $01.45 million for the year ended December 31, ~~2024~~2025, and is expected to contribute adjusted gross margin of approximately $1.9 million in ~~2025~~2026 and thereafter.

Pioneer Supply Header Pipeline Project

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

Renewable Natural Gas Supply Projects

In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for ~~its~~ approval of ~~its~~ 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 $2.5 million for the year ended December 31, 2025, and are projected to generate total adjusted gross margin of approximately $5.4 million in 2026 and $6.4 million thereafter.

~~Chesapeake~~Miami ~~Utilities~~Inner ~~Corporation~~Loop ~~2024~~Pipeline ~~Form 10-K Page 37~~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 $2.8 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $7.6 million in 2026 and 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 $1.5 million in 2027.

Chesapeake Utilities Corporation 2025 Form 10-K Page 37

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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 in July 2024 with the projects estimated to be completed in the first half of 2025. These three renewable projects are projected to generate total adjusted gross margin of approximately $5.7 million in 2025 and $6.7 million thereafter.

CNG/RNG/LNG Transportation and Infrastructure

We have made a commitment to meet customer demand for CNG, RNG and LNG in the markets we serve. This has included making investments within Marlin Gas Services to be able to transport these products through its virtual pipeline fleet to customers. To date, we have also made an infrastructure investment in Ohio, enabling RNG to fuel a third party landfill fleet and to transport RNG to end use customers off our pipeline system.

We are also involved in various other projects, all at various stages and all with different opportunities to participate across the energy value chain. In many of these projects, Marlin will play a key role in ensuring the RNG is transported to one of our many pipeline systems where it will be injected. We include our RNG transportation services and infrastructure related adjusted gross margin from across the organization in combination with our CNG and LNG projects.

For the year ended December 31, ~~2024~~2025, we generated $510.39 million in additional adjusted gross margin including the margin attributable to the Full Circle Dairy and Noble Road projects described below. We estimate annual adjusted gross margin of approximately $2028.05 million in ~~2025~~2026, and $2029.7 million in ~~2026~~2027 for these transportation related services, with potential for additional growth in future years.

Full Circle Dairy

In February 2023, we announced plans to construct, own and operate a dairy manure RNG facility at Full Circle Dairy in Madison County, Florida. The project consists of a facility converting dairy manure to RNG and transportation assets to bring the gas to market. The first injection of RNG occurred in the second quarter of 2024.

Noble Road Landfill RNG Project

In October 2021, Aspire Energy completed construction of its Noble Road Landfill RNG pipeline project, a 33.1-mile pipeline, which transports RNG generated from the Noble Road landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In conjunction with this expansion, Aspire Energy also upgraded an existing compressor station and installed two new metering and regulation sites. The RNG volume represents more than 10 percent of Aspire Energy’s gas gathering volumes.

Regulatory Initiatives (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 year ended December 31, ~~2024~~2025, there was $3.25 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $610.31 million of adjusted gross margin in ~~2025~~2026 and $813.80 million in ~~2026~~2027.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 38

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FCG SAFE Program

In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the ~~Commission~~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 year ended December 31, ~~2024~~2025, there was $34.86 million of additional adjusted gross margin generated pursuant to the program. The program is expected to generate $812.37 million of adjusted gross margin in ~~2025~~2026 and $1016.94 million in ~~2026~~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 will enable FCG to accelerate remediation related to problematic pipe and facilities consisting of obsolete and exposed pipe. These efforts will serve to improve the safety and reliability of service to FCG's customers, and the modifications will result in an estimated additional $50.0 million in capital expenditures associated with the SAFE Program which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.

Capital Cost Surcharge Programs

In December ~~2024~~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 a PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December ~~2024~~2025. The combined revised surcharge became effective January 1, ~~2025~~2026. For the year ended December 31, ~~2024~~2025, there was $02.45 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to produce adjusted gross margin of approximately $59.30 million in ~~2025~~2026 and $610.71 million in ~~2026~~2027 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

~~Florida~~Storm ~~Natural~~Protection ~~Gas Rate Case Proceeding~~ Plan

In ~~May 2022~~2020, ~~our legacy natural gas distribution businesses in Florida filed a consolidated natural gas rate case with~~ the Florida PSC. ~~The~~implemented ~~application~~the ~~included~~Storm aProtection ~~request~~Plan ~~for the following:~~ (i"SPP") ~~permanent~~and ~~rate~~Storm ~~relief~~Protection ofPlan ~~approximately~~Cost ~~$24.1~~Recovery ~~million,~~Clause ~~effective January 1, 2023,~~ (ii"SPPCRC"), awhich ~~depreciation~~require ~~study~~electric ~~also~~utilities ~~submitted~~to ~~with~~petition the ~~filing;~~Florida ~~(iii)~~PSC ~~authorization~~for toapproval ~~make~~of ~~certain~~a ~~changes~~Transmission toand ~~tariffs~~Distribution toStorm ~~include~~Protection ~~the~~Plan ~~consolidation~~that ofcovers ~~rates~~the ~~and~~utility’s ~~rate~~immediate ~~structure~~10-year ~~across~~planning ~~the~~period ~~businesses~~with ~~and~~updates to ~~unify~~ the ~~Florida~~plan ~~Natural~~at ~~Gas~~least ~~distribution~~every ~~business~~3 ~~under~~years. ~~FPU;~~The ~~(iv)~~SPPCRC ~~authorization~~rules allow the utility to ~~retain~~file ~~the~~for ~~acquisition~~recovery ~~adjustment~~of ~~recorded~~associated atcosts ~~the~~related ~~time~~to ofits ~~the~~SPP. ~~FPU~~Our ~~merger~~Florida inelectric ~~our~~distribution ~~revenue~~operation's ~~requirement;~~SPP and ~~(v)~~SPPCRC ~~authorization~~were tofiled ~~establish~~and anapproved ~~environmental~~in ~~remediation~~2022, ~~surcharge~~with ~~for~~modifications, by the ~~purposes~~Florida ofPSC. ~~addressing~~Rates ~~future~~associated ~~expected~~with ~~remediation~~this ~~costs~~initiative ~~for~~were ~~FPU~~effective ~~MGP~~in ~~sites~~January 2023. In ~~August~~October ~~2022~~2024, ~~interim~~the ~~rates~~Florida ~~were~~PSC approved by the ~~Florida~~Company's ~~PSC~~projected in2025 ~~the~~SPP ~~amount~~costs of ~~approximately~~ $720.74 million ~~on an annualized basis, effective~~ for ~~all~~both ~~meter~~capital ~~readings~~and inoperating ~~September 2022~~expenses. InOur ~~January~~Florida ~~2023,~~electric ~~the~~distribution ~~Florida~~operations ~~PSC~~filed ~~approved~~an ~~the~~updated ~~application~~SPP ~~for~~plan ~~consolidation~~in ~~and~~January ~~permanent~~2025 ~~rate~~which ~~relief~~was ofapproved ~~approximately~~in ~~$17.2~~June ~~million~~2025, onwith anmodifications ~~annual~~by ~~basis.~~the ~~Actual~~Florida ~~rates~~PSC. ~~were~~For ~~approved~~the byyear ~~the~~ended ~~Florida~~December 31, ~~PSC~~2025, inthis ~~February~~initiative ~~2023~~generated ~~with~~incremental anadjusted ~~effective~~gross ~~date~~margin of ~~March~~$3.2 1million, ~~2023.~~and ~~The proceeding~~ is expected to generate $179.21 million ofin ~~total~~2026. ~~adjusted~~We ~~gross~~expect ~~margin~~continued ininvestment ~~2025~~under ~~and~~the ~~thereafter~~SPP going forward.

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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 ana 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 ~~which we anticipate will be called Chesapeake Utilities of Maryland, Inc.~~; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. In August 2024, the Maryland natural gas distribution businesses, the Maryland ~~Office of Peoples' Counsel ("~~OPC") and PSC ~~Staff~~staff reached a settlement ~~agreement~~ which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the related settlement agreement in part. The $2.6 million increase in annual base rates was approved, and the Company filed ~~the~~a Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The hearing ~~has~~was ~~been~~held ~~scheduled~~in March 2025, during which Phase II was approved, including an additional $0.9 million in revenue requirement, for ~~March~~a total cumulative increase of $3.5 million. A final order was issued in April 2025 and included approval of the ~~outcome~~consolidation of the ~~application~~operations isand ~~subject~~the toassets ~~review~~of CUC-Maryland Division, Sandpiper Energy, and ~~approval~~Elkton byGas ~~the~~into one entity which was renamed and operates as Chesapeake Utilities of Maryland, ~~PSC~~Inc. For the year ended December 31, 2025, there was $1.5 million of adjusted gross margin generated pursuant to the program. The program is expected to generate $3.5 million of adjusted gross margin in 2026 and in 2027.

Maryland Natural Gas Depreciation Study

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

Chesapeake Utilities Corporation 2024 Form 10-K Page 39

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January 1, 2023. The approved depreciation rates resulted in an annual reduction in depreciation expense of approximately $1.2 million.

Delaware Natural Gas Rate Case

In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. ~~In connection with the application, we are~~ seeking approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective in October 2024. ~~The~~A ~~hearing~~settlement ~~for~~among the ~~proceeding~~Company, ~~has~~PSC ~~been~~staff ~~scheduled~~and ~~for~~the ~~May~~Delaware ~~2025,~~Division of the Public Advocate was reached and approved by the ~~outcome~~Delaware PSC in June 2025 providing an annual revenue increase of $6.1 million, as well as dividing the ~~application~~rate iscase ~~subject~~into two phases. Rates set to ~~review~~recover the approved components of the increase were effective in March 2025. In October 2025, a settlement was reached for Phase II of the rate case addressing tariff-related changes including rate design and ~~approval~~approved by the Delaware ~~PSC~~Public Service Commission with rates effective as of October 15, 2025. For the year ended December 31, 2025, there was $4.1 million of additional adjusted gross margin generated and final rates are expected to generate approximately $6.1 million of adjusted gross margin in 2026 and in 2027.

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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. ~~The~~In ~~outcome~~March of2025, the ~~application~~Florida isPSC ~~subject~~approved the permanent rate increase, but the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to ~~review~~resolve ~~and~~all ~~approval~~outstanding issues. This settlement which was approved by the Florida PSC in July 2025, provides for a total base rate increase of approximately $8.6 ~~The~~million ~~hearings~~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 ~~approval~~purchase and refurbishment of certain substations, which is expected to be completed in December 2026. For the ~~revenue~~year ~~requirement~~ended December 31, 2025, there was $7.0 million of additional adjusted gross margin generated and final rates are ~~scheduled~~expected to ~~occur~~generate approximately $8.6 million of adjusted gross margin in ~~March~~2026 ~~2025~~and $9.1 million in 2027.

~~Storm~~Florida ~~Protection~~Mandatory ~~Plan~~Relocates

In ~~2020~~October 2025, ~~the~~FPU ~~Florida PSC implemented the Storm Protection Plan ("SPP")~~ and ~~Storm~~FCG ~~Protection~~filed ~~Plan~~a ~~Cost~~joint ~~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~~establish ~~plan~~a atrecovery ~~least~~surcharge ~~every~~for 3actual, ~~years.~~estimated ~~The~~and ~~SPPCRC~~projected ~~rules~~relocation ~~allow the utility to file for recovery of associated~~ costs ~~related~~pursuant to ~~its~~the ~~SPP. Our~~ Florida ~~electric~~Administrative ~~distribution~~Code ~~operation's~~which ~~SPP~~enables ~~and~~companies ~~SPPCRC~~to ~~were~~recover ~~filed during~~ the ~~first~~costs ~~quarter~~associated ofwith ~~2022~~relocating ~~and~~or ~~approved~~reconstructing infacilities ~~the~~that ~~fourth~~have ~~quarter~~been ofrequired ~~2022, with modifications,~~ by ~~the~~governmental ~~Florida PSC~~entities. InThe ~~October 2024, the Florida PSC approved the Company's~~ projected ~~2025~~revenue ~~SPP~~requirement ~~costs~~ for ~~both~~2026 ~~capital~~is ~~and operating expenses~~$0.5 ~~For~~million ~~the~~for ~~year~~FPU ~~ended~~and ~~December 31, 2024, this initiative generated incremental adjusted gross margin of~~ $1.90 million, ~~and~~for isFCG. ~~expected~~The toFlorida ~~generate~~PSC ~~$5.6~~approved ~~million~~the petition in ~~2025~~February ~~and~~ 2026., Wewith ~~expect~~the ~~continued~~surcharge ~~investment~~effective ~~under~~in ~~the~~March ~~SPP going forward~~2026.

~~Chesapeake~~Florida ~~Utilities~~City ~~Corporation~~Gas ~~2024~~Rate ~~Form 10-K Page 40~~Case

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

FCG Depreciation Study

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

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Other Major Factors Influencing Adjusted Gross Margin

Weather Impact

In ~~2024~~2025, ~~higher~~increased customer consumption, which includes the effects of colder weather, ~~compared~~largely toin the ~~prior~~Company's ~~year~~Ohio, ~~resulted~~Delmarva inand aFlorida ~~$0.3 million increase in adjusted gross margin. While temperatures in our Delmarva~~ service ~~territories~~areas, ~~were~~compared ~~colder~~to ~~than~~ the prior year, ~~our~~resulted ~~Ohio~~in ~~service~~a ~~territories experienced warmer temperatures compared to 2023~~$9.5 Inmillion ~~addition,~~increase ~~temperatures~~ in ~~the~~adjusted ~~Delmarva~~gross ~~and Ohio service territories in 2024 were both approximately 10 percent warmer compared to normal temperatures~~margin. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the years ended ~~2024~~2025 compared to ~~2023~~2024, and ~~2023~~2024 compared to ~~2022~~2023.

HDD and CDD Information

For the Year Ended December 31,

2024

2023

Variance

2023

2022

Variance

2025

2024

Variance

2024

2023

Variance

Delmarva

Actual HDD

34,~~634~~107

3,~~416~~634

~~218~~473

3,~~416~~634

43,~~088~~416

~~(672)~~218

10-Year Average HDD ("Normal")

43,~~039~~919

4,~~161~~039

(~~122~~120)

4,~~161~~039

4,~~147~~161

14(122)

Variance from Normal

~~(405)~~188

(~~745~~405)

(59745)

Florida

Actual HDD

~~796~~951

~~664~~796

~~132~~155

~~664~~796

~~836~~664

~~(172)~~132

10-Year Average HDD ("Normal")

~~794~~781

~~826~~794

(3213)

~~826~~794

~~828~~826

(232)

Variance from Normal

2170

~~(162)~~2

8(162)

Florida City Gas

Actual HDD

429

351

255

10-Year Average HDD ("Normal")

340

348

(8)

348

361

(13)

Variance from Normal

(106)

Ohio

Actual HDD

56,~~014~~120

5,~~043~~014

~~(29)~~1,106

5,~~043~~014

5,~~532~~043

(~~489~~29)

10-Year Average HDD ("Normal")

5,~~594~~357

5,594

—(237)

5,594

5,~~557~~594

37—

Variance from Normal

~~(580)~~763

(~~551~~580)

(25551)

Florida

Actual CDD

32,~~299~~951

3,~~101~~299

~~198~~(348)

3,~~101~~299

23,~~826~~101

~~275~~198

10-Year Average CDD ("Normal")

3,~~009~~037

23,~~934~~009

7528

23,~~934~~009

2,~~929~~934

575

Variance from Normal

~~290~~(86)

~~167~~290

~~(103)~~167

Natural Gas Distribution Growth

The average number of residential customers served on the Delmarva Peninsula, ~~and~~by ~~our~~FPU ~~legacy~~and ~~Florida~~by ~~Natural~~FCG ~~Gas distribution business~~ increased by approximately 4.01 percent, 3.6 percent and 32.92 percent, respectively, during ~~2024~~2025.

The ~~details~~increase ~~are~~in adjusted gross margin resulting from customer growth is provided in the following table:

	Adjusted Gross Margin Increase
	For the Year Ended December 31, 2024
	For the Year Ended December 31, 2025
(in millions)	Delmarva Peninsula		Florida
Customer growth:
Residential	$	1.65	$	23.71
Commercial and industrial	0.53		12.05
Total customer growth (1)	$	2.1	$	3.7
Total customer growth	$	1.8	$	5.6

~~(1)~~Chesapeake ~~Includes~~Utilities ~~growth~~Corporation ~~amounts~~2025 ~~for~~Form ~~our~~10-K ~~legacy~~Page ~~Florida operations, but excludes the effects of FCG.~~42

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REGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2025		2024		Change		2024		2023		Change
For the Year Ended December	2024		2023		(Decrease)		2023		2022		(Decrease)
(in millions)
Revenue	$	~~583~~687.48	$	~~473~~583.64	$	~~109~~104.84	$	~~473~~583.64	$	~~429~~473.46	$	44109.28
Regulated natural gas and electric costs	~~144~~193.28		~~140~~144.02		449.26		~~140~~144.02		~~127~~140.20		124.82
Adjusted gross margin (1)	~~439~~494.20		~~333~~439.62		~~105~~54.68		~~333~~439.62		~~302~~333.26		31105.46
Operations & maintenance	~~150~~160.42		~~119~~150.84		30(9.68)		~~119~~150.84		~~108~~119.28		11(30.6)
Depreciation, amortization and property taxes	82.5		71.7		10.8		71.7		74.0		(2.3)
Depreciation, amortization and property taxes (2)	104.7		82.5		(22.2)		82.5		71.7		(10.8)
FCG transaction and transition-related expenses (2)	4.0		10.4		(6.4)		10.4		—		10.4
Other taxes	5.9		6.1		0.2		6.1		5.5		(0.6)
Other taxes	6.1		5.5		0.6		5.5		4.7		0.8
FCG transaction and transition-related expenses (3)	1.2		4.0		2.8		4.0		10.4		6.4
Other operating expenses	~~243~~272.0		~~207~~243.40		35(29.60)		~~207~~243.40		~~186~~207.94		20(35.56)
Operating Income	$	196.2	$	126.2	$	70.0	$	126.2	$	115.3	$	10.9
Operating Income (4)	$	222.0	$	196.2	$	25.8	$	196.2	$	126.2	$	70.0

(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.

(2) ~~Transaction~~Includes ~~and~~the ~~transition-related~~absence ~~expenses~~of ~~represent~~an ~~costs~~RSAM ~~attributable~~adjustment tofrom ~~the acquisition and integration of~~ FCG ~~including,~~which ~~but~~represented ~~not~~a ~~limited~~$15.5 ~~to,~~million ~~transaction~~benefit ~~costs,~~during ~~transition~~the ~~services,~~year ~~consulting,~~ended ~~system integration~~December 31, ~~rebranding and legal fees~~2024.

~~2024~~(3) ~~compared~~Transaction and transition-related expenses represent costs attributable to ~~2023~~the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.

(4) Operating ~~income~~results for the Regulated Energy segment for 2024 was $196.2 million, an increase of $70.0 million or 55.5 percent compared to 2023. Excluding transaction and transition-related expenses associated with the acquisition of FCG, ~~operating~~are ~~income~~included ~~increased $63.6 million or 46.6 percent compared to the prior year. Higher operating income reflects incremental contributions~~ from the acquisition ofdate ~~FCG,~~(November ~~incremental margin from our regulatory initiatives and infrastructure programs~~30, ~~and organic growth in our natural gas distribution businesses and pipeline expansion projects~~2023). Excluding the transaction and transition-related expenses described above, operating expenses increased by $42.0 million compared to the prior year primarily attributable to increased FCG operating expenses, higher depreciation, amortization and property taxes and increased facilities expenses, maintenance costs and outside services. Increases in depreciation, amortization and property taxes attributable to growth projects and FCG were offset by lower depreciation rates that were approved as part of the rate filings for our Florida electric operations and Maryland natural gas utilities and a $10.4 million increase in the RSAM adjustment from FCG in 2024 compared to the prior year.

2025 compared to 2024

Operating income for the Regulated Energy segment for 2025 was $222.0 million, an increase of $25.8 million compared to 2024. Excluding transaction and transition-related expenses associated with the acquisition of FCG, operating income increased $23.0 million or 11.5 percent compared to the prior year. Higher operating income reflects incremental margin from our 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, operating expenses increased by $31.8 million compared to the prior year primarily attributable to higher depreciation, amortization and property taxes and increased facilities expenses, maintenance costs and outside services. Increases in depreciation are attributable to growth projects and the absence of an RSAM adjustment from FCG which represented a $15.5 million benefit compared to the prior year.

Adjusted Gross Margin

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

(in millions)
Contribution from FCG	$	88.6
Natural gas transmission service expansions, including interim services	$	18.8
Margin from regulated infrastructure programs	6.2
Contributions from regulated infrastructure programs	13.8
Natural gas growth including conversions (excluding service expansions)	5.8
Rate changes associated with recent rate case activities (1)	12.6
Natural gas transmission service expansions, including interim services	5.2
Natural gas growth including conversions (excluding service expansions)	7.4
Rate changes associated with Florida natural gas base rate proceeding (1)	1.6
Changes in customer consumption	2.4
Interim rates from recent rate case activities	0.9
Other variances	(0.2)
Expiration of regulatory recovery for pandemic related costs	(1.2)
Year-over-year increase in adjusted gross margin	$	54.8
Other variances	(1.5)
Year-over-year increase in adjusted gross margin	$	105.6

(1) Includes adjusted gross margin contributions from both interim and permanent base rates. ~~that~~Refer ~~became~~to ~~effective~~Major inProjects ~~March~~discussion ~~2023~~for additional information.

The following narrative discussion provides further detail and analysis of the significant variances in adjusted gross margin detailed above.

~~Contribution~~Natural ~~from~~Gas ~~Acquisition~~Transmission ofService ~~FCG~~Expansions, including interim services

~~FCG~~We ~~contributed~~generated ~~incremental~~increased adjusted gross margin of $8818.68 million for the year ended December 31, ~~2024~~2025 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore.

~~Chesapeake~~Contributions ~~Utilities~~from ~~Corporation~~Regulated ~~2024~~Infrastructure ~~Form 10-K Page 42~~Programs

Regulated infrastructure programs generated incremental adjusted gross margin of $13.8 million for the year ended December 31, 2025. The increase in adjusted gross margin was primarily related to FCG's SAFE program, Florida's GUARD

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~~Margin~~program, ~~from~~FPU ~~Regulated~~Electric's ~~Infrastructure~~SPP, ~~Programs~~and Eastern Shore's Capital Cost Surcharge program. Refer to Note 17, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

~~Regulated~~Rate ~~infrastructure~~Changes ~~programs~~Associated ~~generated~~with ~~incremental~~Recent ~~adjusted~~Rate ~~gross~~Case margin of $6.2 million for the year ended December 31, 2024. The increase in adjusted gross margin was primarily related to Florida's GUARD program and FPU Electric's SPP. Refer to Note 18, Rates and Other Regulatory Activities~~, in the consolidated financial statements for additional information.~~

Rate changes associated with the Delaware and Maryland natural gas rate cases and Florida Electric base rate case contributed additional adjusted gross margin of $12.6 million for the year ended December 31, 2025. Refer to Note 17, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Natural Gas Distribution Customer Growth

We generated additional adjusted gross margin of $57.84 million from natural gas customer growth. Adjusted gross margin increased by $35.76 million for our Florida ~~Natural~~natural ~~Gas~~gas distribution ~~business~~businesses and $2.1.8 million on the Delmarva Peninsula compared to ~~2023~~2024, due primarily to residential customer growth of 32.98 percent and 4.01 percent in Florida and on the Delmarva Peninsula, respectively.

~~Natural~~Increased ~~Gas~~Customer ~~Transmission Service Expansions, including interim services~~Consumption

WeCustomer ~~generated~~consumption, inclusive of weather-related consumption, increased adjusted gross margin ofby $5.2.4 million for the year ended December 31, ~~2024 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore~~2025.

Rate Changes Associated with the Florida Natural Gas Base Rate Proceeding

Permanent rates associated with the Florida Natural Gas base rate proceeding, effective on March 1, 2023, contributed additional adjusted gross margin of $1.6 million for the year ended December 31, 2024. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Interim Rates from Recent Rate Case Activities

Interim rates associated with the Delaware natural gas rate case and Florida Electric base rate case contributed additional adjusted gross margin of $0.9 million for the year ended December 31, 2024. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Expiration of Regulatory Recovery for Pandemic Related Costs

The expiration of regulatory recovery for pandemic related costs offset adjusted gross margin by $1.2 million for the year ended December 31, 2024.

Other Operating Expenses

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

(in millions)
FCG operating expenses	$	37.8
Depreciation, amortization and property taxes	$	(22.2)
Depreciation, amortization and property tax costs	3.6
Facilities expenses, maintenance costs and outside services	(4.7)
Facilities expenses, maintenance costs and outside services	1.3
Insurance related costs	(1.7)
Insurance related costs	1.0
Credit, collections and customer service costs	(1.3)
Payroll, benefits and other employee-related expenses	(1.02)
FCG transaction and transition-related expenses (1)	(62.4)8
Other variances	(0.7)
Year-over-year increase in other operating expenses	$	35(29.60)

(1) Transaction and transition-related expenses represent costs attributable to the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.

~~2023~~2024 compared to ~~2022~~2023

The results for the Regulated Energy segment for the year ended December 31, ~~2023~~2024 compared to ~~2022~~2023 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, ~~2023~~2024, which is incorporated herein by reference.

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UNREGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2025		2024		Change		2024		2023		Change
For the Year Ended December 31,	2024		2023		(Decrease)		2023		2022		(Decrease)
(in millions)
Revenue	$	~~228~~271.49	$	~~223~~228.14	$	543.35	$	~~223~~228.14	$	~~280~~223.81	$	~~(57~~5.7)3
Propane and natural gas costs	~~100~~127.23		~~102~~100.52		(227.3)1		~~102~~100.52		~~162~~102.75		(~~60.~~2.3)
Adjusted gross margin (1)	~~128~~144.26		~~120~~128.62		716.64		~~120~~128.62		~~118~~120.16		27.56
Operations & maintenance	7485.81		74.28		0(10.63)		74.28		7074.52		3(0.76)
Depreciation, amortization and property taxes	1923.1		19.51		(0.4.0)		19.51		1719.85		10.74
Other taxes	2.68		2.56		(0.12)		2.56		2.45		(0.1)
Other operating expenses	96111.50		96.25		0(14.35)		96.25		9096.72		5(0.53)
Operating Income	$	3133.76	$	2431.47	$	71.39	$	2431.47	$	2724.4	$	(37.0)3

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~~2024~~2025 Compared to ~~2023~~2024

Operating income for the Unregulated Energy segment for ~~2024~~2025 increased by $71.39 million or 296.90 percent compared to ~~2023~~2024. Adjusted gross margin in the Unregulated Energy segment increased primarily due to increased levels of virtual pipeline services, and increased ~~propane~~customer consumption ~~including~~in ~~the~~our ~~impact~~propane ofoperations ~~the December 2023 acquisition,~~ and ~~increased gathering fees and rate changes~~ at Aspire. These increases were partially offset by ~~reduced~~a ~~customer~~change ~~consumption~~in ~~at Aspire primarily from agricultural customers and reduced~~ propane ~~margins~~margin and service fees. The increase in operating expenses included higher ~~vehicle~~payroll, ~~expenses~~benefits and ~~insurance~~other ~~costs~~employee-related ~~which~~expenses, ~~were~~increased ~~largely~~facilities, ~~offset~~maintenance byand ~~lower~~outside ~~payroll~~services costs, ~~benefits~~ and ~~other~~higher ~~employee-related~~depreciation and vehicle expenses compared to the prior year.

Adjusted Gross Margin

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

(in millions)
Propane Operations
Increased propane customer consumption	$	14.85
Contributions from acquisition	1.0
Change in propane margins and service fees	(1.4)
Decreased propane margins and service fees	(0.3)
CNG/RNG/LNG Transportation and Infrastructure
Increased demand for virtual pipeline services	4.5
Increased demand for CNG/RNG/LNG services	10.7
Aspire Energy
Increased margins - rate changes and gathering fees	1.6
Increased customer consumption	2.6
Change in customer consumption	(1.4)
Year-over-year increase in adjusted gross margin	$	16.4
Other variances	0.4
Year-over-year increase in adjusted gross margin	$	7.6

The following narrative discussion provides further detail and analysis of the significant items in the foregoing table.

Propane Operations

•Increased propane customer consumption - Adjusted gross margin was positively impacted by $14.85 million as a result of increased customer consumption driven by colder weather experienced in our Mid-Atlantic and North Carolina service areas during the fourth quarter of ~~2024~~2025.

•~~Contributions~~Propane ~~from~~margins ~~acquisition~~and fees - Adjusted gross margin ~~increased~~declined by $1.04 million, ~~from~~mainly ~~the~~due ~~acquisition~~to oflower Jmargins and customer service fees.T. ~~Lee~~These market conditions, which include market pricing and ~~Son's~~competition ~~that~~with ~~was~~other ~~completed~~propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in ~~December~~demand, ~~2023~~supply and other energy commodity prices.

•Propane margins and fees - Adjusted gross margin decreased by $0.3 million, mainly due to lower margins and customer service fees. These market conditions, which include market pricing and competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices.

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CNG/RNG/LNG Transportation and Infrastructure

•Increased ~~levels~~demand of virtual pipeline services - Adjusted gross margin increased by $410.57 million over ~~2023~~2024 largely due to increased demand for CNG and RNG hold services.

Aspire Energy

•~~Increase~~Increased incustomer ~~gathering~~consumption ~~charges~~ - Adjusted gross margin increased by $12.6 million ~~primarily~~ due to increased ~~gathering~~customer ~~charges~~consumption ~~associated~~related ~~with~~to athe ~~large~~effects ~~commercial~~of ~~customer.~~colder weather in our Ohio service area and resulting from higher consumption from agricultural customers compared to the prior year.

•Change in customer consumption - Adjusted gross margin decreased by $1.4 million due to lower customer consumption from agricultural customers compared to the prior year.

Other Operating Expenses

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

(in millions)
Vehicle expenses	$	0.9
Insurance related costs	0.6
Facilities, maintenance costs, and outside services	0.1
Payroll, benefits and other employee-related expenses	(1.0)
Depreciation, amortization and property tax costs	(0.4)
Other variances	0.1
Year-over-year increase in other operating expenses	$	0.3

Chesapeake Utilities Corporation 2025 Form 10-K Page 45

~~2023~~Table ~~compared~~of ~~to 2022~~Contents

The results for the Unregulated Energy segment for the year ended December 31, 2023 compared to 2022 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated by reference.


(in millions)
Payroll, benefits and other employee-related expenses	$	(5.5)
Facilities, maintenance costs, and outside services	(4.5)
Depreciation, amortization and property taxes	(4.0)


Other variances	(0.5)
Year-over-year increase in other operating expenses	$	(14.5)

2024 compared to 2023

The results for the Unregulated Energy segment for the year ended December 31, 2024 compared to 2023 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2024, which is incorporated by reference.

OTHER INCOME, NET

~~2024~~2025 Compared to ~~2023~~2024

Other income, net, which includes non-operating investment income, interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, amounted to $29.06 million and $12.40 million for ~~2024~~2025 and ~~2023~~2024, respectively. The increase in 2025 was largely attributable to higher gains on asset sales compared to the prior year.

INTEREST CHARGES

~~2024~~2025 Compared to ~~2023~~2024

Interest charges for ~~2024~~2025 increased by $314.51 million compared to the same period in ~~2023~~2024. This increase is primarily attributable to the Senior Notes issued in ~~November~~August ~~2023~~and inSeptember ~~connection~~2025. ~~with~~Increased ~~the~~interest ~~acquisition~~expense ofwas ~~FCG.~~partially ~~Higher~~offset ~~interest~~by ~~expense~~lower onaverage outstanding Revolver borrowings, ~~driven~~a bylower ~~higher~~ weighted-average ~~outstanding~~interest ~~borrowings~~rate, and ~~rates~~higher ~~compared~~capitalized tointerest ~~the~~of ~~prior~~$1.6 ~~year~~million ~~also~~associated ~~contributed~~with growth capital projects compared to the ~~increase~~prior year. The weighted-average interest rate on our Revolver borrowings was 5.6817 percent for the year ended December 31, ~~2024~~2025 compared to 5.4168 percent during the prior year. ~~These factors were partially offset by higher capitalized interest of $2.2 million during the current year associated with growth capital projects.~~

INCOME TAXES

~~2024~~2025 Compared to ~~2023~~2024

Income tax expense was $4352.27 million for ~~2024~~2025 compared to $2843.12 million for ~~2023~~2024. Our effective income tax rates were 2627.73 percent and 2426.47 percent for the years ended December 31, ~~2024~~2025 and ~~2023~~2024, respectively. Income tax expense for the year ended December 31, 2023 included a $2.5 million benefit in deferred tax expense resulting from a reduction in the Pennsylvania state income tax rate. Excluding this change, our effective income tax rate was 26.5 percent in 2023.

Chesapeake Utilities Corporation 2024 Form 10-K Page 45

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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. 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, as applicable, for the issuance of shares of common stock under various types of equity offerings, including the DRIP and under an ATM equity 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 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 $~~355~~470.84 million in ~~2024~~2025.

~~The~~Chesapeake ~~following~~Utilities ~~table~~Corporation ~~shows~~2025 ~~total~~Form ~~capital~~10-K ~~expenditures~~Page ~~for the year ended December 31, 2024 by segment and by business line:~~46

	For the Year Ended December 31, 2024
(in millions)
Regulated Energy:
Natural gas distribution	$	218.6
Natural gas transmission	68.8
Electric distribution	32.8
Total Regulated Energy	320.2
Unregulated Energy:
Propane distribution	12.0
Energy transmission	5.3
Other unregulated energy	16.6
Total Unregulated Energy	33.9
Other:
Corporate and other businesses	1.7
Total Other	1.7
Total 2024 Capital Expenditures	$	355.8

In the table below, we have provided a range of our forecasted capital expenditures by segment and business line for 2025:

Chesapeake Utilities Corporation 2024 Form 10-K Page 46

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	Estimate for Fiscal 2025
(in millions)	Low		High
Regulated Energy:
Natural gas distribution	$	135.0	$	155.0
Natural gas transmission	135.0		145.0
Electric distribution	35.0		45.0
Total Regulated Energy	305.0		345.0
Unregulated Energy:
Propane distribution	12.0		15.0
Energy transmission	5.0		10.0
Other unregulated energy	2.0		3.0
Total Unregulated Energy	19.0		28.0
Other:
Corporate and other businesses	1.0		2.0
Total 2025 Forecasted Capital Expenditures	$	325.0	$	375.0

The following table shows total capital expenditures for the year ended December 31, 2025 by segment and by business line:

The 2025 forecast excludes potential acquisitions due to their opportunistic nature.


	For the Year Ended December 31, 2025
(in millions)
Regulated distribution	$	124.4
Regulated transmission	140.0
Regulated infrastructure	121.2
Unregulated businesses	49.9
Technology	34.9
Total 2025 Capital Expenditures	$	470.4

~~The~~In ~~Company~~the ~~continues~~table tobelow, ~~re-affirm~~we ~~its~~have ~~capital~~provided ~~guidance~~a ~~for~~range ~~the five-year period ended 2028~~ of ~~$1.5~~our ~~billion~~forecasted ~~to $1.8 billion, and projects~~ capital expenditures ofby ~~$325~~category ~~million to $375 million~~ for ~~2025.~~2026:

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 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. Historically, actual capital expenditures have typically lagged behind the budgeted amounts. 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.


	Estimate for Fiscal 2026
(in millions)	Low		High
Regulated distribution	$	110.0	$	120.0
Regulated transmission	135.0		145.0
Regulated infrastructure	90.0		100.0
Unregulated businesses	25.0		35.0
Technology	90.0		100.0

Total 2026 Forecasted Capital Expenditures	$	450.0	$	500.0

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

The Company continues to affirm its capital guidance for the five-year period ended 2028 of $1.5 billion to $1.8 billion, and projects capital expenditures of $450.0 million to $500.0 million for 2026.

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 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. 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.

Chesapeake Utilities Corporation 2025 Form 10-K Page 47

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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 tables present our capitalization as of December 31, ~~2024~~2025 and ~~2023~~2024 and includes the impacts associated with financing the FCG acquisition:

	December 31, 2024				December 31, 2023
	December 31, 2025				December 31, 2024
(dollars in millions)
Long-term debt, net of current maturities	$	1,~~261~~327.71	4845	%	$	1,~~187~~261.17	4948	%
Stockholders’ equity	1,~~390~~598.25		5255	%	1,~~246~~390.12		5152	%
Total capitalization, excluding short-term borrowings	$	2,~~651~~925.96	100	%	$	2,~~433~~651.29	100	%

	December 31, 2024				December 31, 2023
	December 31, 2025				December 31, 2024
(dollars in millions)
Short-term debt	$	~~196~~158.50	75	%	$	~~179~~196.95	7	%
Long-term debt, including current maturities	1,~~287~~461.27		45	%	1,~~205~~287.62		4645	%
Stockholders’ equity	1,~~390~~598.25		4850	%	1,~~246~~390.12		4748	%
Total capitalization, including short-term borrowings	$	23,~~873~~218.92	100	%	$	2,~~631~~873.69	100	%

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. 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 ~~expect~~may, tofrom ~~move~~time ~~closer~~ to ~~our~~time, ~~target~~allow our capital structure ~~over~~to fall below the ~~next~~target ~~couple~~range to align the completion of ~~years~~large capital projects with the respective permanent financing.

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

In November 2024, we established a new ATM program under which we may sell shares of our common stock up to an aggregate offering price of $100.0 million. This current ATM program is active through November 2027. For the year ended December 31, 2025 and 2024, we received net proceeds of $123.2 million and $72.5 million, respectively, associated with shares issued under the ~~direct~~DRIP ~~stock purchase~~ and ~~waiver~~our ~~components~~ATM ~~of the DRIP~~program. ~~During 2023, there were no issuances under the DRIP.~~

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife ~~with terms that extend through February 2026~~, however neither of such lenders have any obligation to purchase debt thereunder. AtWe ~~December~~amended 31these agreements with Prudential and MetLife in February 2026 and June 2025, ~~2024~~respectively, to expand the total borrowing capacity and extend the term of the agreements. As of the February 2026 amendment, a total of $~~255~~343.03 million of borrowing capacity was available under these agreements with terms that extend through February 2029 and June 2030, respectively.

Long-Term Debt

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.

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

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

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

On March 14, 2023, we issued 5.43 percent Senior Notes due in March 2038 in the aggregate principal amount of $80.0 million and used the proceeds received from the issuances of the Senior Notes to reduce short-term borrowings under our Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal amortization payment beginning in the sixth year after the issuance.

Short-Term Borrowings

We are authorized by our ~~Board~~BOD ~~of Directors~~ to borrow up to $450.0 million of short-term debt, as required. At December 31, ~~2024~~2025 and ~~2023~~2024, we had $~~196~~158.50 million and $~~179~~196.95 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 54.0673 percent and 5.8306 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, ~~2024~~2025.

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

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

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The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, ~~2024~~2025, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, ~~2024~~2025 was $~~250~~287.02 million. As of December 31, ~~2024~~2025, we had issued $64.98 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 1514, Stockholders Equity.

Key statistics regarding our unsecured short-term credit facilities (our Revolver and previous bilateral lines of credit and revolving credit facility) for the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023 are as follows:

(dollars in millions)	~~2024~~2025			~~2023~~2024			~~2022~~2023
Average borrowings during the year	$	~~185~~174.71		$	~~130~~185.27		$	~~170~~130.42
Weighted average interest rate for the year	5.6702		%	5.4167		%	25.4941		%
Maximum month-end borrowings	$	~~249~~256.75		$	~~206~~249.57		$	~~225~~206.15

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023:

	For the Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
(in millions)
Net cash provided by (used in):
Operating activities	$	~~239~~233.47	$	~~203~~239.54	$	~~158~~203.95
Investing activities	(~~349~~435.97)		(~~1,111~~349.49)		(~~136~~1,111.54)
Financing activities	~~113~~195.59		~~906~~113.65		~~(21~~906.2)6
Net increase (decrease) in cash and cash equivalents	3(6.01)		~~(1.~~3).0		(1.23)
Cash and cash equivalents—beginning of period	47.9		64.29		56.02
Cash and cash equivalents—end of period	$	71.98	$	47.9	$	64.29

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 changes in 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.

We normally generate a large portion of our annual net income and related increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered to customers during the peak heating season by our natural gas and propane operations and our natural gas supply, gathering and processing operation. 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.

During ~~2024~~2025, net cash provided by operating activities was $~~239~~233.47 million. Operating cash flows were primarily impacted by the following:

•Net income, adjusted for non-cash adjustments, provided a $~~202~~244.14 million source of cash; ~~and~~

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•An increased level of deferred taxes ~~associated~~and ~~largely~~investment ~~with~~tax credits which includes incremental tax depreciation from growth investments resulted in a source of cash of $3628.48 million. ; partially offset by

•Net changes in assets and liabilities resulted in a use of cash of $39.5 million mainly due to an increase in net receivables, accrued revenue and regulatory assets.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $~~349~~435.97 million during the year ended December 31, ~~2024~~2025, largely driven by $~~355~~448.36 million for new capital expenditures partially offset by $512.29 million of proceeds from asset sales.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $~~113~~195.59 million for the year ended December 31, ~~2024~~2025. This source of cash was largely related to:

•A net increase in long-term debt borrowings resulting in a net source of cash of $81173.06 million, including $99199.51 million from issuances partially offset by long-term repayments of $1825.5 million;

•Net proceeds of $72123.60 million from the issuance of common stock under the DRIP and ATM program; partially offset by the following:

•Net ~~borrowings~~repayments under the Revolver of $1439.14 million;, ~~partially offset by~~ and

•A $5460.27 million use of cash for dividend payments in ~~2024~~2025.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5051

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CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, ~~2024~~2025:

	Payments Due by Period
Contractual Obligations	~~2025~~2026		~~2026-~~2027-2028		~~2028-~~2029-2030		After ~~2029~~2030		Total
(in millions)
Long-term debt (1)	$	25134.56	$	~~266~~328.34	$	~~293~~369.70	$	~~705~~633.3	$	1,~~290~~465.83
Operating leases (2)	2.64		3.56		2.36		42.19		1211.5
Purchase obligations (3)
Transmission capacity	45.16		8778.80		5949.8		~~103~~87.09		~~295~~261.73
Storage capacity	3.4.3		27.19		03.27		—3.1		519.70
Commodities	3433.92		—		—		—		3433.92
Electric supply	6.89		13.7		1312.73		1610.49		5043.68
Unfunded benefits (4)	0.32		0.64		0.64		10.18		21.68
Funded benefits (5)	23.24		4.49		42.3		36.56		1417.42
Total Contractual Obligations	$	~~120~~230.86	$	~~378~~436.49	$	~~374~~440.61	$	~~833~~745.45	$	1,~~707~~853.21

(1) This represents principal payments on long-term debt. See Item 8, Financial Statements and Supplementary Data, Note 12, Long-Term Debt, for additional information. The expected interest payments on long-term debt are $6373.90 million, $~~118~~123.34 million, $8786.76 million and $~~126~~98.02 million, respectively, for the periods indicated above. Expected interest payments for all periods total $~~395~~381.92 million.

(2) See Item 8, Financial Statements and Supplementary Data, Note 142, ~~Leases~~Summary of Significant Accounting Policies, for additional information.

(3) See Item 8, Financial Statements and Supplementary Data, Note 2019, Other Commitments and Contingencies, for additional information.

(4) These amounts associated with our unfunded post-employment and post-retirement benefit plans are based on expected payments to current retirees and assume a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations. See Item 8, Financial Statements and Supplementary Data, Note 1615, Employee Benefit Plans, for additional information on the plans.

(5) The FPU Pension Plan was in a ~~$3.6 million~~ over funded position at December 31, ~~2024~~2025. The assets funding this plan are in a separate trust and are not considered assets of ours or included in our balance sheets. We do not expect to make payments to the trust funds in 2025. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8, Financial Statements and Supplementary Data, Note 1615, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $1417.42 million, funded with Rabbi Trust assets in the same amount. The Rabbi Trust assets are recorded under Investments on the consolidated balance sheets. We assume a retirement age of 65 for purposes of distribution from this trust.

OFF-BALANCE SHEET ARRANGEMENTS

Our ~~Board~~BOD ~~of Directors~~ has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of December 31, ~~2024~~2025 was $3862.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, ~~2024~~2025 was approximately $2841.41 million with the guarantees expiring on various dates through ~~November~~March ~~2025~~2026. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, ~~2024~~2025 was $54.20 million.

As of December 31, ~~2024~~2025, we have issued letters of credit totaling approximately $64.98 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 ~~2025~~2026. There have been no draws on these letters of credit as of December 31, ~~2024~~2025. 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 Item 8, Financial Statements and Supplementary Data, Note 2019, Other Commitments and Contingencies in the consolidated financial statements.

CRITICAL ACCOUNTING ESTIMATES

We prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. We base our estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since a significant portion of our businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Chesapeake Utilities Corporation 2024 Form 10-K Page 51

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Regulatory Assets and Liabilities

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As a result of the ratemaking process, we record certain assets and liabilities in accordance with ASC Topic 980, Regulated Operations, and consequently, the accounting principles applied by our regulated energy businesses differ in certain respects from those applied by the unregulated businesses. Amounts are deferred as regulatory assets and liabilities when there is a probable expectation that they will be recovered in future revenues or refunded to customers as a result of the regulatory process. This is more fully described in Item 8, Financial Statements and Supplementary Data, Note 2, Summary of Significant Accounting Policies, in the consolidated financial statements. If we were required to terminate the application of ASC Topic 980, we would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material effect on our results of operations.

Financial Instruments

We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. We continually monitor the use of these instruments to ensure compliance with our risk management policies and account for them in accordance with GAAP, such that every derivative instrument is recorded as either an asset or a liability measured at its fair value. It also requires that changes in the derivatives' fair value are recognized in the current period earnings unless specific hedge accounting criteria are met. If these instruments do not meet the definition of derivatives or are considered “normal purchases and normal sales,” they are accounted for on an accrual basis of accounting.

Additionally, GAAP also requires us to classify the derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair value of the assets and liabilities and their placement within the fair value hierarchy.

We determined that certain propane put options, call options, swap agreements and interest rate swap agreements met the specific hedge accounting criteria. We also determined that most of our contracts for the purchase or sale of natural gas, electricity and propane either: (i) did not meet the definition of derivatives because they did not have a minimum purchase/sell requirement, or (ii) were considered “normal purchases and normal sales” because the contracts provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities that we expect to use or sell over a reasonable period of time in the normal course of business. Accordingly, these contracts were accounted for on an accrual basis of accounting.

Additional information about our derivative instruments is disclosed in Item 8, Financial Statements and Supplementary Data, Note 8, Derivative Instruments, in the consolidated financial statements.

Goodwill and Other Intangible Assets

We test goodwill for impairment at least annually in December, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. The annual impairment testing for ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023 indicated that goodwill was not impaired. At December 31, ~~2024~~2025, our goodwill balance totaled $507.75 million including $460.9 million attributable to the acquisition of FCG. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 4, Acquisitions, and Note 10, Goodwill and Other Intangible Assets, in the consolidated financial statements.

Other Assets Impairment Evaluations

We periodically evaluate whether events or circumstances have occurred which indicate that long-lived assets may not be recoverable. When events or circumstances indicate that an impairment is present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.

Pension and Other Postretirement Benefits

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 1615, Employee Benefit Plans, in the consolidated financial statements, including plan asset investment allocation, estimated future benefit payments, general descriptions of the plans, significant assumptions, the impact of certain changes in certain assumptions, and significant changes in estimates.

~~Chesapeake~~At ~~Utilities~~December ~~Corporation~~31, ~~2024~~2025, ~~Form~~actuarial 10assumptions include expected long-Kterm ~~Page~~rates 52of return on plan assets for FPU's pension plan of 5.50 percent and a discount rate of 5.25 percent. The discount rate was determined by management considering high-quality corporate bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and

Chesapeake Utilities Corporation 2025 Form 10-K Page 53

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At December 31, 2024, actuarial assumptions include expected long-term rates of return on plan assets for FPU's pension plan of 6.00 percent and a discount rate of 5.50 percent. The discount rate was determined by management considering high-quality corporate bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected lives of the plans and the availability of the lump-sum payment option. A 25 basis point increase or decrease in the discount rate would not have a material impact on our pension and postretirement liabilities and related costs.

Actual changes in the fair value of plan assets and the differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension benefit costs that we ultimately recognize for our funded pension plan. A 25 basis point change in the rate of return would not have a material impact on the funded status of our FPU pension plan and related costs.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

INTEREST RATE RISK

The fluctuation in interest rates ~~expose~~exposes us to potential increased cost we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. We 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 12, Long-Term Debt, and Note 13, Short-Term Borrowings, respectively, in the 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 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 and sales activities.

We can store up to approximately 8.54 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 a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.

Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers in order to fulfill our natural gas purchase requirements.

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, ~~2023~~2024 to December 31, ~~2024~~2025:

(in millions)			Balance at December 31, ~~2023~~2024						Increase in Fair Market Value						Less Amounts Settled						Balance at December 31, ~~2024~~2025
Sharp			$	(0.4)6					$	2.(0.8)					$	(1.0.5)					$	(0.67)

There were no changes in the methods of valuations during the year ended December 31, ~~2024~~2025.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5354

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The following is a summary of fair market value of financial derivatives as of December 31, ~~2024~~2025, by method of valuation and by maturity for each fiscal year period.

(in millions)			~~2025~~2026						~~2026~~2027						~~2027~~2028						Total Fair Value
Price based on Mont Belvieu - Sharp			$	(0.56)					$	(0.1)					$	—					$	(0.67)

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 Item 8, Financial Statements and Supplementary Data, Note 8, Derivative Instruments, in the 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.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5455

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Stockholders and the Board of Directors ~~and Stockholders~~ of

Chesapeake Utilities Corporation

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation and Subsidiaries (the "Company") as of December 31, ~~2024~~2025 and ~~2023~~2024, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, ~~2024~~2025, and the related notes and financial statement schedules listed in Item 15(a)2 (collectively referred to as the "consolidated financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control –- Integrated Framework: (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the consolidated financial position of the Company as of December 31, ~~2024~~2025 and ~~2023~~2024, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, ~~2024~~2025, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, ~~2024~~2025, based on criteria established in Internal Control –- Integrated Framework: (2013) issued by COSO.

Basis for ~~Opinion~~Opinions

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

A company'’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company'’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5556

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company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

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

Critical Audit ~~Matter~~Matters

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

/s/ Baker Tilly US, LLP

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

Philadelphia, Pennsylvania

February 2625, ~~2025~~2026

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5657

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Income

	For the Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
(dollars in millions, shares in thousands (except per share data))
Operating Revenues
Regulated Energy	$	~~583~~687.48	$	~~473~~583.64	$	~~429~~473.46
Unregulated Energy	~~228~~271.49		~~223~~228.14		~~280~~223.81
Other businesses and eliminations	(2429.67)		(2624.16)		(2926.51)
Total operating revenues	~~787~~930.20		~~670~~787.62		~~680~~670.76
Operating Expenses
Natural gas and electricity costs	~~144~~193.28		~~140~~144.02		~~127~~140.20
Propane and natural gas costs	7597.67		7675.56		~~133~~76.35
Operations	~~210~~229.13		~~178~~210.41		~~164~~178.54
FCG transaction and transition-related expenses	41.02		~~10.~~4.0		—10.4
Maintenance	2223.59		2022.45		1820.24
Depreciation and amortization	6591.7		65.57		6965.05
Other taxes	36.95		2836.69		2528.6
Total operating expenses	~~559~~674.01		~~519~~559.80		~~537~~519.8
Operating Income	~~228~~255.29		~~150~~228.82		~~142~~150.98
Other income, net	29.06		12.40		5.1.4
Interest charges	6872.45		3668.94		2436.49
Income Before Income Taxes	~~161~~193.80		~~115~~161.38		~~123~~115.63
Income taxes	4352.27		2843.12		3328.81
Net Income	$	~~118~~140.63	$	87118.26	$	8987.82
Weighted Average Common Shares Outstanding:
Basic	2223,~~469~~389		1822,~~371~~469		1718,~~722~~371
Diluted	2223,~~531~~488		1822,~~435~~531		1718,~~804~~435
Earnings Per Share of Common Stock:
Basic	$	56.2800	$	45.7528	$	54.0775
Diluted	$	5.2697	$	45.7326	$	54.0473

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5758

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Comprehensive Income

	For the Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
(in millions)
Net Income	$	~~118~~140.63	$	87118.26	$	8987.82
Other Comprehensive Income (Loss), net of tax:
Employee Benefits net gain (loss), net of tax of $0.1, $0.0, and $0.2, respectively	0.5		(0.1)		0.7
Employee Benefits net gain (loss), net of tax of $0.1, $0.1, and $0.0, respectively	0.4		0.5		(0.1)
Cash Flow Hedges, net of tax:
Net gain (loss) on commodity contract cash flow hedges, net of tax of $0.6, $(0.5), and $(0.4), respectively	1.4		(1.4)		(0.9)
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(0.2), $0.6, and $(0.5), respectively	(0.5)		1.4		(1.4)
Reclassifications of net gain on commodity contract cash flow hedges, net of tax of $(0.3), $0.0, and $(1.0), respectively	(0.7)		—		(2.5)
Reclassifications of net gain on commodity contract cash flow hedges, net of tax of $(0.1), $(0.3), and $0.0, respectively	(0.4)		(0.7)		—
Net gain on interest rate swap cash flow hedges, net of tax of $0.2, $0.2, and $0.0, respectively	0.5		0.5		—
Net (loss) gain on interest rate swap cash flow hedges, net of tax of $(0.1), $0.2, and $0.2, respectively	(0.3)		0.5		0.5
Reclassifications of net gain on interest rate swap cash flow hedges, net of tax of $(0.2), $(0.1), and $0.0, respectively	(0.6)		(0.4)		—
Reclassifications of net gain on interest rate swap cash flow hedges, net of tax of $(0.1), $(0.2), and $(0.1), respectively	(0.2)		(0.6)		(0.4)
Total Other Comprehensive Income (Loss)	(1.10)		(1.4)1		(21.74)
Comprehensive Income	$	~~119~~139.73	$	85119.87	$	8785.18

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5859

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Assets	~~2024~~2025		~~2023~~2024
(in millions, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	2,~~661~~941.86	$	2,~~418~~661.58
Unregulated Energy	~~463~~492.74		~~410~~463.87
Other businesses	2938.93		3029.39
Total property, plant and equipment	3,~~155~~472.43		23,~~859~~155.64
Less: Accumulated depreciation and amortization	(~~567~~637.6)		(~~516~~567.46)
Plus: Construction work in progress	~~148~~283.17		~~113~~148.21
Net property, plant and equipment	23,~~735~~118.94		2,~~456~~735.49
Current Assets
Cash and cash equivalents	71.98		47.9
Trade and other receivables	80106.09		7480.50
Less: Allowance for credit losses	(35.34)		(23.73)
Trade and other receivables, net	76101.75		7176.87
Accrued revenue	3750.81		3237.68
Propane inventory, at average cost	8.98		98.39
Other inventory, at average cost	1817.09		1918.90
Regulatory assets	2329.97		1923.59
Storage gas prepayments	34.85		43.78
Income taxes receivable	~~6.8~~—		36.8
Prepaid expenses	1719.37		1517.43
Derivative assets, at fair value	~~0.6~~—		1.0.6
Other current assets	23.60		2.86
Total current assets	~~204~~237.30		~~185~~204.73
Deferred Charges and Other Assets
Goodwill	507.75		~~508~~507.27
Other intangible assets, net	1513.02		1615.90
Investments, at fair value	1417.42		1214.34
Derivative assets, at fair value	~~0.1~~—		—0.1
Operating lease right-of-use assets	109.59		1210.45
Regulatory assets	7774.43		9677.4
Receivables and other deferred charges	1117.73		1611.47
Total deferred charges and other assets	~~636~~639.84		~~662~~636.68
Total Assets	$	3,~~577~~994.08	$	3,~~304~~577.70

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 5960

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Capitalization and Liabilities	~~2024~~2025		~~2023~~2024
(in millions, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—	$	—
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	11.1		10.8
Common stock, par value $0.4867 per share (authorized 75,000,000 shares)	11.6		11.1
Additional paid-in capital	~~830~~962.58		~~749~~830.45
Retained earnings	~~550~~626.38		~~488~~550.73
Accumulated other comprehensive loss	(12.7)		(21.87)
Deferred compensation obligation	912.86		9.18
Treasury stock	(912.86)		(9.18)
Total stockholders’ equity	1,~~390~~598.25		1,~~246~~390.12
Long-term debt, net of current maturities	1,~~261~~327.71		1,~~187~~261.17
Total capitalization	2,~~651~~925.96		2,~~433~~651.29
Current Liabilities
Current portion of long-term debt	25134.56		1825.5
Short-term borrowing	~~196~~158.50		~~179~~196.95
Accounts payable	78115.32		7778.53
Customer deposits and refunds	45.71		4645.47
Accrued interest	4.8.7		74.08
Dividends payable	1416.74		1314.17
Accrued compensation	2321.96		1623.59
Regulatory liabilities	1614.15		1316.71
Derivative liabilities, at fair value	—0.8		~~0.4~~—
Other accrued liabilities	1315.90		13.49
Total current liabilities	~~419~~529.49		~~386~~419.4
Deferred Credits and Other Liabilities
Deferred income taxes	~~296~~313.13		~~259~~296.1
Regulatory liabilities	~~184~~188.01		~~195~~184.30
Environmental liabilities	2.29		2.62
Other pension and benefit costs	1314.20		1513.32
Derivative liabilities at fair value	0.1		0.9
Derivative liabilities, at fair value	0.6		0.1
Operating lease - liabilities	8.7.9		108.67
Deferred investment tax credits and other liabilities	112.45		1.34
Total deferred credits and other liabilities	~~505~~539.73		~~485~~505.17
Environmental and other commitments and contingencies (Notes 19 and 20)
Environmental and other commitments and contingencies (Notes 18 and 19)
Total Capitalization and Liabilities	$	3,~~577~~994.08	$	3,~~304~~577.70

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6061

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2024		2023		2022
	2025		2024		2023
(in millions)
Operating Activities
Net Income	$	~~118~~140.63	$	87118.26	$	8987.82
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	6591.7		65.57		6965.05
Depreciation and accretion included in operations expenses	15.89		1115.98		11.09
Deferred income taxes, net	36.4		3.4		23.7
Deferred income taxes and investment tax credits	28.8		36.4		3.4
Realized (loss) on sale of assets/commodity contracts	(4.4)		(0.8)		(7.5)
Realized gains on sale of assets/commodity contracts	(10.6)		(4.4)		(0.8)
Unrealized loss (gain) on investments/commodity contracts	(1.8)		(1.9)		1.8
Unrealized gains on investments/commodity contracts	(2.1)		(1.8)		(1.9)
Employee benefits and compensation	—		~~0.3~~—		(10.1)3
Share-based compensation	8.45		78.64		67.46
Other, net	(0.2)7		(0.2)		—0.2
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(1037.31)		2(10.3)		~~(11.~~2).3
Propane inventory, storage gas and other inventory	3(0.36)		03.3		(70.8)3
Regulatory assets/liabilities, net	0(18.24)		200.12		~~(38~~20.6)1
Prepaid expenses and other current assets	0(1.4)		180.74		918.17
Accounts payable and other accrued liabilities	013.43		~~(16~~0.8)4		2(16.78)
Income taxes receivable	(2.9)		(1.3)		14.9
Income taxes receivable/payable	7.9		(2.9)		(1.3)
Customer deposits and refunds	(0.76)		3(0.97)		03.79
Accrued compensation	7(2.09)		17.50		(1.2)5
Accrued interest	(23.2)9		3(2.72)		—3.7
Other assets and liabilities, net	5(3.76)		(25.3)7		(2.83)
Net cash provided by operating activities	~~239~~233.47		~~203~~239.54		~~158~~203.95
Investing Activities
Property, plant and equipment expenditures	(~~355~~448.36)		(~~188~~355.63)		(~~128~~188.36)
Proceeds from sale of assets	512.29		25.92		32.9
Acquisitions, net of cash acquired	~~0.6~~—		~~(925.~~0).6		(11925.80)
Environmental expenditures	~~(0.4)~~—		(0.74)		(0.37)
Net cash used in investing activities	(~~349~~435.97)		(~~1,111~~349.49)		(~~136~~1,111.54)
Financing Activities
Common stock dividends	(5460.27)		(4054.02)		(3540.20)
Proceeds from issuance of common stock, net of expenses	72123.60		~~366~~72.46		4366.54
Tax withholding payments related to net settled stock compensation	(1.50)		(21.5)		(2.85)
Change in cash overdrafts due to outstanding checks	10.54		(01.3)5		1.(0.3)
Net borrowings (repayments) under line of credit agreements	14(39.14)		~~(22~~14.5)1		(2022.65)
Proceeds from issuance of long-term debt	99199.51		~~627~~99.05		49627.90
Repayment of long-term debt and finance lease obligation	(1825.5)		(2118.5)		(1821.05)
Net cash provided by (used in) financing activities	113.5		906.6		(21.2)
Net cash provided by financing activities	195.9		113.5		906.6
Net (Decrease) Increase in Cash and Cash Equivalents	3(6.01)		~~(1.~~3).0		(1.23)
Cash and Cash Equivalents — Beginning of Period	47.9		64.29		56.02
Cash and Cash Equivalents — End of Period	$	71.98	$	47.9	$	64.29

See Note 7 for Supplemental Cash Flow Disclosures.

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6162

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Stockholders' Equity

	Common Stock (1)
(dollars in millions, shares in thousands (except per share data))	NumberofShares (2)	ParValue		AdditionalPaid-InCapital		RetainedEarnings		~~AccumulatedOtherComprehensiveIncome (Loss)~~AccumulatedOtherComprehensiveLoss		DeferredCompensation		TreasuryStock		Total
Balance at December 31, 2021	17,655	$	8.6	$	371.2	$	393.1	$	1.3	$	7.2	$	(7.2)	$	774.2
Balance at December 31, 2022	17,741	$	8.6	$	380.0	$	445.5	$	(1.4)	$	7.1	$	(7.1)	$	832.7
Net Income	—	—		—		89.8		—		—		—		89.8
Other comprehensive income (loss)	—	—		—		—		(2.7)		—		—		(2.7)
Dividends declared ($2.085 per share)	—	—		—		(37.4)		—		—		—		(37.4)
Issuance under various plans (5)	39	—		5.3		—		—		—		—		5.3
Share-based compensation and tax benefit (3) (4)	47	—		3.5		—		—		—		—		3.5
Treasury stock activities (2)	—	—		—		—		—		(0.1)		0.1		—
Balance at December 31, 2022	17,741	8.6		380.0		445.5		(1.4)		7.1		(7.1)		832.7
Net Income	—	—		—		87.2		—		—		—		87.2
Issuance of common stock in connection with acquisition of FCG	4,439	2.2		364.3		—		—		—		—		366.5
Other comprehensive income (loss)	—	—		—		—		(1.4)		—		—		(1.4)
Dividends declared ($2.305 per share)	—	—		—		(44.0)		—		—		—		(44.0)
Share-based compensation and tax benefit (3) (4)	55	—		5.1		—		—		—		—		5.1
Treasury stock activities (2)	—	—		—		—		—		2.0		(2.0)		—
Balances at December 31, 2023	22,235	10.8		749.4		488.7		(2.8)		9.1		(9.1)		1,246.1
Balance at December 31, 2023	22,235	10.8		749.4		488.7		(2.8)		9.1		(9.1)		1,246.1
Net Income	—	—		—		118.6		—		—		—		118.6
Other comprehensive income (loss)	—	—		—		—		1.1		—		—		1.1
Dividends declared ($2.510 per share)	—	—		—		(57.0)		—		—		—		(57.0)
Issuance under various plans (5)	627	0.3		74.2		—		—		—		—		74.5
Share-based compensation and tax benefit (3) (4)	37	—		6.9		—		—		—		—		6.9
Treasury stock activities (2)	—	—		—		—		—		0.7		(0.7)		—
Balances at December 31, 2024	22,899	$11.1	~~11.1~~	$830.5	~~830.5~~	$550.3	~~550.3~~	$(1.7)	~~(1.7)~~	$9.8	~~9.8~~	$(9.8)	~~(9.8)~~	$1,390.2	~~1,390.2~~
Net Income	—	—		—		140.3		—		—		—		140.3
Other comprehensive income (loss)	—	—		—		—		(1.0)		—		—		(1.0)
Dividends declared ($2.695 per share)	—	—		—		(63.8)		—		—		—		(63.8)
Issuance under various plans (5)	961	0.5		123.0		—		—		—		—		123.5
Share-based compensation and tax benefit (3) (4)	36	—		9.3		—		—		—		—		9.3
Treasury stock activities (2)	—	—		—		—		—		2.8		(2.8)		—
Balances at December 31, 2025	23,896	$	11.6	$	962.8	$	626.8	$	(2.7)	$	12.6	$	(12.6)	$	1,598.5

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

(2) Includes ~~114~~129 thousand, ~~108~~114 thousand and 108 thousand shares at December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

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

(4) The shares issued under the SICP are net of shares withheld for employee taxes. For ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we withheld 148 thousand, 2014 thousand and 2220 thousand shares, respectively, for taxes.

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

The accompanying notes are an integral part of the financial statements.

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6263

Table of Contents

Notes to the Consolidated Financial Statements

1. ORGANIZATION AND BASIS OF PRESENTATION

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

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

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

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

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property within the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, ~~2024~~2025 and ~~2023~~2024 is provided in the following table:

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6364

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Notes to the Consolidated Financial Statements

	As of December 31,
(in millions)	~~2024~~2025		~~2023~~2024
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	1,~~679~~828.32	$	1,~~486~~679.83
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	~~819~~927.59		~~788~~819.25
Electric distribution	~~163~~185.04		~~143~~163.50
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	201.6		194.9
Propane operations – Mid-Atlantic, Virginia, North Carolina, South Carolina and Florida	208.1		201.6
Natural gas transmission and supply – Ohio	~~139~~147.26		~~134~~139.2
Electricity and steam generation	37.4		37.14
Mobile CNG and pipeline solutions	5264.8		4052.68
Sustainable energy investments, including renewable natural gas related investments	3234.76		432.07
Other	2938.93		3029.39
Total property, plant and equipment	3,~~155~~472.43		23,~~859~~155.64
Less: Accumulated depreciation and amortization	(~~567~~637.6)		(~~516~~567.46)
Plus: Construction work in progress	~~148~~283.17		~~113~~148.21
Net property, plant and equipment	$	23,~~735~~118.94	$	2,~~456~~735.49

Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, ~~2024~~2025 and ~~2023~~2024, the non-refundable contributions totaled $57.98 million and $45.29 million, respectively.

AFUDC

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. ~~During~~For the ~~year~~years ended December 31, ~~2024~~2025, ~~AFUDC~~2024 ~~was $1.4 million~~ and ~~was reflected as a reduction of interest expense. For the years ended December 31,~~ 2023 ~~and 2022~~, AFUDC was not material.

Leases

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

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

WeChesapeake ~~have~~Utilities ~~lease~~Corporation ~~agreements~~2025 ~~with~~Form ~~lease and non~~10-~~lease~~K ~~components.~~Page At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 14, Leases, for additional information.65

Chesapeake Utilities Corporation 2024 Form 10-K Page 64

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Notes to the Consolidated Financial Statements

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

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, ~~2024~~2025, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $23.85 million and $2.28 million at December 31, ~~2024~~2025 and ~~2023~~2024, respectively.

Impairment of Long-lived Assets

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

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023, we reported $15.89 million, $1115.98 million and $11.09 million, respectively, of depreciation and accretion in operations expenses.

The following table shows the average depreciation rates used for regulated operations during the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023:

	2024	2023	2022
	2025	2024	2023
Natural gas distribution – Delmarva Peninsula (1)	2.1.7%	2.51%	2.5%
Natural gas distribution – Florida (2) (3)	2.7%	2.27%	2.52%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.43%	2.4%	2.4%
Natural gas transmission – Ohio (4)	2.35%	52.03%	5.0%
Electric distribution	2.49%	2.4%	2.84%

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

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

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

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

Chesapeake Utilities Corporation 2025 Form 10-K Page 66

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Notes to the Consolidated Financial Statements

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


Asset Description			Useful Life
Propane distribution mains			10-37 years
Propane bulk plants and tanks			10-40 years
Propane equipment, meters and meter installations			5-33 years
Measuring and regulating station equipment			5-37 years
Natural gas pipelines			45 years
Natural gas right of ways			Perpetual
CHP plant			30 years
Natural gas processing equipment			20-25 years
Office furniture and equipment			3-10 years
Transportation equipment			4-20 years
Structures and improvements			5-45 years
Other			Various

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6567

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Notes to the Consolidated Financial Statements

Regulated Operations

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

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

Revenue Recognition

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

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

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

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

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

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

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

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

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

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

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6668

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Notes to the Consolidated Financial Statements

Natural Gas, Electric and Propane Costs

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

Operations and Maintenance Expenses

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

Cash and Cash Equivalents

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

Accounts Receivable and Allowance for Credit Losses

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

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

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

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

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6769

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Notes to the Consolidated Financial Statements

The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, ~~2024~~2025:

(in millions)
Balance at December 31, 2023	$	2.7
Balance at December 31, 2024	$	3.3
Additions:
Provision for credit losses	23.15
Recoveries	0.42
Deductions:
Write offs	(1.96)
Balance at December 31, 2024	$	3.3
Balance at December 31, 2025	$	5.4

Inventories

We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, ~~2024~~2025, ~~2023~~2024 or ~~2022~~2023.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. There were no goodwill impairments recognized during the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

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

Asset Removal Cost

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

See Note 1817, Rates and Other Regulatory Activities, for information related to FCG's ~~reserve surplus amortization mechanism ("~~RSAM") that was approved as part of its rate case effective as of May 1, 2023.

Pension and Other Postretirement Plans

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

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

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6870

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Notes to the Consolidated Financial Statements

bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.

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

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

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

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

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

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

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

Financial Instruments

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

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

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

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 6971

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Notes to the Consolidated Financial Statements

Recently Adopted Accounting Standards

FASB

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

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

Recent Accounting Standards Yet to be Adopted

FASB

Income ~~Taxes~~Statement Expense Disaggregation (ASC ~~740~~220) - In ~~December~~November ~~2023~~2024, the FASB issued ASU ~~2023~~2024-0903, ~~Improvements~~Disaggregation toof Income ~~Tax~~Statement ~~Disclosures~~Expenses, which ~~modifies~~requires ~~required~~disclosure ~~income~~in ~~tax~~the ~~disclosures~~notes ~~primarily related~~ to anfinancial ~~entity's~~statements ~~rate~~of ~~reconciliation~~specified ~~and~~ information ~~pertaining~~about tocertain ~~income~~costs ~~taxes~~and ~~paid~~expenses. ~~These~~ASU ~~enhancements~~2024-03 ~~have~~will ~~been~~be ~~made~~effective tofor ~~address~~our ~~requests~~annual ~~from~~financial ~~investors~~statements ~~related~~beginning toJanuary ~~transparency~~1, 2027 and ~~usefulness of income tax disclosures. ASU 2023-09 will be effective for~~ our ~~annual~~interim financial statements beginning January 1, ~~2025~~2028. ASU ~~2023~~2024-0904 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.

~~Income~~Internal-Use ~~Statement~~Software ~~Expense Disaggregation~~ (ASC ~~220~~350) - In ~~November~~September ~~2024~~2025, the FASB issued ASU ~~2024~~2025-0406, ~~Disaggregation~~Targeted ofImprovements ~~Income~~to ~~Statement~~the ~~Expenses~~Accounting for Internal-Use Software. This update, ~~which~~among ~~require~~other ~~disclosure~~changes, eliminates the project stages used in the ~~notes~~historical toguidance ~~financial~~and ~~statements~~instead, offocuses ~~specified~~on ~~information~~a ~~about~~principles-based ~~certain~~approach ~~costs~~that utilizes management's commitment to the project and ~~expenses~~the probability of project completion. ASU ~~2024~~2025-0406 will be effective for our ~~annual~~interim ~~financial statements beginning January 1, 2027~~ and ~~our~~annual ~~interim~~ financial statements beginning January 1, 2028. ~~ASU~~We ~~2024-04~~do ~~only~~not ~~impacts~~expect ~~disclosures,~~ASU ~~and~~2025-06 asto ~~a result, will not~~ have ana material impact on our financial position or results of ~~operations~~operation.

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

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

SEC

Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks, and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed ~~and~~that sought review of the final ruling in multiple courts of appeals. AtIn ~~this~~March ~~time~~2025, itthe isSEC ~~uncertain~~withdrew asits todefense ~~when~~of the ~~review~~final ~~will~~rule. beWe ~~completed,~~will ~~the~~continue ~~final~~to ~~outcome~~monitor ofany ~~the~~further ~~review,~~developments ~~and~~related to the ~~timing~~stay ofand ~~required~~review ~~disclosure~~process.

3.Federal ~~EARNINGS~~Statute ~~PER SHARE~~Updates

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

	For the Year Ended December 31,
	2024		2023		2022
(dollars in millions, shares in thousands (except per share data))
Calculation of Basic Earnings Per Share:
Net Income	$	118.6	$	87.2	$	89.8
Weighted average shares outstanding (1)	22,469		18,371		17,722
Basic Earnings Per Share	$	5.28	$	4.75	$	5.07
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic (1)	22,469		18,371		17,722
Effect of dilutive securities — Share-based compensation	62		64		82
Adjusted denominator — Diluted (1)	22,531		18,435		17,804
Diluted Earnings Per Share	$	5.26	$	4.73	$	5.04

Chesapeake Utilities Corporation 2025 Form 10-K Page 72

(1) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.

Chesapeake Utilities Corporation 2024 Form 10-K Page 70

Table of Contents

Notes to the Consolidated Financial Statements

3. EARNINGS PER SHARE

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


	For the Year Ended December 31,
	2025		2024		2023
(dollars in millions, shares in thousands (except per share data))
Calculation of Basic Earnings Per Share:


Net Income	$	140.3	$	118.6	$	87.2
Weighted average shares outstanding (1)	23,389		22,469		18,371


Basic Earnings Per Share	$	6.00	$	5.28	$	4.75

Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic (1)	23,389		22,469		18,371
Effect of dilutive securities — Share-based compensation	99		62		64
Adjusted denominator — Diluted (1)	23,488		22,531		18,435


Diluted Earnings Per Share	$	5.97	$	5.26	$	4.73

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

4. ACQUISITIONS

Acquisition of Florida City Gas

~~FCG~~The ~~serves~~purchase ~~approximately~~price ~~123,000~~of ~~residential~~the ~~and~~acquisition ~~commercial~~was ~~natural~~funded ~~gas~~with ~~customers~~$366.4 million ~~across~~of ~~eight~~net ~~counties~~proceeds infrom ~~Florida,~~the ~~including~~issuance ~~Miami-Dade,~~of ~~Broward,~~4.4 million ~~Brevard,~~shares ~~Palm~~of ~~Beach,~~our ~~Hendry,~~common ~~Martin~~stock, Stthe issuance of approximately $550.0 million ~~Lucie~~principal amount of uncollateralized senior notes, and ~~Indian~~borrowings ~~River.~~under ~~Its~~the ~~natural~~Company's ~~gas~~Revolver. ~~system~~See ~~includes~~Note ~~approximately~~12, 3Long-Term Debt,~~982~~ ~~miles~~and ofNote ~~distribution~~14, ~~mains~~Stockholders' ~~and~~Equity, 80for ~~miles~~additional ofdetails ~~transmission~~on ~~pipe~~these financing activities.

The excess of the purchase price for FCG over the fair value of the ~~acquisition~~assets acquired and liabilities assumed was ~~funded~~reflected ~~with~~as ~~$366.4 million~~goodwill ofwithin ~~net~~the ~~proceeds~~Regulated Energy segment. Goodwill resulting from the ~~issuance~~acquisition ofwas ~~4.4 million~~largely ~~shares~~attributable ofto expansion opportunities provided within our ~~common~~existing ~~stock~~regulated operations in Florida, ~~the~~including ~~issuance~~planned ofcustomer ~~approximately~~growth ~~$550.0 million~~and ~~principal~~growth ~~amount~~in ofrate ~~uncollateralized~~base ~~senior~~through ~~notes~~continued investment in our utility infrastructure, ~~and~~as ~~borrowings~~well ~~under~~as natural gas transmission infrastructure supporting the ~~Company's~~distribution ~~Revolver~~operations. ~~See~~The ~~Note~~goodwill ~~12,~~recognized ~~Long-Term~~in ~~Debt,~~connection ~~and~~with ~~Note~~the ~~15,~~acquisition ~~Stockholders'~~of ~~Equity,~~FCG ~~for~~is ~~additional~~deductible ~~details~~for onincome ~~these~~tax ~~financing activities~~purposes.

~~The~~Chesapeake ~~excess~~Utilities ofCorporation ~~the~~2025 ~~purchase~~Form ~~price~~10-K ~~for~~Page FCG over the fair value of the assets acquired and liabilities assumed was reflected as goodwill within the Regulated Energy segment. Goodwill resulting from the acquisition is largely attributable to expansion opportunities provided within our existing regulated operations in Florida, including planned customer growth and growth in rate base through continued investment in our utility infrastructure, as well as natural gas transmission infrastructure supporting the distribution operations. The goodwill recognized in connection with the acquisition of FCG is deductible for income tax purposes.73

Table of Contents

Notes to the Consolidated Financial Statements

The components of the purchase price allocation are as follows:


(in millions)
Assets acquired:	Acquisition Date Fair Value
Cash	$	2.3
Accounts receivable, net	14.1
Regulatory assets - current	3.0
Other current assets	2.0
Property, plant and equipment	454.4
Goodwill	460.9
Regulatory assets - non-current	3.4
Other deferred charges and other assets	18.3
Total assets acquired	958.4

Liabilities assumed:
Current liabilities	(20.9)
Regulatory liabilities	(14.1)
Other deferred credits and other liabilities	(0.6)
Total liabilities assumed	(35.6)

Net purchase price	$	922.8

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

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

Chesapeake Utilities Corporation 2024 Form 10-K Page 71

Table of Contents

Notes to the Consolidated Financial Statements

the period from the acquisition date through December 31, 2023, the Company’s consolidated results include $12.1 million of operating revenue and a $3.3 million net loss attributable to FCG which includes $7.5 million of the transaction and transition-related expenses described above.

Acquisition of J.T. Lee and Son's

In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $3.9 million. In connection with this acquisition, we recorded a $0.3 million liability which was subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Upon the expiration of the first anniversary of the transaction, this liability was settled. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Diversified Energy. Sharp added approximately 3,000 customers and distribution of approximately 800,000 gallons of propane annually. The transaction also includes a bulk plant with 60,000 gallons of propane storage, enabling the Company to realize efficiencies with additional storage capacity and overlapping delivery territories.

In connection with this acquisition, we recorded $2.7 million in property plant and equipment, $0.9 million in goodwill, $0.2 million in working capital, and less than $0.1 million in intangible assets associated primarily with non-compete agreements, all of which are deductible for income tax purposes. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the years ended December 31, 2024 and 2023.

5. 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 revenue by major source based on product and service type for the years ended December 31, ~~2024~~2025, ~~2023~~2024 and ~~2022~~2023:

Chesapeake Utilities Corporation ~~2024~~2025 Form 10-K Page 7274

Table of Contents

Notes to the Consolidated Financial Statements

	For the Year Ended December 31, 2024
	For the Year Ended December 31, 2025
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	76103.95	$	—	$	—	$	76103.95
Florida Natural Gas distribution	170.3		—		—		170.3
FPU natural gas distribution	191.8		—		—		191.8
Florida City Gas	140.3		—		—		140.3
FCG	170.4		—		—		170.4
FPU electric distribution	92103.69		—		—		92103.69
Maryland natural gas division	24.6		—		—		24.6
Maryland natural gas distribution (1)	64.2		—		—		64.2
Sandpiper natural gas/propane operations	20.0		—		—		20.0
Total energy distribution	633.8		—		—		633.8
Elkton Gas	7.3		—		—		7.3
Total energy distribution	532.0		—		—		532.0
Energy transmission
Aspire Energy	—		3550.24		—		3550.24
Aspire Energy Express	1.5		—		—		1.5
Eastern Shore	8186.79		—		—		8186.79
Peninsula Pipeline	3452.58		—		—		3452.58
Total energy transmission	~~117~~141.72		3550.24		—		~~152~~191.96
Energy generation
Eight Flags	—		18.01		—		18.01
Propane operations
Propane distribution operations	—		~~157~~171.96		—		~~157~~171.96
CNG / RNG
Marlin Gas Services	—		1628.62		—		1628.62
Other RNG	—		13.08		—		13.08
Total CNG / RNG Services	—		1732.60		—		1732.60
Other and eliminations
Eliminations	(6687.32)		(0.32)		(2429.89)		(91117.43)
Other	—		—		0.2		0.2
Total other and eliminations	(6687.32)		(0.32)		(2429.67)		(91117.21)
Total operating revenues (1)	$	583.4	$	228.4	$	(24.6)	$	787.2
Total operating revenues (2)	$	687.8	$	271.9	$	(29.7)	$	930.0

(1) ~~Total~~In ~~operating~~accordance ~~revenues~~with ~~for~~ the ~~year~~Maryland ~~ended~~PSC ~~December 31,~~approval ~~2024~~of our natural gas base rate proceeding, ~~include~~effective ~~other~~April ~~revenue~~2025, ~~(revenues~~our ~~from~~natural ~~sources~~gas ~~other~~distribution ~~than~~businesses ~~contracts~~in ~~with~~Maryland ~~customers)~~(Maryland ofnatural ~~$1.6~~gas ~~million~~division, Sandpiper Energy and ~~$0.4~~Elkton ~~million~~Gas) ~~for~~are ~~our~~now ~~Regulated~~consolidated for rate-making and ~~Unregulated~~other ~~Energy~~purposes ~~segments,~~and ~~respectively.~~are ~~The~~reflected ~~sources~~on ofa ~~other~~consolidated ~~revenues~~basis ~~include~~for ~~revenue~~all ~~from~~periods ~~alternative~~presented ~~revenue~~consistent ~~programs~~with ~~related~~the tofinal ~~revenue~~rate ~~normalization~~order. ~~for~~See ~~Maryland~~Note ~~division~~17, Rates and ~~Sandpiper~~Other ~~and~~Regulatory ~~late~~Activities, ~~fees~~for additional information.

~~Chesapeake~~(2) ~~Utilities~~Total ~~Corporation~~operating ~~2024~~revenues ~~Form~~for ~~10-K~~the ~~Page~~year 73ended December 31, 2025, include other revenue (revenues from sources other than contracts with customers) of $0.8 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization and late fees for the Maryland natural gas distribution businesses.

Chesapeake Utilities Corporation 2025 Form 10-K Page 75

Table of Contents

Notes to the Consolidated Financial Statements

	For the Year Ended December 31, 2023
	For the Year Ended December 31, 2024
(in millions)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	8376.9	$	—	$	—	$	8376.9
Florida Natural Gas distribution	168.4		—		—		168.4
FPU natural gas distribution	170.3		—		—		170.3
Florida City Gas (1)	12.1		—		—		12.1
FCG	140.3		—		—		140.3
FPU electric distribution	9992.56		—		—		9992.56
Maryland natural gas division	28.1		—		—		28.1
Maryland natural gas distribution (1)	51.9		—		—		51.9
Sandpiper natural gas/propane operations	20.2<

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