10-K

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, 2023

☐ 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, 2023, 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 $2.1 billion.

The number of shares of Chesapeake Utilities Corporation's common stock outstanding as of February 16, 2024 was 22,238,384

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2024 Annual Meeting of Shareholders are incorporated by reference in Part II and Part III hereof.

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2023

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	3
Item 1A. Risk Factors	16
Item 1B. Unresolved Staff Comments	24
Item 1C. Cybersecurity	24
Item 2. Properties	26
Item 3. Legal Proceedings	27
Item 4. Mine Safety Disclosures	27
Part II	27
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	27
Item 6. Reserved	30
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	53
Item 8. Financial Statements and Supplementary Data	55
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
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

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification issued by the FASB

Adjusted Gross Margin: a non-GAAP measure calculated by deducting the purchased cost of natural gas, propane and electricity and the cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Adjusted Gross Margin exclude depreciation and amortization and certain costs presented in operations and maintenance expenses in accordance with regulatory requirements

Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities

Aspire Energy Express: Aspire Energy Express, LLC, a wholly-owned subsidiary of Chesapeake Utilities

ASU: Accounting Standards Update issued by the FASB

ATM: At-the-market

CDC: U.S. Centers for Disease Control and Prevention

CDD: Cooling Degree-Day

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

Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, its divisions and subsidiaries, as appropriate in the context of the disclosure

CHP: Combined Heat and Power Plant

Company: Chesapeake Utilities Corporation, its divisions and subsidiaries, as appropriate in the context of the disclosure

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: an 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

ESG: Environmental, Social and Governance

FASB: Financial Accounting Standards Board

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

FERC: Federal Energy Regulatory Commission

FGT: Florida Gas Transmission Company

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

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

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

GAAP: Generally Accepted Accounting Principles

GRIP: Gas Reliability Infrastructure Program

Gross Margin: a term under U.S. GAAP which is the excess of sales over costs of goods sold

GUARD: Gas Utility Access and Replacement Directive, a program to enhance the safety, reliability and accessibility of portions of the Company’s natural gas distribution system in Florida

Guernsey Power Station: Guernsey Power Station, LLC, a power generation facility in Guernsey County Ohio

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

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 $375.0 million unsecured revolving credit facility with certain lenders

RNG: Renewable natural gas

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

SAFE: Safety, Access, and Facility Enhancement, a program to enhance the safety, reliability and accessibility of portions of the FCG’s natural gas distribution system

SEC: Securities and Exchange Commission

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

Shelf Notes: Unsecured senior promissory notes issuable under the Shelf Agreement executed with various counterparties

SICP: Stock and Incentive Compensation Plan, which as used herein covers stock-based compensation awards issued under the current 2023 plan and the previous 2013 plan

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

Transco: Transcontinental Gas Pipe Line Company, LLC

U.S.: The United States of America

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 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;

•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 responsible use of our technologies, including artificial intelligence;

•adverse weather conditions, including the effects of hurricanes, ice storms and other damaging weather events;

•customers' preferred energy sources;

•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 financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

•the ability to successfully execute, manage and integrate a merger, acquisition or divestiture of assets or businesses and the related regulatory or other conditions associated with the merger, acquisition or divestiture;

•the impact on our costs and funding obligations, under our pension and other 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;

Chesapeake Utilities Corporation 2023 Form 10-K Page 1

•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 2023 Form 10-K     Page 2

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 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 provide opportunities for returns greater than traditional utility returns. We seek to identify and develop opportunities across the energy value chain, with emphasis on midstream and downstream investments that are accretive to earnings per share, consistent with our long-term growth strategy and create opportunities to continue our record of higher-than-authorized regulated returns. 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. By investing in these related businesses and services, the Company creates opportunities to sustain its track record of higher returns, as compared to a traditional utility.

Currently, the Company’s growth strategy is focused on the following platforms, including:

•Optimizing the earnings growth in our existing businesses, which includes organic growth, strategic and complimentary acquisitions, territory expansions, and new products and services as well as increased opportunities to transform the Company with a focus on people, process, technology and organizational structure.

•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.

•Pursuit of growth opportunities that enable us to utilize our integrated set of energy delivery businesses to participate in sustainable energy investments.

Operating Segments

We conduct operations within two reportable segments: Regulated Energy and Unregulated Energy. The remainder of our operations is presented as "Other businesses and eliminations." 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 $923.4 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 serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe. Results for FCG are included within our consolidated results from the acquisition date.

The following table presents net income for the year ended December 31, 2023 and total assets as of December 31, 2023, by operation and area served:

Chesapeake Utilities Corporation 2023 Form 10-K Page 3

Operations	Areas Served	Net Income (Loss)		Total Assets
(in thousands)
Natural Gas Distribution
Delmarva Natural Gas (1)	Delaware/Maryland	$	9,256	$	407,089
Florida Natural Gas (2)	Florida	23,840		545,952
Florida City Gas (3)	Florida	(3,256)		1,010,998
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	23,284		480,147
Peninsula Pipeline	Florida	12,195		154,301
Aspire Energy Express	Ohio	417		6,746
Electric Distribution
FPU	Florida	3,727		176,348
Total Regulated Energy		$	69,463	$	2,781,581

(1) Delmarva Natural Gas consists of Delaware division, Maryland division, Sandpiper Energy and Elkton Gas.

(2) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution business in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts are now being presented on a consolidated basis consistent with the final rate order.

(3) FCG net income (loss) includes results from the acquisition date, including transaction-related expenses attributable to the acquisition. For additional information on FCG's results, see discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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 Natural Gas 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.

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, 2023:

Chesapeake Utilities Corporation 2023 Form 10-K     Page 4

	Delmarva Natural Gas Distribution				Florida Natural Gas Distribution (1)				Florida City Gas Distribution (2)				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	87,709	62	%	$	50,792	30	%	$	5,042	42	%	$	49,542	50	%
Commercial and Industrial	54,261		38	%	108,913		65	%	5,872		49	%	52,047		52	%
Other (3)	(997)		<(1)%		8,655		5	%	1,159		9	%	(2,115)		(2)	%
Total Operating Revenues	$	140,973	100	%	$	168,360	100	%	$	12,073	100	%	$	99,474	100	%
Volumes (in Dts for natural gas/MW Hours for electric)
Residential	4,389,934		29	%	2,081,045		5	%	157,884		10	%	300,118		44	%
Commercial and Industrial	10,230,662		69	%	41,498,921		94	%	940,028		57	%	384,306		56	%
Other	293,186		2	%	627,934		1	%	549,132		33	%	—		—	%
Total Volumes	14,913,782		100	%	44,207,900		100	%	1,647,044		100	%	684,424		100	%
Average Number of Customers (4)
Residential	97,666		92	%	88,384		91	%	112,585		93%		25,719		78	%
Commercial and Industrial	8,246		8	%	8,415		9	%	8,587		7%		7,372		22	%
Other	23		<1%		6		<1%		6		<1%		—		—	%
Total Average Number of Customers	105,935		100	%	96,805		100	%	121,178		100	%	33,091		100	%

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution business in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts are now being presented on a consolidated basis consistent with the final rate order.

(2) Operating revenues and volumes for FCG include amounts from the acquisition date. Customer totals for FCG reflect actual amounts at December 31, 2023 since the period from the acquisition covered only one month. For additional information on FCG's results, see discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

(3) 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.

(4) Average number of customers is based on the twelve-month average for the year ended December 31, 2023.

The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, 2023, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, 2023. 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, 2023:

	Eastern Shore				Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated (1)	$	34,050	43	%	$	24,324	80	%
Local distribution companies - non-affiliated	22,163		28	%	2,449		8	%
Commercial and industrial - affiliated	—		—	%	1,651		5	%
Commercial and industrial - non-affiliated	23,439		29	%	534		2	%
Other (2)	271		<1%		1,442		5	%
Total Operating Revenues	$	79,923	100	%	$	30,400	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	160,595		51	%	351,976		39	%
Local distribution companies - non-affiliated	56,576		18	%	534,825		59	%
Commercial and industrial - affiliated	—		—	%	8,300		1	%
Commercial and industrial - non-affiliated	98,540		31	%	5,100		1	%
Total Contracted firm transportation capacity	315,711		100	%	900,201		100	%
Design day capacity (in Dts/d)	315,711		100	%	900,201		100	%

(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 are from the rental of gas properties.

Chesapeake Utilities Corporation 2023 Form 10-K Page 5

Regulatory Overview

The following table highlights key regulatory information for each of our principal Regulated Energy operations. Peninsula Pipeline and Aspire Energy Express are not regulated with regard to cost of service by either the Florida PSC or Ohio PUC respectively, or the FERC and are therefore excluded from the table. See Item 8, Financial Statements and Supplementary Data (Note 18, 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		Electric Distribution	Natural Gas Transmission
Operation/Division	Delaware	Maryland (1)	Sandpiper (1)	Elkton Gas (1) (2)	Florida Natural Gas	Florida City Gas	FPU	Eastern Shore
Regulatory Agency	Delaware PSC	Maryland PSC			Florida PSC			FERC
Effective date - Last Rate Order	01/01/2017	12/1/2007	12/01/2019	02/07/2019	3/1/23	6/9/23	10/8/2020	08/01/2017
Rate Base (in Rates) (in Millions)	Not stated	Not stated	Not stated	Not stated	$453.7	$487.3	$24.9	Not stated
Annual Rate Increase Approved (in Millions)	$2.3	$0.6	N/A(3)	$0.1	$17.2	$14.1	$3.4 base rate and $7.7 from storm surcharge	$9.8
Capital Structure (in rates) (4)*	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
Allowed Return on Equity (5)	9.75%	10.75%	Not stated (6)	9.80%	10.25%	9.50%	10.25% (7)	Not stated
TJCA Refund Status associated with customer rates	Refunded	Refunded	Refunded	N/A	Retained	Refunded	Refunded	Refunded

(1) 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. The outcome of the application is subject to review and approval by the Maryland PSC.

(2) The rate increase and allowed return on equity for Elkton Gas were approved by the Maryland PSC before we acquired the company.

(3) The Maryland PSC approved a declining return on equity.

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

(5) Allowed after-tax return on equity.

(6) 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.

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

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 6

In May 2022, our legacy natural gas distribution businesses filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 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 rate structure across the businesses and to unify the Florida natural gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (v) 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. The discovery process and subsequent hearings were concluded during the fourth quarter of 2022 and briefs were submitted in the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023.

In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed reserve surplus amortization mechanism ("RSAM") with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. On June 23, 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied on September 12, 2023. On July 7, 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending.

The following table presents surcharge and other mechanisms that have been approved by the respective PSC for our regulated energy distribution businesses. 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 GRIP 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 storm-related costs.

Operation(s)/Division(s)	Jurisdiction	Infrastructure mechanism	Revenue normalization
Delaware division	Delaware	Yes	No
Maryland division	Maryland	No	Yes
Sandpiper Energy	Maryland	Yes	Yes
Elkton Gas	Maryland	Yes	Yes
Florida Natural Gas	Florida	Yes	No
Florida City Gas (1)	Florida	Yes	No
FPU electric division	Florida	Yes	No

(1) See Item 8, Financial Statements and Supplementary Data, Note 18, 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 heating degree-day, and each degree of temperature above 65 degrees Fahrenheit is counted as one cooling degree-day. Normal heating and cooling degree-days are based on the most recent 10-year average.

Chesapeake Utilities Corporation 2023 Form 10-K Page 7

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.

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.

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 1, 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 Natural Gas distribution business uses Peninsula Pipeline and Peoples Gas 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.

A summary of our pipeline capacity contracts follows:

Chesapeake Utilities Corporation 2023 Form 10-K     Page 8

		Maximum Daily Firm Transportation Capacity (Dts)	Contract Expiration Date
Division	Pipeline
Delmarva Natural Gas Distribution	Eastern Shore	160,595	2024-2035
	Columbia Gas (1)	5,246	2024-2026
	Transco (1)	30,419	2024-2028
	TETLP (1)	50,000	2027
Florida Natural Gas	Gulfstream (2)	10,000	2032
	FGT	47,409 - 78,817	2025-2041
	Peninsula Pipeline	346,200	2033-2048
	Peoples Gas	12,160	2024
	Florida Southeast Connection LLC	5,000	2044
	Southern Natural Gas Company	1,500	2029
Florida City Gas	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, entered into a precedent agreement to provide natural gas transportation capacity to Guernsey Power Station, who completed construction of its power generation facility in Guernsey County, Ohio in January 2023. 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. 

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	Gulf Power Company	Full Requirement*	2026
Northeast Florida	Florida Power & Light Company	Full Requirement*	2026
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 2023 Form 10-K Page 9

Unregulated Energy

Overview

The following table presents net income for the year ended December 31, 2023 and total assets as of December 31, 2023, for our Unregulated Energy segment by operation and area served:

Operations	Area Served	Net Income (Loss)		Total Assets
(in thousands)
Propane Operations (Sharp, Diversified Energy, FPU and Flo-gas)	Delaware, Maryland, Virginia, Pennsylvania, North Carolina, South Carolina, Florida	$	13,587	$	191,164
Energy Transmission (Aspire Energy)	Ohio	3,080		145,183
Energy Generation (Eight Flags)	Florida	2,235		37,805
Marlin Gas Services	The Entire U.S.	432		54,256
Sustainable investments and other (1)	Various	(1,697)		48,994
Total		$	17,637	$	477,402

(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.

Propane Operations - Operational Highlights

For the year ended December 31, 2023, operating revenues, volumes sold and average number of customers by customer class for our propane operations were as follows:

	Operating Revenues (in thousands)				Volumes (in thousands of gallons)			Average Number of Customers (1)
Residential bulk	$	46,913	30	%	15,187	21	%	59,483	70	%
Residential metered	13,931		9	%	4,457	6	%	17,387	21	%
Commercial bulk	37,541		24	%	21,242	30	%	7,703	9	%
Commercial metered	1,809		1	%	574	1	%	202	<1%
Wholesale	25,073		16	%	24,876	35	%	35	<1%
AutoGas	7,045		5	%	4,949	7	%	76	<1%
Other (2)	22,436		15	%	—	—	%	—	—	%
Total	$	154,748	100	%	71,285	100	%	84,886	100	%

(1) Average number of customers is based on a twelve-month average for the year ended December 31, 2023. Excludes customers from the propane acquisition that closed in December 2023. See Note 4 under Item 8, Financial Statements and Supplementary Data, for additional information on this acquisition.

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 10

Competition

Our propane operations compete with national and local independent companies primarily on the basis of price and service. Propane is generally a cheaper fuel for home heating than 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 8.9 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 22,000 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 October 2021, Aspire Energy completed construction of its Noble Road Landfill RNG pipeline project, which began transporting RNG generated from the landfill to Aspire Energy’s pipeline system in January of 2022, displacing conventionally produced natural gas. In 2023, the RNG volumes represented approximately 10 percent of Aspire Energy’s gas gathering volumes and are anticipated to continue at such rate in 2024 and beyond. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

For the twelve-month period ended December 31, 2023, Aspire Energy's operating revenues and deliveries by customer type were as follows:

	Operating revenues				Deliveries
	(in thousands)		% of Total		(in thousands Dts)	% of Total
Supply to Columbia Gas of Ohio	$	11,694	32	%	2,351	31	%
Supply to CGC	16,844		45	%	2,025	27	%
Supply to Marketers	6,287		17	%	3,141	41	%
Other (including natural gas gathering and processing)	2,314		6	%	64	1	%
Total	$	37,139	100	%	7,581	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 Natural 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 and virtual pipeline solutions, primarily to utilities and pipelines. 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 safely perform these 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

Chesapeake Utilities Corporation 2023 Form 10-K Page 11

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.

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 are constructing a dairy manure RNG facility that we will 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 $19.3 million through December 31, 2023. The first injection of RNG is projected to occur in the first half of 2024.

Environmental Matters

See Item 8, Financial Statements and Supplementary Data (see Note 19, Environmental Commitments and Contingencies, in the consolidated financial statements).

Human Capital Initiatives

Our success is the direct result of our employees and our strong culture that fully engages our team and promotes equity, diversity, inclusion, integrity, accountability and reliability. We believe that a combination of diverse team members and an inclusive culture contributes to the success of our Company and to enhanced societal advancement. Each employee is a valued member of our team bringing a diverse perspective to help grow our business and achieve our goals.

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 team, our culture of safety, and our commitment to supporting a more sustainable future.

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. 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.

Subsequent to the acquisition of FCG, we had a total of 1,281 employees at December 31, 2023, 196 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 legacy employees with these labor unions expire in 2025. Negotiations began in January 2024 with IBEW for those union employees that joined our Company as part of our acquisition of FCG. 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.

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. Our internal recognition

Chesapeake Utilities Corporation 2023 Form 10-K     Page 12

platform was unveiled in 2023 and enables employees to be recognized in real-time for their contributions. Our employees are the backbone of our continued growth and success.

We have an established an equity, diversity and inclusion ("EDI") Council which recommends and promotes our EDI strategy, advises our employee resource groups ("ERGs") and works with our operating units and support teams on EDI initiatives. The EDI Council’s charter includes the following objectives:

•Build a more diverse and inclusive workforce

•Promote a culture of understanding, equality and inclusion

•Educate employees about the benefits of diversity at Chesapeake Utilities

•Support community programs and organizations that are diverse and inclusive

•Provide guidance on EDI matters for the Company

The EDI Council includes members of our leadership team, the chairs of each of our ERGs and other individuals in key support roles. The CEO receives a regular report on the achievements of the EDI Council, strategic direction of initiatives, resource needs and issues that require policy decisions or other actions.

Our first ERG was established in 2019, and as of December 31, 2023, there were ten 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.

Workplace Health and Safety

We believe that there is nothing more important than the safety of our team, our customers and our communities. 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 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.

To maintain safety as a 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 short-term and long-term strategic initiative in managing our operations. Our state-of-the art training facility, Safety Town, located in Dover, Delaware, now serves as a resource 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. Construction is underway for our second Safety Town facility in Florida, and we are excited to begin utilizing this facility in 2024.

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 of Directors and its Committees, as well as the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, the Board of Directors is committed to overseeing the sustainability of the Company, its environmental stewardship initiatives, its safety and operational compliance practices, and to promoting equity, diversity and inclusion that reflects the diverse communities we serve. Our ESG Committee brings together a cross-functional team of leaders across the organization responsible for identifying, assessing, executing and advancing the Company's strategic sustainability initiatives. Our Environmental Sustainability Office identifies and manages emission-reducing projects both internally as well as those that support our customers' sustainability goals. Throughout the year, Chesapeake Utilities drove numerous initiatives in support of its sustainability focus, including but not limited to:

•Constructed an RNG injection point in Yulee, Florida, providing a pathway to market for produced RNG, and progressed on construction of our first RNG production facility in Lee, Florida;

Chesapeake Utilities Corporation 2023 Form 10-K Page 13

•Completed an expansion of our intrastate transmission pipeline to Vero Beach, Florida, increasing the availability of natural gas to the area;

•Served as an industry anchor partner in the Mid-Atlantic Clean Hydrogen Hub (MACH2TM), which was awarded federal funding of up to $750 million in October 2023; MACH2TM is a collaboration between Delaware, southern New Jersey and southeastern Pennsylvania;

•In Delaware, filed a first-of-its-kind energy efficiency program focused on natural gas; pending approval from the Delaware PSC, the program will be implemented in 2024;

•Our Florida Natural Gas distribution business received approval for its 10-year GUARD program to remove accessibility challenges and replace older problematic distribution lines and services, increasing employee, customer, and community safety; FCG received approval to extend its similar program, SAFE, for 10 more years;

•Provided Healthy Pantry Naming Sponsor-level support and donated several recycled benches from our Pipe Recycling Project for the new 70,000 square foot Food Bank of Delaware facility located in Milford, Delaware;

•Rolled out our “Chesapeake Connections Program,” connecting new team members with a “connection buddy” outside of their department for the first few months of employment;

•Introduced two new ERGs in 2023 – “PRIDE,” which is focused on providing a sense of acceptance and belonging for everyone in the Chesapeake Utilities family, and “GREEN,” which is passionate about the environment and committed to reducing societal impacts on the planet; and

•Named a 2023 Champion of Board Diversity by The Forum of Executive Women.

Information About 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	66	2010	Chairman 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	57	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	66	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	65	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	54	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;

Chesapeake Utilities Corporation 2023 Form 10-K     Page 14

•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.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 15

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 the section entitled 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.

Instability and volatility in the financial markets 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 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 access capital at competitive rates, 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, 2023, 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 depend 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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 16

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 recently 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.

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 market conditions could adversely impact the return on plan assets for our Company sponsored defined benefit plans, which may require significant additional funding.

The Company’s primary defined benefit pension plan, the FPU pension plan, is a funded plan that is closed to new employees and the future benefits are frozen. At December 31, 2023, the FPU pension plan benefit obligation was $49.4 million and was funded at approximately 100 percent. The costs of providing benefits and related funding requirements of the FPU plan is subject to changes in the market value of the assets that fund the plan and the discount rates used to estimate the pension benefit obligations. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of 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 minimum federal government requirements and may result in higher pension expense in future years. Adverse changes in the benefit obligation of the 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 operations, decrease borrowing capacity and increase interest expense.

OPERATIONAL RISKS

We are dependent upon construction of 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 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 or if such rights-of-way 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.

Chesapeake Utilities Corporation 2023 Form 10-K Page 17

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 (Maryland division, Sandpiper Energy and Elkton Gas) which have 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 results of operations, cash flows and financial condition. 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 results of operations, cash flows and financial condition. Variations in weather from year to year can cause our results of operations, cash flows and financial condition 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 may damage our assets, cause operational interruptions and result in the loss of human life, all of which could negatively affect our earnings, financial condition and results of operations.

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, natural disasters 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.

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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 18

A security breach disrupting our operating systems and facilities 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.

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 and financial condition. 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, results of operations, financial condition and cash flows.

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; and

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 19

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.

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.

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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 20

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, on August 16, 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 further 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 our stock price 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 results of operations, cash flows and financial condition.

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 net income 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.

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 results of operations, cash flows, and financial condition 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.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 21

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 120,000 residential and commercial natural gas customers in Florida, for $923.4 million in cash, pursuant to the previously disclosed 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 benefits and growth prospects 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.

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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 22

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 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 be 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 (see Note 19, 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.

Chesapeake Utilities Corporation 2023 Form 10-K Page 23

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 or financial results.

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 of Directors is authorized to issue preferred stock without stockholder approval on such terms as our Board 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.

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’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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 24

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 everchanging landscape.

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 follow frameworks established by the National Institute of Standards and Technology (NIST). 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 to ensure 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: We work to protect our business from cybersecurity threats through multi-layered defenses and apply lessons learned from our defense and monitoring efforts to help prevent future attacks. We utilize data analytics to detect anomalies and review trends in the data. We regularly assess and deploy technical safeguards designed to protect our information systems from cybersecurity threats. Such safeguards are regularly evaluated and enhanced based on vulnerability assessments, cybersecurity threat intelligence and incident response experience.

•Information Sharing and Collaboration: We share and receive threat intelligence and best practices with industry peers, government agencies, information sharing and analysis centers, industry trade organizations, and cybersecurity forums. These relationships enable the rapid sharing of information around threat and vulnerability mitigation.

•Third-Party Risk Assessments: We engage third-party services to conduct assessments of our security controls, whether through penetration testing, independent audits or consulting on best practices to address new challenges. These assessments include testing both the design and operational effectiveness of security controls.

•Companywide Policies and Procedures: We have companywide cybersecurity policies and procedures, such as encryption standards, antivirus protection, remote access protocols, multi-factor authentication, protection of confidential information, and the use of the internet, social media, email, and wireless devices. These policies go through an internal review process and are approved by the appropriate members of management.

•Training and Awareness: We provide awareness training to our employees to help identify, avoid and mitigate cybersecurity threats. Our employees routinely participate in phishing campaigns, education that reinforces compliance with our policies, standards and practices, and other awareness training. We also periodically perform simulations and other exercises with management and incorporate external resources and advisors as needed. Our team of cybersecurity professionals collaborate 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).

As of the date of this Form 10-K, there have not been any cybersecurity incidents that have materially affected our business strategy, 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. 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, in conjunction with its Audit Committee, oversees management’s approach to cybersecurity risk and its alignment with the Company’s risk management program. The Board and Audit Committee receive reports from management about the prevention, detection, mitigation, and remediation of cybersecurity incidents, including material

Chesapeake Utilities Corporation 2023 Form 10-K Page 25

security risks and vulnerabilities. Additionally, management provides the Audit Committee with updates on cybersecurity risk assessments, risk mitigation strategies, and relevant internal and industry cybersecurity matters. The Company’s Chief Information Officer (“CIO”) is responsible for developing and implementing our information security program and reporting on cybersecurity matters to the Board and Audit Committee. The Company’s CIO has 25 years of experience in the information technology industry. The CIO reports to the Chief Executive Officer and is supported by a dedicated cybersecurity team within our information systems department, as well as a multidisciplinary incident response team. Employees across the organization also have a role in our cybersecurity defenses, which we believe improves our cybersecurity posture.

In addition, the Company’s Risk Management Committee (“RMC”) evaluates risks relating to cybersecurity, among other significant risks, and applicable mitigation plans to address such risks. The RMC is comprised of members of the executive leadership team. The RMC meets monthly and receives updates from the CIO or a member of our cybersecurity team. The RMC reviews security performance metrics, global security risks, security enhancements, and updates on our security posture.

ITEM 2. Properties.

Offices and other operational facilities

We own or lease offices and other operational facilities in our service territories located in Delaware, Maryland, Virginia, North Carolina, South Carolina, Florida, Pennsylvania 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, 2023:

Operations	Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines)	2,075
Delmarva Natural Gas (Underground propane pipelines)	17
FPU (Natural gas pipelines)	3,154
Florida City Gas (Natural gas pipelines)	3,860
Natural Gas Transmission
Eastern Shore	517
Florida City Gas	79
Peninsula Pipeline	177
Aspire Energy Express (1)	—
Electric Distribution
FPU	906
Total	10,785

(1) Aspire Energy Express had less than 1 mile of natural gas pipeline at December 31, 2023.

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.

Chesapeake Utilities Corporation 2023 Form 10-K Page 26

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, 2023:

Operations	Gallons or miles
Propane distribution
Propane storage capacity (gallons in millions)	8.9
Underground propane distribution mains (miles)	153
Unregulated Energy Transmission and gathering (Aspire Energy)
Natural gas pipelines (miles)	2,800

ITEM 3. Legal Proceedings.

See Note 20, 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 stock is traded on the New York Stock Exchange ("NYSE") under the ticker symbol CPK. As of February 16, 2024, we had 1,974 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $2.305 per share in 2023 and $2.085 per share in 2022, and have paid a cash dividend to holders of our common stock for 63 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.

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 (see Note 12, Long-Term Debt, in the consolidated financial statements) for additional information.

Chesapeake Utilities Corporation 2023 Form 10-K Page 27

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, 2023:

	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (2)	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs (2)
Period
October 1, 2023 through October 31, 2023 (1)	663	$	95.19	—	—
November 1, 2023 through November 30, 2023	—	—		—	—
December 1, 2023 through December 31, 2023	—	—		—	—
Total	663	$	95.19	—	—

(1) In October 2023, we purchased 663 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 (see Note 16, Employee Benefit Plans, in the consolidated financial statements).

(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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 28

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, 2023, 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, 2018 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.

	2018		2019		2020		2021		2022		2023
Chesapeake Utilities	$	100	$	120	$	138	$	189	$	156	$	142
Industry Index	$	100	$	119	$	99	$	114	$	122	$	121
S&P 500 Index	$	100	$	131	$	156	$	200	$	164	$	207

Chesapeake Utilities Corporation 2023 Form 10-K Page 29

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 information is presented on a diluted basis, unless otherwise noted.

Acquisition of FCG

On November 30, 2023, we completed the acquisition of FCG for $923.4 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 serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe. 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 is 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.

The impact of FCG's results from the acquisition date and effects on our liquidity are discussed further below and throughout Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

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 2023 Form 10-K     Page 30

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, 2023, 2022 and 2021:

Adjusted Gross Margin

	For the Year Ended December 31, 2023
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	473,595	$	223,148	$	(26,139)	$	670,604
Cost of Sales:
Natural gas, propane and electric costs	(140,008)		(102,492)		26,019		(216,481)
Depreciation & amortization	(48,162)		(17,347)		8		(65,501)
Operations & maintenance expenses (1)	(27,485)		(31,507)		343		(58,649)
Gross Margin (GAAP)	257,940		71,802		231		329,973
Operations & maintenance expenses (1)	27,485		31,507		(343)		58,649
Depreciation & amortization	48,162		17,347		(8)		65,501
Adjusted Gross Margin (Non-GAAP)	$	333,587	$	120,656	$	(120)	$	454,123

	For the Year Ended December 31, 2022
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	429,424	$	280,750	$	(29,470)	$	680,704
Cost of Sales:
Natural gas, propane and electric costs	(127,172)		(162,683)		29,349		(260,506)
Depreciation & amortization	(52,707)		(16,257)		(9)		(68,973)
Operations & maintenance expenses (1)	(35,472)		(29,825)		9		(65,288)
Gross Margin (GAAP)	214,073		71,985		(121)		285,937
Operations & maintenance expenses (1)	35,472		29,825		(9)		65,288
Depreciation & amortization	52,707		16,257		9		68,973
Adjusted Gross Margin (Non-GAAP)	$	302,252	$	118,067	$	(121)	$	420,198

Chesapeake Utilities Corporation 2023 Form 10-K Page 31

	For the Year Ended December 31, 2021
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	383,920	$	206,869	$	(20,821)	$	569,968
Cost of Sales:
Natural gas, propane and electric costs	(100,737)		(106,900)		20,687		(186,950)
Depreciation & amortization	(48,748)		(13,869)		(44)		(62,661)
Operations & maintenance expenses (1)	(32,780)		(24,123)		179		(56,724)
Gross Margin (GAAP)	201,655		61,977		1		263,633
Operations & maintenance expenses (1)	32,780		24,123		(179)		56,724
Depreciation & amortization	48,748		13,869		44		62,661
Adjusted Gross Margin (Non-GAAP)	$	283,183	$	99,969	$	(134)	$	383,018

(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 U.S. GAAP.

2023 to 2022 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for 2023 was $257.9 million, an increase of $43.9 million, or 20.5 percent, compared to 2022. Higher gross margin reflects contributions from the Company's Florida Natural Gas base rate proceeding, organic growth in the Company's natural gas distribution businesses and continued pipeline expansion projects, and contributions attributable to the acquisition of FCG. These increases were partially offset by reduced customer consumption resulting from the significantly warmer temperatures in our northern service territories throughout the year and increased employee costs related to growth initiatives, the ongoing competitive labor market and higher benefits costs.

2022 to 2021 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for the year ended December 31, 2022 compared to 2021 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, 2022, which is incorporated herein by reference.

2023 to 2022 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for 2023 was $71.8 million, which was largely consistent with gross margin for the prior year. The effects of changes in customer consumption due primarily to significantly warmer weather in our Mid-Atlantic and North Carolina service areas throughout the year and increased operating expenses and depreciation were largely offset by increased propane margins and fees and increased gathering charges and consumption for Aspire Energy.

2022 to 2021 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for the year ended December 31, 2022 compared to 2021 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, 2022, which is incorporated herein by reference.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 32

Adjusted Net Income and Adjusted EPS

	Year Ended
	December 31,
(in thousands, except shares and per share data)	2023		2022		2021
Net Income (GAAP)	$	87,212	$	89,796	$	83,466
FCG transaction-related expenses, net (1)	10,625		—		—
Adjusted Net Income (Non-GAAP)	$	97,837	$	89,796	$	83,466
Weighted average common shares outstanding - diluted	18,434,857		17,804,294		17,633,029
Earnings Per Share - Diluted (GAAP)	$	4.73	$	5.04	$	4.73
FCG transaction-related expenses, net (1)	0.58		—		—
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	5.31	$	5.04	$	4.73

(1) Transaction-related expenses for the year ended December 31, 2023 represent costs incurred attributable to the acquisition of FCG, including pretax operating expenses of $10.4 million associated with legal, consulting and audit fees and $4.1 million of interest charges related to pretax fees and expenses associated with the Bridge Facility.

2023 to 2022 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2023 was $87.2 million, or $4.73 per share, compared to $89.8 million, or $5.04 per share in 2022. Net income for the year ended December 31, 2023 included $10.6 million of transaction-related expenses in connection with the FCG acquisition. Excluding these costs, net income increased by $8.0 million or 9 percent compared to the prior year.

2022 to 2021 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2022 compared to 2021 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, 2022, which is incorporated herein by reference.

Chesapeake Utilities Corporation 2023 Form 10-K Page 33

OVERVIEW AND HIGHLIGHTS

(in thousands except shares and per share data)					Increase						Increase
For the Year Ended December 31,	2023		2022		(Decrease)		2022		2021		(Decrease)
Operating Income
Regulated Energy	$	126,199	$	115,317	$	10,882	$	115,317	$	106,174	$	9,143
Unregulated Energy	24,426		27,350		(2,924)		27,350		24,427		2,923
Other businesses and eliminations	178		266		(88)		266		511		(245)
Operating Income	150,803		142,933		7,870		142,933		131,112		11,821
Other income, net	1,438		5,051		(3,613)		5,051		1,720		3,331
Interest charges	36,951		24,356		12,595		24,356		20,135		4,221
Income from Before Income Taxes	115,290		123,628		(8,338)		123,628		112,697		10,931
Income Taxes	28,078		33,832		(5,754)		33,832		29,231		4,601
Net Income	$	87,212	$	89,796	$	(2,584)	$	89,796	$	83,466	$	6,330
Basic Earnings Per Share of Common Stock	$	4.75	$	5.07	$	(0.32)	$	5.07	$	4.75	$	0.32
Diluted Earnings Per Share of Common Stock	$	4.73	$	5.04	$	(0.31)	$	5.04	$	4.73	$	0.31
Adjusted Net Income and Adjusted Earnings Per Share
Net Income (GAAP)	$	87,212	$	89,796	$	(2,584)	$	89,796	$	83,466	$	6,330
FCG transaction-related expenses, net (1)	10,625		—		10,625		—		—		—
Adjusted Net Income (Non-GAAP)	$	97,837	$	89,796	$	8,041	$	89,796	$	83,466	$	6,330
Weighted average common shares outstanding - diluted	18,434,857		17,804,294		630,563		17,804,294		17,633,029		171,265
Earnings Per Share - Diluted (GAAP)	$	4.73	$	5.04	$	(0.31)	$	5.04	$	4.73	$	0.31
FCG transaction-related expenses, net (1)	0.58		—		0.58		—		—		—
Adjusted Earnings Per Share - Diluted (Non-GAAP)	$	5.31	$	5.04	$	0.27	$	5.04	$	4.73	$	0.31

(1) Transaction-related expenses for the year ended December 31, 2023 represent costs incurred attributable to the acquisition of FCG, including pretax operating expenses of $10.4 million associated with legal, consulting and audit fees and $4.1 million of interest charges related to pretax fees and expenses associated with the Bridge Facility.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 34

2023 compared to 2022

Key variances in operations between 2023 and 2022 included:

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Year ended December 31, 2022 Adjusted Results**	$	123,628	$	89,796	$	5.04
Non-recurring Items:
One-time benefit associated with reduction in state tax rate	—		2,469		0.13
Absence of interest income from federal income tax refund	(826)		(600)		(0.03)
Absence of gain from sales of assets	(1,902)		(1,382)		(0.07)
	(2,728)		487		0.03
Increased (Decreased) Adjusted Gross Margins:
Contribution from rate changes associated with Florida Natural Gas base rate proceeding*	13,361		9,820		0.53
Increased propane margins per gallon and fees	8,821		6,483		0.34
Contribution from the acquisition of FCG	8,687		6,385		0.35
Natural gas growth (excluding service expansions)	6,214		4,567		0.25
Natural gas transmission service expansions*	4,812		3,537		0.19
Contributions from regulated infrastructure programs*	2,597		1,909		0.10
Increased margins from Aspire Energy	1,141		839		0.05
Increased adjusted gross margin from off-system natural gas capacity sales	960		706		0.04
Customer consumption primarily resulting from weather	(13,627)		(10,016)		(0.54)
	32,966		24,230		1.31
(Increased) Decreased Other Operating Expenses (Excluding Natural Gas, Electricity and Propane Costs):
Payroll, benefits and other employee-related expenses	(9,013)		(6,625)		(0.36)
FCG operating expenses	(4,190)		(3,080)		(0.17)
Facilities expenses, maintenance costs and outside services	(1,756)		(1,290)		(0.07)
Customer service related costs	(820)		(603)		(0.03)
Regulatory expenses	(658)		(484)		(0.03)
Depreciation, amortization and property tax costs	615		452		0.02
Decreased vehicle expenses	577		424		0.02
	(15,245)		(11,206)		(0.62)
Interest charges	(8,494)		(6,243)		(0.34)
Change in pension expense	(1,453)		(1,068)		(0.06)
Increase in shares outstanding due to 2023 and 2022 equity offerings	—		—		(0.17)
Net other changes	1,070		1,841		0.12
Year ended December 31, 2023 Adjusted Results**	$	129,744	$	97,837	$	5.31

* See the Major Projects and Initiatives table.

** Transaction-related expenses attributable to the acquisition of FCG have been excluded from the Company’s non-GAAP measures of adjusted net income and adjusted EPS. See previous tables for a reconciliation of these items against the related GAAP measures.

Chesapeake Utilities Corporation 2023 Form 10-K Page 35

SUMMARY OF KEY FACTORS

Recently Completed and Ongoing Major Projects and Initiatives

We constantly pursue and develop additional projects and 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 recently completed and currently underway. 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. Our practice is to add new projects and initiatives to this table once negotiations or details are substantially final and/or the associated earnings can be estimated.

	Adjusted Gross Margin
	Year Ended December 31,						Estimate for Calendar Year
(in thousands)	2021		2022		2023		2024		2025
Pipeline Expansions:
Guernsey Power Station	$	187	$	1,377	$	1,478	$	1,482	$	1,478
Southern Expansion	—		—		586		2,344		2,344
Winter Haven Expansion	—		260		637		626		626
Beachside Pipeline Expansions	—		—		1,810		2,451		2,414
North Ocean City Connector	—		—		—		—		494
St. Cloud / Twin Lakes Expansion	—		—		264		584		584
Clean Energy (1)	—		126		1,064		1,009		1,079
Wildlight	—		—		471		2,000		2,038
Lake Wales	—		—		265		454		454
Newberry	—		—		—		862		2,585
Total Pipeline Expansions	187		1,763		6,575		11,812		14,096
CNG/RNG/LNG Transportation and Infrastructure	7,566		11,100		11,181		12,500		13,969
Regulatory Initiatives:
Florida GUARD Program	—		—		353		2,421		5,136
FCG SAFE Program	—		—		—		2,683		5,293
Capital Cost Surcharge Programs	1,199		2,001		2,829		3,979		4,374
Florida Rate Case Proceeding (2)	—		2,474		15,835		17,153		17,153
Maryland Rate Case (3)	—		—		—		TBD		TBD
Electric Storm Protection Plan	—		486		1,326		2,433		3,951
Total Regulatory Initiatives	1,199		4,961		20,343		28,669		35,907
Total	$	8,952	$	17,824	$	38,099	$	52,981	$	63,972

(1) Includes adjusted gross margin generated from interim services through the project in-service date in September 2023.

(2) Includes adjusted gross margin during 2023 comprised of both interim rates and permanent base rates which became effective in March 2023.

(3) Rate case application filed with the Maryland PSC in January 2024. See additional information provided below.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 36

Discussion of Major Projects and Initiatives

Pipeline Expansions

Guernsey Power Station

Guernsey Power Station and our affiliate, Aspire Energy Express, are engaged in a firm transportation capacity agreement whereby Guernsey Power Station has constructed a power generation facility and Aspire Energy Express provides firm natural gas transportation service to this facility. Guernsey Power Station commenced construction of the project in October 2019, Aspire Energy Express completed construction of the gas transmission facilities in the fourth quarter of 2021, and the facility went into service during the first quarter of 2023. The project generated additional adjusted gross margin of $0.1 million for the year ended December 31, 2023, and is expected to produce adjusted gross margin of approximately $1.5 million in 2024 and beyond.

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 and generated adjusted gross margin of $0.6 million for the year ended December 31, 2023 and is expected to produce adjusted gross margin of approximately $2.3 million in 2024 and beyond.

Winter Haven Expansion

In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with Florida Natural Gas for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline constructed a new interconnect with FGT and a new regulator station for Florida Natural Gas. Florida Natural Gas is using the additional firm service to support new incremental load due to growth in the area, including providing service, most immediately, to a new can manufacturing facility, as well as reliability and operational benefits to Florida Natural Gas's existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, Florida Natural Gas also extended its distribution system to connect to the new station. This expansion was placed in service in the third quarter of 2022. The project generated additional adjusted gross margin of $0.4 million for the year ended December 31, 2023, and is expected to produce adjusted gross margin of approximately $0.6 million in 2024 and beyond.

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 Florida City Gas’ 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, area east under the Intercoastal Waterway and southward on the barrier island. Construction was completed and 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 $1.8 million for the year ended December 31, 2023, and is expected to produce adjusted gross margin of approximately $2.5 million in 2024 and $2.4 million in 2025 and beyond.

North Ocean City Connector

During the second quarter of 2022, we began construction of an extension of service into North Ocean City, Maryland. Our Delaware natural gas division and Sandpiper installed approximately 5.4 miles of pipeline across southern Sussex County, Delaware to Fenwick Island, Delaware and Worcester County, Maryland. The project reinforces our existing system in Ocean City, Maryland and enables incremental growth along the pipeline. Construction of this project was completed in the second quarter of 2023. The Company filed a natural gas rate case application with the PSC for the state of Maryland in January 2024 as discussed below. Adjusted gross margin in connection with this project is contingent upon the completion of the rate case and inclusion of the project in rate base. As a result, we expect this expansion to generate annual adjusted gross margin of approximately $0.5 million beginning in 2025, with additional margin opportunities from incremental growth.

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 Dt/day 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, 2023. We expect this extension to generate additional annual adjusted gross margin of approximately $0.6 million in 2024 and beyond.

Chesapeake Utilities Corporation 2023 Form 10-K Page 37

Clean Energy Expansion

During the fourth quarter of 2022, Clean Energy Fuels ("Clean Energy") and Florida Natural Gas entered into a precedent agreement for firm transportation services associated with a CNG fueling station Clean Energy is constructing. We installed approximately 2.2 miles of main extension in Davenport, Florida to support the filling station which was placed into service during September 2023. Our subsidiary, Marlin Gas Services, provided interim services to Clean Energy during the construction phase of the project. The project generated additional adjusted gross margin of $0.9 million for the year ended December 31, 2023, and is expected to contribute adjusted gross margin of approximately $1.0 million in 2024 and $1.1 million in 2025 and beyond.

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 will enable us to build the project during the construction and 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. Various phases of the project commenced in the first quarter of 2023, with construction on the overall project continuing through 2025. The project generated additional adjusted gross margin of $0.5 million for the year ended December 31, 2023, and is expected to contribute adjusted gross margin of approximately $2.0 million in 2024 and beyond.

Lake Wales Expansion

In February 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with our Florida Natural Gas distribution business, FPU, for an additional 9,000 Dt/d of firm service in the Lake Wales, Florida area. The PSC approved the petition in April 2023. Approval of the agreement enabled Peninsula Pipeline to complete 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 $0.3 million for the year ended December 31, 2023, and is expected to contribute adjusted gross margin of approximately $0.5 million in 2024 and beyond.

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 Dt/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 propane community gas systems in Newberry was made in November 2023, and the Florida PSC is scheduled to vote on this in March 2024. The project is expected to contribute adjusted gross margin of approximately $0.9 million in 2024 and $2.6 million in 2025 and beyond.

Worcester Resiliency Upgrade

In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. Eastern Shore has requested certificate authorization by December 2024, with a target in-service date by the third quarter of 2025.

East Coast Reinforcement Projects

In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that 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/day and 3,400 Dts/day, respectively. The Florida PSC is scheduled to vote on the projects in March 2024.

Central Florida Reinforcement Projects

In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida. The projects are driven by the need for increased supply to communities in central Florida 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 Plant City and Lake Mattie with an additional 5,000 Dts/day and 8,700 Dts/day, respectively.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 38

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. Similarly, we announced in March 2022, the opening of a high-capacity CNG truck and tube trailer fueling station in Port Wentworth, Georgia. As one of the largest public access CNG stations on the East Coast, it will offer a RNG option to customers in the near future. We constructed the station in partnership with Atlanta Gas Light, a subsidiary of Southern Company Gas.

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 service and infrastructure related adjusted gross margin from across the organization in combination with our CNG and LNG projects.

For the year ended December 31, 2023, we generated $0.1 million in additional adjusted gross margin associated with the transportation of CNG and RNG by Marlin's virtual pipeline and Aspire Energy's Noble Road RNG pipeline. We estimate annual adjusted gross margin of approximately $12.5 million in 2024, and $14.0 million in 2025 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 is projected to occur in the first half 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 is expected to represent nearly 10 percent of Aspire Energy’s gas gathering volumes.

Regulatory Initiatives

Florida GUARD Program

In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a ten-year program to enhance the safety, reliability, and accessibility of portions of our natural gas distribution system. We identified various categories of projects to be included in GUARD, which include the relocation of mains and service lines located in rear easements and other difficult to access areas to the front of the street, the replacement of problematic distribution mains, service lines, and maintenance and repair equipment and system reliability projects. In August 2023, the Florida PSC approved the GUARD program, which included $205 million of capital expenditures projected to be spent over a 10-year period. For the year ended December 31, 2023, there was $0.4 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $2.4 million of adjusted gross margin in 2024 and $5.1 million in 2025.

Chesapeake Utilities Corporation 2023 Form 10-K Page 39

FCG SAFE Program

In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the Commission approved a replacement of 160 miles of pipe that was used in the 1970s and 1980s and shown through industry research to exhibit premature failure in the form of cracking. The program includes projected capital expenditures of $205 million over a 10-year period. The program is expected to generate $2.7 million of adjusted gross margin in 2024 and $5.3 million in 2025.

Capital Cost Surcharge Programs

In December 2019, the FERC approved Eastern Shore’s capital cost surcharge to become effective January 1, 2020. The surcharge, an approved item in the settlement of Eastern Shore’s last general rate case, allows Eastern Shore to recover capital costs associated with mandated highway or railroad relocation projects that required the replacement of existing Eastern Shore facilities. In 2023, there was $0.8 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to produce adjusted gross margin of approximately $4.0 million in 2024 and $4.4 million in 2025 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

Florida Natural Gas Rate Case Proceeding

In May 2022, our legacy natural gas distribution businesses in Florida filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 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 rate structure across the businesses and to unify the Florida Natural Gas distribution business under FPU; (iv) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (v) 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. The discovery process and related hearings were concluded during the fourth quarter of 2022 and briefs were submitted in the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023. For the year ended December 31, 2023, there was $15.8 million of adjusted gross margin generated pursuant to this proceeding, and it is expected to generate $17.2 million of total adjusted gross margin in 2024 and 2025.

Maryland Natural Gas Rate Case

In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $6.9 million; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses under the new corporate entity which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. The outcome of the application is subject to review and approval by the Maryland PSC.

Storm Protection Plan

In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC"), which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs related to its SPP. Our Florida electric distribution operation's SPP and SPPCRC were filed during the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. For the year ended December 31, 2023, this initiative generated incremental adjusted gross margin of $0.8 million, and is expected to generate $2.4 million in 2024 and $4.0 million in 2025. We expect continued investment under the SPP going forward.

COVID-19 Regulatory Proceeding

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset allows us to obtain recovery of these costs in the next base rate proceedings. Our Florida regulated business units reached a settlement with the Florida OPC in June 2021, enabling the business units to establish a regulatory asset of $2.1 million. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units are currently amortizing the amount over two years effective January 1, 2022 and recovering the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric

Chesapeake Utilities Corporation 2023 Form 10-K     Page 40

division. This resulted in additional adjusted gross margin of $1.0 million annually for both 2022 and 2023, which was offset by a corresponding amortization of regulatory asset expense in each year.

Other Major Factors Influencing Adjusted Gross Margin

Weather and Consumption

Weather had a significant impact on customer consumption during 2023, resulting in adjusted gross margin being negatively impacted by approximately $13.6 million compared to 2022 driven largely by significantly warmer weather in some of the Company's service territories resulting in reduced consumption. The following table summarizes heating degree day ("HDD") and cooling degree day (“CDD”) variances from the 10-year average HDD/CDD ("Normal") for the years ended 2023 compared to 2022, and 2022 compared to 2021.

HDD and CDD Information

	For the Years Ended December 31,
	2023	2022	Variance	2022	2021	Variance
Delmarva
Actual HDD	3,416	4,088	(672)	4,088	3,849	239
10-Year Average HDD ("Normal")	4,161	4,147	14	4,147	4,182	(35)
Variance from Normal	(745)	(59)		(59)	(333)
Florida
Actual HDD	664	836	(172)	836	829	7
10-Year Average HDD ("Normal")	826	828	(2)	828	839	(11)
Variance from Normal	(162)	8		8	(10)
Ohio
Actual HDD	5,043	5,532	(489)	5,532	5,138	394
10-Year Average HDD ("Normal")	5,594	5,557	37	5,557	5,621	(64)
Variance from Normal	(551)	(25)		(25)	(483)
Florida
Actual CDD	3,101	2,826	275	2,826	2,687	139
10-Year Average CDD ("Normal")	2,934	2,929	5	2,929	2,952	(23)
Variance from Normal	167	(103)		(103)	(265)

Natural Gas Distribution Growth

The average number of residential customers served on the Delmarva Peninsula and our legacy Florida Natural Gas distribution business increased by approximately 5.4 percent and 3.9 percent, respectively, during 2023.

On the Delmarva Peninsula, a larger percentage of the adjusted gross margin growth was generated from residential growth given the expansion of gas into new housing communities and conversions to natural gas as our distribution infrastructure continues to build out. In Florida, as new communities continue to build out due to population growth and the additional infrastructure to support the growth, there is increased load from both residential customers as well as new commercial and industrial customers. The details are provided in the following table:

Chesapeake Utilities Corporation 2023 Form 10-K Page 41

	Adjusted Gross Margin Increase
	For the Year Ended December 31, 2023
(in thousands)	Delmarva Peninsula		Florida
Customer growth:
Residential	$	1,895	$	1,599
Commercial and industrial	589		2,131
Total customer growth (1)	$	2,484	$	3,730

(1) Customer growth amounts for our legacy Florida operations include the effects of revised rates associated with the Company's natural gas base rate proceeding, but exclude the effects of the FCG acquisition.

REGULATED ENERGY

					Increase						Increase
For the Year Ended December	2023		2022		(Decrease)		2022		2021		(Decrease)
(in thousands)
Revenue	$	473,595	$	429,424	$	44,171	$	429,424	$	383,920	$	45,504
Natural gas and electric costs	140,008		127,172		12,836		127,172		100,737		26,435
Adjusted gross margin (1)	333,587		302,252		31,335		302,252		283,183		19,069
Operations & maintenance	125,310		112,963		12,347		112,963		108,190		4,773
Depreciation & amortization	48,162		52,707		(4,545)		52,707		48,748		3,959
FCG transaction-related expenses (2)	10,355		—		10,355		—		—		—
Other taxes	23,561		21,265		2,296		21,265		20,071		1,194
Other operating expenses	207,388		186,935		20,453		186,935		177,009		9,926
Operating Income	$	126,199	$	115,317	$	10,882	$	115,317	$	106,174	$	9,143

(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-related expenses referred to in this table represent pretax operating expenses of $10.4 million associated with legal, consulting and audit fees incurred in connection with the acquisition of FCG.

2023 compared to 2022

Operating income for the Regulated Energy segment for 2023 was $126.2 million, an increase of $10.9 million, or 9.4 percent, compared to 2022. Excluding transaction-related expenses associated with the acquisition of FCG, operating income increased $21.2 million or 18.4 percent compared to the prior year. Higher operating income reflects contributions from our regulatory initiatives, organic growth in our natural gas distribution businesses and continued pipeline expansion projects, and contributions from the acquisition of FCG. These increases were partially offset by changes in customer consumption resulting from the significantly warmer temperatures in our northern service territories throughout the year. Excluding the transaction-related expenses described above, operating expenses increased by $10.1 million compared to the prior year primarily attributable to increased employee costs driven by growth initiatives, the ongoing competitive labor market and higher benefits costs and higher property taxes compared to the prior year. Increases in depreciation and amortization expense attributable to growth projects that were placed into service during the current year were offset by reductions related to revised depreciation rates approved in the Company's Florida Natural Gas rate case and electric depreciation study filing, and a $5.1 million RSAM adjustment from FCG.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 42

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

(in thousands)
Rate changes associated with the Florida Natural Gas base rate proceeding (1)	$	13,361
Contribution from the acquisition of FCG	8,687
Natural gas growth including conversions (excluding service expansions)	6,214
Natural gas transmission service expansions	4,812
Contributions from regulated infrastructure programs	2,597
Changes in customer consumption, driven by significantly warmer temperatures	(5,096)
Other variances	760
Year-over-year increase in adjusted gross margin	$	31,335

(1) Includes adjusted gross margin contributions from interim rates and permanent base rates that became effective in March 2023.

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

Rate Changes Associated with the Florida Natural Gas Base Rate Proceeding

In August 2022, the Florida PSC approved interim rates starting in September 2022. In February 2023, we obtained a final rate order in connection with the Florida Natural Gas base rate proceeding with permanent rates effective on March 1, 2023. These interim and permanent rates contributed additional adjusted gross margin of $13.4 million. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Contribution from Acquisition of FCG

FCG contributed adjusted gross margin of $8.7 million from the acquisition date.

Natural Gas Distribution Customer Growth

We generated additional adjusted gross margin of $6.2 million from natural gas customer growth. Adjusted gross margin increased by $3.7 million for our Florida Natural Gas distribution business and $2.5 million on the Delmarva Peninsula compared to 2022, due primarily to residential customer growth of 3.9 percent and 5.4 percent in Florida and on the Delmarva Peninsula, respectively.

Natural Gas Transmission Service Expansions

We generated increased adjusted gross margin of $4.8 million from natural gas transmission service expansions of Peninsula Pipeline, Eastern Shore and Aspire Energy Express.

Contributions from Regulated Infrastructure Programs

Contributions from regulated infrastructure programs generated incremental adjusted gross margin of $2.6 million for the year. The increase in adjusted gross margin was primarily related to FPU Electric's storm protection plan, Eastern Shore's capital surcharge program and Florida's GUARD program. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Chesapeake Utilities Corporation 2023 Form 10-K Page 43

Customer Consumption - Inclusive of Weather

We experienced reduced customer consumption for the year ended December 31, 2023, largely the result of significantly warmer weather experienced in the Delmarva service territory throughout the year resulting in reduced adjusted gross margin of $5.1 million compared to 2022.

The major components of the increase in other operating expenses are as follows:

(in thousands)
FCG transaction-related expenses (1)	$	10,355
Payroll, benefits and other employee-related expenses	5,054
FCG operating expenses	4,190
Facilities expenses, maintenance costs and outside services	1,416
Customer service related costs	764
Regulatory expenses	658
Depreciation, amortization and property tax costs	(2,308)
Other variances	324
Year-over-year increase in other operating expenses	$	20,453

(1) Transaction-related expenses referred to in this table represent pretax operating expenses of $10.4 million associated with legal, consulting and audit fees incurred in connection with the acquisition of FCG.

2022 compared to 2021

The results for the Regulated Energy segment for the year ended December 31, 2022 compared to 2021 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, 2022, which is incorporated herein by reference.

UNREGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2023		2022		(Decrease)		2022		2021		(Decrease)
(in thousands)
Revenue	$	223,148	$	280,750	$	(57,602)	$	280,750	$	206,869	$	73,881
Propane and natural gas costs	102,492		162,683		(60,191)		162,683		106,900		55,783
Adjusted gross margin (1)	120,656		118,067		2,589		118,067		99,969		18,098
Operations & maintenance	74,168		70,489		3,679		70,489		57,905		12,584
Depreciation & amortization	17,347		16,257		1,090		16,257		13,869		2,388
Other taxes	4,715		3,971		744		3,971		3,768		203
Other operating expenses	96,230		90,717		5,513		90,717		75,542		15,175
Operating Income	$	24,426	$	27,350	$	(2,924)	$	27,350	$	24,427	$	2,923

(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.

2023 Compared to 2022

Operating income for the Unregulated Energy segment for 2023 decreased by $2.9 million compared to 2022. Operating results were impacted by changes in customer consumption due to significantly warmer weather in our Mid-Atlantic and North Carolina service areas throughout the year as well as conversion of propane customers to our natural gas distribution service. Additionally, we experienced increased operating expenses associated with increased payroll, benefits and employee related expenses driven by competition in the current labor market, depreciation, amortization and property taxes, as well as increased costs for facilities, maintenance and outside services. These factors were partially offset by increased propane margins and fees and increased gathering charges and customer consumption for Aspire.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 44

Adjusted Gross Margin

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

(in thousands)
Propane Operations
Increased propane margins and fees	$	8,821
Propane customer consumption - primarily weather related	(8,235)
Decreased customer consumption due to conversion of customers to our natural gas system	(793)
Aspire Energy
Increase in gathering margin	1,141
Increased customer consumption	496
Eight Flags
Increased electric generation margin	1,018
Other variances	141
Year-over-year increase in adjusted gross margin	$	2,589

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

Propane Operations

•Increased propane margins and fees - Adjusted gross margin increased by $8.8 million, mainly due to increased 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.

•Propane customer consumption - Adjusted gross margin was negatively impacted by $8.2 million as a result of reduced customer consumption driven by significantly warmer weather that our Mid-Atlantic and North Carolina service areas experienced throughout 2023.

•Reduced customer consumption due to conversion of customers to natural gas - Adjusted gross margin was reduced by $0.8 million as more customers converted from propane to our natural gas distribution service.

Aspire Energy

•Increase in gathering charges - Adjusted gross margin increased by $1.1 million primarily due to increased gathering charges associated with a large commercial customer.

•Increased customer consumption - Adjusted gross margin increased by $0.5 million despite warmer temperatures due to increased customer consumption from agricultural customers compared to the prior year.

Eight Flags

•Increased electric generation margin - Adjusted gross margin increased by $1.0 million due to increased electric generation compared to the prior year.

Other Operating Expenses

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

(in thousands)
Increased payroll, benefits and other employee-related expenses	$	3,959
Increased depreciation, amortization and property tax costs	1,717
Other variances	(163)
Period-over-period increase in other operating expenses	$	5,513

Chesapeake Utilities Corporation 2023 Form 10-K Page 45

2022 compared to 2021

The results for the Unregulated Energy segment for the year ended December 31, 2022 compared to 2021 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, 2022, which is incorporated by reference.

OTHER INCOME, NET

Other income, net was $1.4 million and $5.1 million for 2023 and 2022, respectively. Other income, net includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets for our unregulated businesses and pension and other benefits expense. The decrease was primarily attributable to the absence of a one-time gain related to a building sale during 2022, the absence of interest income received in connection with a Federal Income Tax refund during 2022, and higher pension related expenses compared to the prior-year period.

INTEREST CHARGES

2023 Compared to 2022

Interest charges for 2023 increased by $12.6 million compared to the same period in 2022. This increase is primarily attributable to $6.2 million in interest expense as a result of long-term debt placements in 2023, including the November 2023 placement in connection with the FCG acquisition as well as $4.1 million related to bridge financing costs also attributable to the FCG acquisition. Higher interest expense on Revolver borrowings of $3.1 million driven by higher average interest rates compared to the prior year also contributed to the increase. The weighted-average interest rate on our Revolver borrowings was 5.4 percent for the year ended December 31, 2023 compared to 2.5 percent during the prior year as a result of the Federal Reserve actions in 2022 and 2023. These factors were partially offset by higher capitalized interest of $1.7 million during the current year associated with capital projects.

INCOME TAXES

2023 Compared to 2022

Income tax expense was $28.1 million for 2023 compared to $33.8 million for 2022. Our effective income tax rates were 24.4 percent and 27.4 percent for the years ended December 31, 2023 and 2022, respectively. Income tax expense for the year ended December 31, 2023 includes a $2.5 million benefit 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.

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 previously, shares of common stock 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 an 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 $1.1 billion in 2023, which includes $923.4 million attributable to the purchase of FCG and $3.9 million related to an acquisition in the propane distribution business.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 46

The following table shows total capital expenditures for the year ended December 31, 2023 by segment and by business line:

	For the Year Ended December 31, 2023
(in thousands)
Regulated Energy:
Natural gas distribution	$	109,245
Natural gas transmission	40,179
Electric distribution	19,745
Total Regulated Energy	169,169
Unregulated Energy:
Propane distribution	14,287
Energy transmission	5,469
Other unregulated energy	20,508
Total Unregulated Energy	40,264
Other:
Corporate and other businesses	1,762
Total Other	1,762
Legacy capital expenditures	211,195
FCG Acquisition (1)	926,702
Total 2023 Capital Expenditures	$	1,137,897

(1) Includes amounts for the acquisition of FCG net of cash acquired and their capital expenditures from the date of the acquisition through December 31, 2023. For additional information on the FCG acquisition, refer to Note 4, Acquisitions, in the consolidated financial statements.

In the table below, we have provided a range of our forecasted capital expenditures by segment and business line for 2024:

	Estimate for Fiscal 2024
(in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	150,000	$	170,000
Natural gas transmission	90,000		120,000
Electric distribution	25,000		28,000
Total Regulated Energy	265,000		318,000
Unregulated Energy:
Propane distribution	13,000		15,000
Energy transmission	5,000		6,000
Other unregulated energy	13,000		15,000
Total Unregulated Energy	31,000		36,000
Other:
Corporate and other businesses	4,000		6,000
Total 2024 Forecasted Capital Expenditures	$	300,000	$	360,000

The 2024 forecast excludes potential acquisitions due to their opportunistic nature.

As a result of the Company’s most recent 5-year strategic plan review where we revisited growth projections over the next five years for our legacy businesses and with the increased scale and investment opportunities related to FCG, the Company previously announced new capital expenditure guidance for the five-year period ended 2028 that will range from $1.5 billion to $1.8 billion.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 47

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.

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, 2023 and 2022 and includes the impacts associated with financing the FCG acquisition:

	December 31, 2023				December 31, 2022
(dollars in thousands)
Long-term debt, net of current maturities	$	1,187,075	49	%	$	578,388	41	%
Stockholders’ equity	1,246,104		51	%	832,801		59	%
Total capitalization, excluding short-term borrowings	$	2,433,179	100	%	$	1,411,189	100	%

	December 31, 2023				December 31, 2022
(dollars in thousands)
Short-term debt	$	179,853	7	%	$	202,157	12	%
Long-term debt, including current maturities	1,205,580		46	%	599,871		37	%
Stockholders’ equity	1,246,104		47	%	832,801		51	%
Total capitalization, including short-term borrowings	$	2,631,537	100	%	$	1,634,829	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 to move closer to our target capital structure over the next couple of years.

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.

During 2023, there were no issuances under the DRIP. In 2022, we issued less than 0.1 million shares at an average price per share of $136.26 and received net proceeds of $4.5 million under the DRIP.

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended these Shelf Agreements, which expanded the total borrowing capacity and extended the term of the agreements for an additional three years from the effective dates to 2026. The following table summarizes our Shelf Agreements at December 31, 2023:

	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement (1)
(in thousands)
Prudential Shelf Agreement	$	405,000	$	(300,000)	—		$	105,000
MetLife Shelf Agreement	200,000		(50,000)		—		150,000
Total	$	605,000	$	(350,000)	$	—	$	255,000

Chesapeake Utilities Corporation 2023 Form 10-K     Page 48

(1) The amended Prudential and MetLife Shelf Agreements both expire in February 2026.

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 November 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG which closed during the fourth quarter of 2023. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes 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.

In March 2023, we issued 5.43 percent Senior Notes due March 14, 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 of Directors to borrow up to $375.0 million of short-term debt, as required. At December 31, 2023 and 2022, we had $179.9 million and $202.2 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.83 percent and 5.04 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2023.

We have entered into several amendments to our Revolver which resulted in modifications to both tranches of the facility. The most recent amendment in October 2023 allowed for a change in our funded indebtedness ratio from 65 percent to 70 percent during the quarter in which the acquisition of FCG is consummated and the quarter subsequent to the closing of the acquisition. The amendment in August 2023 served to renew the 364-day tranche of the Revolver, providing for $175.0 million of short-term debt capacity. Additionally, the amendment for borrowings under the 364-day tranche shall now 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. Further, the amendment provided that borrowings under the 364-day green loan sublimit shall now bear interest at (i) the SOFR rate plus a 10-basis point credit spread adjustment and an applicable margin of 1.00 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate plus 0.05 percent or less, solely at our discretion. The amendment entered into in 2022 served to reset the benchmark interest rate to SOFR and to eliminate a previous covenant which capped our investment limit to $150.0 million for investments where we maintain less than 50 percent ownership.

The 364-day tranche of the Revolver expires in August 2024 and the five-year tranche expires in August 2026. Borrowings under both tranches of the Revolver are 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. As of December 31, 2023, the pricing under the 364-day tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 75-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances. As of December 31, 2023, the pricing under the five-year tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 95-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances.

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio as described above. As of December 31, 2023, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, 2023 was $188.1 million. As of December 31, 2023, we had issued $7.0 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

Chesapeake Utilities Corporation 2023 Form 10-K Page 49

In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC 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 without any funds drawn to finance the transaction.

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, 2023, 2022 and 2021 are as follows:

(in thousands)	2023			2022			2021
Average borrowings during the year	$	130,246		$	170,434		$	182,305
Weighted average interest rate for the year	5.41		%	2.49		%	1.03		%
Maximum month-end borrowings	$	206,460		$	225,050		$	226,097

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2023, 2022 and 2021:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Net cash provided by (used in):
Operating activities	$	203,482	$	158,882	$	150,504
Investing activities	(1,111,391)		(136,448)		(223,023)
Financing activities	906,609		(21,206)		73,996
Net (decrease) increase in cash and cash equivalents	(1,300)		1,228		1,477
Cash and cash equivalents—beginning of period	6,204		4,976		3,499
Cash and cash equivalents—end of period	$	4,904	$	6,204	$	4,976

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 changes in deferred income taxes, 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 2023, net cash provided by operating activities was $203.5 million. Operating cash flows were primarily impacted by the following:

•Net income, adjusted for non-cash adjustments, provided a $170.0 million source of cash;

•Changes in net regulatory assets and liabilities due primarily to the change in fuel costs collected through the various cost recovery mechanisms resulted in a $20.1 million source of cash; and

•Other working capital changes, as well as propane inventory and the related hedging activity, resulted in a $9.8 million source of cash.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $1.1 billion during the year ended December 31, 2023. Key investing activities contributing to the cash flow change included:

•Net cash of $925.0 million was used in 2023 to acquire FCG and a propane distribution business; and

•Cash used to pay for capital expenditures amounted to $188.6 million for 2023.

Cash Flows Provided by Financing Activities

Chesapeake Utilities Corporation 2023 Form 10-K     Page 50

Net cash provided by financing activities totaled $906.6 million for the year ended December 31, 2023. This source of cash was largely related to financing activities in connection with the FCG acquisition and included:

•A net increase in long-term debt borrowings resulting in a net source of cash of $605.5 million, including $627.0 million from issuances, offset by long-term repayments of $21.5 million;

•Net proceeds of $366.4 million from the issuance of common stock; partially offset by

•A $40.0 million use of cash for dividend payments in 2023; and

•Net repayments under lines of credit resulting in a use of cash of $22.5 million.

CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2023:

	Payments Due by Period
Contractual Obligations	2024		2025-2026		2027-2028		After 2028		Total
(in thousands)
Long-term debt (1)	$	18,505	$	160,079	$	268,373	$	762,376	$	1,209,333
Operating leases (2)	2,771		4,062		2,788		5,243		14,864
Purchase obligations (3)
Transmission capacity	45,314		87,627		70,030		128,326		331,297
Storage capacity	3,312		4,519		860		—		8,691
Commodities	30,983		—		—		—		30,983
Electric supply	6,431		12,936		12,961		12,961		45,289
Unfunded benefits (4)	228		485		474		1,131		2,318
Funded benefits (5)	2,018		4,035		4,035		2,172		12,260
Total Contractual Obligations	$	109,562	$	273,743	$	359,521	$	912,209	$	1,655,035

(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 $62.4 million, $116.4 million, $92.8 million and $160.6 million, respectively, for the periods indicated above. Expected interest payments for all periods total $432.2 million.

(2) See Item 8, Financial Statements and Supplementary Data, Note 14, Leases, for additional information.

(3) See Item 8, Financial Statements and Supplementary Data, Note 20, 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 16, Employee Benefit Plans, for additional information on the plans.

(5) We have recorded long-term liabilities of $0.2 million at December 31, 2023 for the FPU qualified, defined benefit pension plan. 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 2024. 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 16, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $12.3 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 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, 2023 was $35.0 million. The aggregate amount guaranteed at December 31, 2023 was approximately $24.3 million with the guarantees expiring on various dates through December 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2023 was $4.0 million.

As of December 31, 2023, we have issued letters of credit totaling approximately $7.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the capacity agreement between NEXUS and Aspire, and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 2024. There have been no draws on these letters of credit as of December 31, 2023. 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 20, Other Commitments and Contingencies in the consolidated financial statements.

Chesapeake Utilities Corporation 2023 Form 10-K Page 51

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.

Regulatory Assets and Liabilities

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 2023 indicated no impairment of goodwill. At December 31, 2023, our goodwill balance totaled $508.2 million including $461.2 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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 52

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 16, 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 assumptions, and significant changes in estimates.

At December 31, 2023, 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 5.00 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 0.25 percent 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 0.25 percent change in the rate of return would not have a material impact on our annual pension cost for the FPU pension plan.

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

INTEREST RATE RISK

The fluctuation in interest rates expose 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 8.9 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 53

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2022 to December 31, 2023:

(in thousands)	Balance at December 31, 2022		Increase (Decrease) in Fair Market Value		Less Amounts Settled		Balance at December 31, 2023
Sharp	$	1,507	$	(1,822)	$	(61)	$	(376)

There were no changes in the methods of valuations during the year ended December 31, 2023.

The following is a summary of fair market value of financial derivatives as of December 31, 2023, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2024		2025		2026		Total Fair Value
Price based on Mont Belvieu - Sharp	$	(264)	$	(75)	$	(37)	$	(376)

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 2023 Form 10-K     Page 54

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Chesapeake Utilities Corporation

Opinions on the Consolidated 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, 2023 and 2022, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the years in the three-year period ended December 31, 2023, and the related notes and financial statement schedule 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, 2023, 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 present fairly, in all material respects, the financial position of the Company as of December 31, 2023 and 2022, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, based on criteria established in Internal Control – Integrated Framework: (2013) issued by COSO.

Basis for Opinion

The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for their assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control 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 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 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.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management has excluded Florida City Gas (“FCG”) from its assessment of internal control over financial reporting as of December 31, 2023, because it was acquired by the Company in a business combination during 2023. We have also excluded FCG from our audit of internal control over financial reporting. FCG is a wholly-owned subsidiary whose total assets and loss before taxes represented 31 percent and 4 percent, respectively, of the Company’s consolidated total assets and earnings before taxes as of December 31, 2023 and for the year then ended.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 55

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.

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

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Goodwill Impairment Assessment - Energy Transmission and Supply Services (Aspire Energy) - Unregulated Energy Segment - Refer to Notes 2 and 10 to the consolidated financial statements

Critical Audit Matter Description

As described in Notes 2 and 10 to the consolidated financial statements, the Company has recorded goodwill associated with the Aspire Energy reporting unit within its Unregulated Energy reportable segment as of December 31, 2023. To test goodwill for impairment, the Company uses a present value technique based on discounted cash flows to estimate the fair value of its reporting units. Management’s testing of goodwill as of December 31, 2023 indicated no impairment.

We identified the goodwill impairment assessment of Aspire Energy as a critical audit matter because the fair value estimate requires significant estimates and assumptions by management, including those relating to future revenue and operating margin forecasts and discount rates. Testing these estimates involved especially challenging, subjective, or complex judgments and effort.

How the Critical Audit Matter was Addressed in the Audit

The primary procedures we performed to address this critical audit matter included:

•We obtained an understanding, evaluated the design, and tested the operating effectiveness of controls over management’s goodwill impairment evaluation, including those over the determination of the fair value of the Aspire Energy reporting unit.

•We evaluated the appropriateness of management’s valuation methodology, including testing the mathematical accuracy of the calculation.

•We assessed the historical accuracy of management’s revenue and operating margin forecasts.

•We compared the significant assumptions used by management to current industry and economic trends, current and historical performance of the reporting unit, and other relevant factors.

•We performed sensitivity analyses of the significant assumptions to evaluate the changes in the fair value of the reporting units that would result from changes in the assumptions.

•We evaluated whether the assumptions were consistent with evidence obtained in other areas of the audit, including testing the Company’s fair value of all reporting units within the Company's Regulated and Unregulated Energy segments, in relation to the market capitalization of the Company and assessed the results.

/s/ Baker Tilly US, LLP

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

Lancaster, Pennsylvania

February 21, 2024

Chesapeake Utilities Corporation 2023 Form 10-K     Page 56

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Income

	For the Year Ended December 31,
	2023		2022		2021
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	473,595	$	429,424	$	383,920
Unregulated Energy	223,148		280,750		206,869
Other businesses and eliminations	(26,139)		(29,470)		(20,821)
Total operating revenues	670,604		680,704		569,968
Operating Expenses
Natural gas and electricity costs	140,008		127,172		100,737
Propane and natural gas costs	76,474		133,334		86,213
Operations	178,437		164,505		148,294
FCG transaction-related expenses	10,355		—		—
Maintenance	20,401		18,176		16,793
Depreciation and amortization	65,501		68,973		62,661
Other taxes	28,625		25,611		24,158
Total operating expenses	519,801		537,771		438,856
Operating Income	150,803		142,933		131,112
Other income, net	1,438		5,051		1,720
Interest charges	36,951		24,356		20,135
Income Before Income Taxes	115,290		123,628		112,697
Income taxes	28,078		33,832		29,231
Net Income	$	87,212	$	89,796	$	83,466
Weighted Average Common Shares Outstanding:
Basic	18,370,758		17,722,227		17,558,078
Diluted	18,434,857		17,804,294		17,633,029
Earnings Per Share of Common Stock:
Basic	$	4.75	$	5.07	$	4.75
Diluted	$	4.73	$	5.04	$	4.73

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 57

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Comprehensive Income

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Net Income	$	87,212	$	89,796	$	83,466
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $11, $18 and $550, respectively	32		57		1,616
Net (loss) gain, net of tax of $(37), $243, and $93, respectively	(110)		705		262
Cash Flow Hedges, net of tax:
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(501), $(369) and $2,702, respectively	(1,322)		(934)		7,075
Reclassifications of net gain on commodity contract cash flow hedges, net of tax of $(17), $(963) and $(1,838), respectively	(44)		(2,545)		(4,813)
Net gain on interest rate swap cash flow hedges, net of tax of $165, $0, and $0, respectively	473		—		—
Reclassifications of net (gain) loss on interest rate swap cash flow hedges, net of tax of $(135), $12 and $12, respectively	(388)		35		28
Total Other Comprehensive (Loss) Income	(1,359)		(2,682)		4,168
Comprehensive Income	$	85,853	$	87,114	$	87,634

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 58

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Assets	2023		2022
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	2,418,494	$	1,802,999
Unregulated Energy	410,807		393,215
Other businesses and eliminations	30,310		29,890
Total property, plant and equipment	2,859,611		2,226,104
Less: Accumulated depreciation and amortization	(516,429)		(462,926)
Plus: Construction work in progress	113,192		47,295
Net property, plant and equipment	2,456,374		1,810,473
Current Assets
Cash and cash equivalents	4,904		6,204
Trade and other receivables	74,485		65,758
Less: Allowance for credit losses	(2,699)		(2,877)
Trade receivables, net	71,786		62,881
Accrued revenue	32,597		29,206
Propane inventory, at average cost	9,313		9,365
Other inventory, at average cost	19,912		16,896
Regulatory assets	19,506		41,439
Storage gas prepayments	4,695		6,364
Income taxes receivable	3,829		2,541
Prepaid expenses	15,407		15,865
Derivative assets, at fair value	1,027		2,787
Other current assets	2,723		428
Total current assets	185,699		193,976
Deferred Charges and Other Assets
Goodwill	508,174		46,213
Other intangible assets, net	16,865		17,859
Investments, at fair value	12,282		10,576
Derivative assets, at fair value	40		982
Operating lease right-of-use assets	12,426		14,421
Regulatory assets	96,396		108,214
Receivables and other deferred charges	16,448		12,323
Total deferred charges and other assets	662,631		210,588
Total Assets	$	3,304,704	$	2,215,037

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 59

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Capitalization and Liabilities	2023		2022
(in thousands, 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)	10,823		8,635
Additional paid-in capital	749,356		380,036
Retained earnings	488,663		445,509
Accumulated other comprehensive loss	(2,738)		(1,379)
Deferred compensation obligation	9,050		7,060
Treasury stock	(9,050)		(7,060)
Total stockholders’ equity	1,246,104		832,801
Long-term debt, net of current maturities	1,187,075		578,388
Total capitalization	2,433,179		1,411,189
Current Liabilities
Current portion of long-term debt	18,505		21,483
Short-term borrowing	179,853		202,157
Accounts payable	77,481		61,496
Customer deposits and refunds	46,427		37,152
Accrued interest	7,020		3,349
Dividends payable	13,119		9,492
Accrued compensation	16,544		14,660
Regulatory liabilities	13,719		5,031
Derivative liabilities, at fair value	354		585
Other accrued liabilities	13,362		13,618
Total current liabilities	386,384		369,023
Deferred Credits and Other Liabilities
Deferred income taxes	259,082		256,167
Regulatory liabilities	195,279		142,989
Environmental liabilities	2,607		3,272
Other pension and benefit costs	15,330		16,965
Derivative liabilities at fair value	927		1,630
Operating lease - liabilities	10,550		12,392
Deferred investment tax credits and other liabilities	1,366		1,410
Total deferred credits and other liabilities	485,141		434,825
Environmental and other commitments and contingencies (Notes 19 and 20)
Total Capitalization and Liabilities	$	3,304,704	$	2,215,037

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 60

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Operating Activities
Net Income	$	87,212	$	89,796	$	83,466
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	65,501		68,973		62,661
Depreciation and accretion included in operations expenses	11,934		11,044		10,228
Deferred income taxes, net	3,413		23,705		26,658
Realized (loss) on sale of assets/commodity contracts	(824)		(7,532)		(9,026)
Unrealized loss (gain) on investments/commodity contracts	(1,916)		1,817		(1,464)
Employee benefits and compensation	342		(1,111)		(53)
Share-based compensation	7,622		6,438		5,945
Other, net	170		—		—
Changes in assets and liabilities:
Accounts receivable and accrued revenue	2,270		(11,159)		(1,634)
Propane inventory, storage gas and other inventory	293		(7,847)		(9,517)
Regulatory assets/liabilities, net	20,102		(38,671)		(18,464)
Prepaid expenses and other current assets	18,689		9,124		(1,520)
Accounts payable and other accrued liabilities	(16,795)		2,724		8,285
Income taxes receivable	(1,288)		14,919		(4,575)
Customer deposits and refunds	3,928		664		3,176
Accrued compensation	1,462		(1,231)		1,198
Other assets and liabilities, net	1,367		(2,771)		(4,860)
Net cash provided by operating activities	203,482		158,882		150,504
Investing Activities
Property, plant and equipment expenditures	(188,618)		(128,276)		(186,924)
Proceeds from sale of assets	2,926		3,860		1,033
Acquisitions, net of cash acquired	(925,034)		(11,766)		(36,371)
Environmental expenditures	(665)		(266)		(761)
Net cash used in investing activities	(1,111,391)		(136,448)		(223,023)
Financing Activities
Common stock dividends	(40,009)		(35,147)		(31,537)
Issuance of stock for Dividend Reinvestment Plan	(28)		4,534		15,851
Proceeds from issuance of common stock, net of expenses	366,417		—		—
Tax withholding payments related to net settled stock compensation	(2,455)		(2,838)		(1,478)
Change in cash overdrafts due to outstanding checks	(301)		955		(1,154)
Net borrowings (repayments) under line of credit agreements	(22,544)		(20,608)		46,647
Proceeds from issuance of long-term debt	627,011		49,859		59,478
Repayment of long-term debt and finance lease obligation	(21,482)		(17,961)		(13,811)
Net cash provided by (used in) financing activities	906,609		(21,206)		73,996
Net (Decrease) Increase in Cash and Cash Equivalents	(1,300)		1,228		1,477
Cash and Cash Equivalents — Beginning of Period	6,204		4,976		3,499
Cash and Cash Equivalents — End of Period	$	4,904	$	6,204	$	4,976

See Note 7 for Supplemental Cash Flow Disclosures.

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

Chesapeake Utilities Corporation 2023 Form 10-K Page 61

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Stockholders' Equity

	Common Stock (1)
(in thousands, except shares and per share data)	Number of Shares (2)	Par Value		Additional Paid-In Capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Deferred Compensation		Treasury Stock		Total
Balance at December 31, 2020	17,461,841	$	8,499	$	348,482	$	342,969	$	(2,865)	$	5,679	$	(5,679)	$	697,085
Net Income	—	—		—		83,466		—		—		—		83,466
Other comprehensive income	—	—		—		—		4,168		—		—		4,168
Dividends declared ($1.880 per share)	—	—		—		(33,363)		—		—		—		(33,363)
Dividend reinvestment plan (5)	147,256	72		18,176		—		—		—		—		18,248
Share-based compensation and tax benefit (3) (4)	46,313	22		4,504		—		—		—		—		4,526
Treasury stock activities (2)	—	—		—		—		—		1,561		(1,561)		—
Balance at December 31, 2021	17,655,410	8,593		371,162		393,072		1,303		7,240		(7,240)		774,130
Net Income	—	—		—		89,796		—		—		—		89,796
Other comprehensive income	—	—		—		—		(2,682)		—		—		(2,682)
Dividends declared ($2.085 per share)	—	—		—		(37,359)		—		—		—		(37,359)
Issuance under various plans (5)	39,418	19		5,273		—		—		—		—		5,292
Share-based compensation and tax benefit (3) (4)	46,590	23		3,601		—		—		—		—		3,624
Treasury stock activities (2)	—	—		—		—		—		(180)		180		—
Balances at December 31, 2022	17,741,418	8,635		380,036		445,509		(1,379)		7,060		(7,060)		832,801
Net Income	—	—		—		87,212		—		—		—		87,212
Issuance of common stock in connection with acquisition of FCG	4,438,596	2,160		364,257		—		—		—		—		366,417
Other comprehensive loss	—	—		—		—		(1,359)		—		—		(1,359)
Dividends declared ($2.305 per share)	—	—		—		(44,058)		—		—		—		(44,058)
Issuance under various plans (5)	—	—		(26)		—		—		—		—		(26)
Share-based compensation and tax benefit (3) (4)	55,323	28		5,089		—		—		—		—		5,117
Treasury stock activities (2)	—	—		—		—		—		1,990		(1,990)		—
Balances at December 31, 2023	22,235,337	$	10,823	$	749,356	$	488,663	$	(2,738)	$	9,050	$	(9,050)	$	1,246,104

(1) 2,000,000 shares of preferred stock at $0.01 par value per share have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity.

(2) Includes 107,623, 108,143 and 116,238 shares at December 31, 2023, 2022 and 2021, 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 2023, 2022 and 2021, we withheld 19,859, 21,832 and 14,020 shares, respectively, for taxes.

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

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 62

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, North Carolina, South Carolina, 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.

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 owned by 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, 2023 and 2022 is provided in the following table:

Chesapeake Utilities Corporation 2023 Form 10-K Page 63

Notes to the Consolidated Financial Statements

	As of December 31,
(in thousands)	2023		2022
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida (1)	$	1,486,796	$	925,501
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	788,185		741,865
Electric distribution	143,513		135,633
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	194,918		185,090
Natural gas transmission and supply – Ohio	134,192		128,620
Electricity and steam generation	37,064		36,886
Mobile CNG and pipeline solutions	40,558		38,543
Sustainable energy investments, including renewable natural gas	4,076		4,076
Other	30,309		29,890
Total property, plant and equipment	2,859,611		2,226,104
Less: Accumulated depreciation and amortization	(516,429)		(462,926)
Plus: Construction work in progress	113,192		47,295
Net property, plant and equipment	$	2,456,374	$	1,810,473

(1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition.

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, 2023 and 2022, the non-refundable contributions totaled $4.2 million and $7.6 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 the years ended December 31, 2023, 2022 and 2021, AFUDC was immaterial and was reflected as a reduction of interest charges.

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.

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.

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. See Note 14, Leases, for additional information.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 64

Notes to the Consolidated Financial Statements

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, 2023, 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 $2.2 million and $1.5 million at December 31, 2023 and 2022, 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, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 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, 2023, 2022 and 2021:

	2023	2022	2021
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida (1) (2)	2.2%	2.5%	2.5%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.4%	2.4%	2.3%
Natural gas transmission – Ohio	5.0%	5.0%	N/A
Electric distribution	2.4%	2.8%	2.8%

(1) Excludes the acquisition of FCG which was completed on November 30, 2023.

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

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 2023 Form 10-K Page 65

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 2023 Form 10-K     Page 66

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.

Chesapeake Utilities Corporation 2023 Form 10-K Page 67

Notes to the Consolidated Financial Statements

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. The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2023:

(in thousands)
Balance at December 31, 2022	$	2,877
Additions:
Provision for credit losses	2,340
Recoveries	166
Deductions:
Write offs	(2,684)
Balance at December 31, 2023	$	2,699

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, 2023, 2022 or 2021.

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, 2023, 2022 and 2021. 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 18, 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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 68

Notes to the Consolidated Financial Statements

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 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 net of any valuation allowance when it is more likely than not that such income tax benefits will 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

Chesapeake Utilities Corporation 2023 Form 10-K Page 69

Notes to the Consolidated Financial Statements

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.

Recent Accounting Standards Yet to be Adopted

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

Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2024. ASU 2023-09 only impacts disclosures, and as a result, will not have a material impact on our financial position or results of operations.

3. EARNINGS PER SHARE

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

	For the Year Ended December 31,
	2023		2022		2021
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	87,212	$	89,796	$	83,466
Weighted average shares outstanding (1)	18,370,758		17,722,227		17,558,078
Basic Earnings Per Share	$	4.75	$	5.07	$	4.75
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic (1)	18,370,758		17,722,227		17,558,078
Effect of dilutive securities — Share-based compensation	64,099		82,067		74,951
Adjusted denominator — Diluted (1)	18,434,857		17,804,294		17,633,029
Diluted Earnings Per Share	$	4.73	$	5.04	$	4.73

(1) 2023 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.

4. ACQUISITIONS

Acquisition of Florida City Gas

On November 30, 2023, we completed the acquisition of FCG for $923.4 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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 70

Notes to the Consolidated Financial Statements

FCG, a regulated utility, serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe.

The purchase price of the acquisition was funded with $366.4 million of net proceeds from the issuance of 4.4 million shares of our common stock, the issuance of approximately $550.0 million principal amount of uncollateralized senior notes, and borrowings under the Company's Revolver. See Note 12, Long-Term Debt, and Note 15, Stockholders' Equity, for additional details on these financing activities.

We accounted for the acquisition of FCG using the acquisition method. At December 31, 2023, the allocation of the purchase price remains preliminary pending finalizing of certain working capital balances. As such, the fair value measurements presented below are subject to change within the measurement period not to exceed one year from the date of the acquisition. As FCG is a regulated utility, the measurement of the fair value of most of the assets acquired and liabilities assumed were determined using the predecessor’s carrying value. In certain other instances where assets and liabilities are not subject to regulation, we determined the fair value in accordance with the principles of ASC Topic 820, Fair Value Measurements.

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

The components of the preliminary purchase price allocation are as follows:

(in thousands)
Assets acquired:	Acquisition Date Fair Value
Cash	$	2,270
Accounts receivable, net	14,396
Regulatory assets - current	2,983
Other current assets	2,707
Property, plant and equipment	453,845
Goodwill	461,193
Regulatory assets - non-current	3,381
Other deferred charges and other assets,	18,309
Total assets acquired	959,084
Liabilities assumed:
Current liabilities	(20,954)
Regulatory liabilities	(14,137)
Other deferred credits and other liabilities	(548)
Total liabilities assumed	(35,639)
Net purchase price	$	923,445

Direct transaction costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges include $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 have been deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate.

For 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-related expenses described above. For additional information on FCG's results, see discussion under Item 7, Management's Discussion

Chesapeake Utilities Corporation 2023 Form 10-K Page 71

Notes to the Consolidated Financial Statements

and Analysis of Financial Condition and Results of Operations. The following unaudited financial information reflects our pro forma operating revenues and net income assuming the FCG acquisition had occurred on January 1, 2022. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the results of operations that would have been achieved or the future results of operations of FCG.

For the Year Ended December 31,
	2023		2022
(in thousands)
Operating Revenue	$	786,473	$	798,355
Net Income	$	85,398	$	81,508

Acquisition of J.T. Lee and Son's

In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $3.9 million. In connection with this acquisition, we recorded a $0.3 million liability which is subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. 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 amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the year ended December 31, 2023.

Acquisition of Planet Found Energy Development

In October 2022, we acquired Planet Found Energy Development, LLC ("Planet Found") for $9.5 million. In connection with this acquisition, we recorded a $0.9 million liability which was released after the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy segment beginning in the fourth quarter of 2022. Planet Found's farm scale anaerobic digestion pilot system and technology produces biogas from 1200 tons of poultry litter annually. The transaction accelerated our efforts in converting poultry waste to renewable, sustainable energy while simultaneously improving the local environments in our service territories.

In connection with this acquisition, we recorded $4.4 million in intangible assets associated primarily with intellectual property and non-compete agreements, $4.0 million in property plant and equipment, $1.1 million in goodwill, and less than $0.1 million in working capital, all of which are deductible for income tax purposes. The operating revenues and net income of Planet Found were not material to our consolidated results for the years ended December 31, 2023 and 2022.

Acquisition of Davenport Energy

In June 2022, Sharp acquired the propane operating assets of Davenport Energy's Siler City, North Carolina propane division for approximately $2.0 million. Through this acquisition, the Company expanded its operating footprint further into North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. Sharp added approximately 850 customers, and expected distribution of approximately 0.4 million gallons of propane annually. We recorded $1.5 million in property plant and equipment, $0.5 million in goodwill, and immaterial amounts associated with customer relationships and non-compete agreements, all of which are deductible for income tax purposes. The financial results associated with this acquisition are included within the Company's propane distribution operations within its Unregulated Energy segment. The operating revenues and net income of Davenport Energy were not material to our consolidated results for the years ended December 31, 2023 and 2022.

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 72

Notes to the Consolidated Financial Statements

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 table displays revenue by major source based on product and service type for the years ended December 31, 2023, 2022 and 2021:

	For the year ended December 31, 2023
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	83,882	$	—	$	—	$	83,882
Florida Natural Gas distribution (1)	168,360		—		—		168,360
Florida City Gas (2)	12,073		—		—		12,073
FPU electric distribution	99,474		—		—		99,474
Maryland natural gas division	28,092		—		—		28,092
Sandpiper natural gas/propane operations	20,185		—		—		20,185
Elkton Gas	8,814		—		—		8,814
Total energy distribution	420,880		—		—		420,880
Energy transmission
Aspire Energy	—		37,139		—		37,139
Aspire Energy Express	1,478		—		—		1,478
Eastern Shore	79,923		—		—		79,923
Peninsula Pipeline	30,400		—		—		30,400
Total energy transmission	111,801		37,139		—		148,940
Energy generation
Eight Flags	—		19,207		—		19,207
Propane operations
Propane distribution operations	—		154,748		—		154,748
Compressed Natural Gas Services
Marlin Gas Services	—		12,300		—		12,300
Other and eliminations
Eliminations	(59,086)		(246)		(26,321)		(85,653)
Other	—		—		182		182
Total other and eliminations	(59,086)		(246)		(26,139)		(85,471)
Total operating revenues (3)	$	473,595	$	223,148	$	(26,139)	$	670,604

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions, and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

(3) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 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 for Maryland division and Sandpiper and late fees.

Chesapeake Utilities Corporation 2023 Form 10-K Page 73

Notes to the Consolidated Financial Statements

	For the year ended December 31, 2022
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	82,176	$	—	$	—	$	82,176
Florida Natural Gas distribution (1)	155,870		—		—		155,870
FPU electric distribution	81,714		—		—		81,714
Maryland natural gas division	26,607		—		—		26,607
Sandpiper natural gas/propane operations	21,278		—		—		21,278
Elkton Gas	9,198		—		—		9,198
Total energy distribution	376,843		—		—		376,843
Energy transmission
Aspire Energy	—		56,225		—		56,225
Aspire Energy Express	1,377		—		—		1,377
Eastern Shore	78,624		—		—		78,624
Peninsula Pipeline	27,263		—		—		27,263
Total energy transmission	107,264		56,225		—		163,489
Energy generation
Eight Flags	—		25,318		—		25,318
Propane operations
Propane distribution operations	—		188,412		—		188,412
Compressed Natural Gas Services
Marlin Gas Services	—		11,159		—		11,159
Other and eliminations
Eliminations	(54,683)		(364)		(29,778)		(84,825)
Other	—		—		308		308
Total other and eliminations	(54,683)		(364)		(29,470)		(84,517)
Total operating revenues (2)	$	429,424	$	280,750	$	(29,470)	$	680,704

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 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 for Maryland division and Sandpiper and late fees.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 74

Notes to the Consolidated Financial Statements

	For the year ended December 31, 2021
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	71,195	$	—	$	—	$	71,195
Florida Natural Gas distribution (1)	134,609		—		—		134,609
FPU electric distribution	78,300		—		—		78,300
Maryland natural gas division	22,449		—		—		22,449
Sandpiper natural gas/propane operations	20,746		—		—		20,746
Elkton Gas	7,105		—		—		7,105
Total energy distribution	334,404		—		—		334,404
Energy transmission
Aspire Energy	—		38,163		—		38,163
Aspire Energy Express	187		—		—		187
Eastern Shore	76,911		—		—		76,911
Peninsula Pipeline	26,630		—		—		26,630
Total energy transmission	103,728		38,163		—		141,891
Energy generation
Eight Flags	—		18,652		—		18,652
Propane operations
Propane distribution operations	—		142,082		—		142,082
Compressed Natural Gas Services
Marlin Gas Services	—		8,315		—		8,315
Other and eliminations
Eliminations	(54,212)		(343)		(21,348)		(75,903)
Other	—		—		527		527
Total other and eliminations	(54,212)		(343)		(20,821)		(75,376)
Total operating revenues (2)	$	383,920	$	206,869	$	(20,821)	$	569,968

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 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 for Maryland division and Sandpiper and late fees.

Regulated Energy Segment

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide.

Chesapeake Utilities Corporation 2023 Form 10-K Page 75

Notes to the Consolidated Financial Statements

Revenues for Eastern Shore 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 the FERC-approved maximum rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers receive service only when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Aspire Energy Express is engaged in natural gas intrastate transmission in the State of Ohio. We currently serve the Guernsey power plant and our performance obligation is satisfied over time as the natural gas is transported to the plant. We recognize revenue based on rates approved by the Ohio PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Unregulated Energy Segment

Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Eight Flags' CHP plant, which is located on land leased from a customer, produces three sources of energy: electricity, steam and heated water. This customer purchases the steam (unfired and fired) and heated water, which are used in the customer’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.

For our propane distribution operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane distribution customers with meters, we satisfy our performance obligation over time. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane distribution metered customers, we accrue unbilled revenues for propane that is estimated to have been consumed, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Marlin Gas Services provides mobile CNG and pipeline solutions primarily to utilities and pipelines. 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. Marlin Gas Services' performance obligations are comprised of the compression of natural gas, mobilization of CNG equipment, utilization of equipment and on-site CNG support. Our performance obligations for the compression of natural gas, utilization of mobile CNG equipment and for the on-site CNG staff support are satisfied over time when the natural gas is compressed, equipment is utilized or as our staff provide support services to our customers. Our performance obligation for the mobilization of CNG equipment is satisfied at a point-in-time when the equipment is delivered to the customer project location. We recognize revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 76

Notes to the Consolidated Financial Statements

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2023 and 2022 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2022	$	61,687	$	18	$	4,321	$	983
Balance at 12/31/2023	67,741		18		3,524		1,022
Increase (decrease)	$	6,054	$	—	$	(797)	$	39

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

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2023 and 2022, the amounts recognized in revenue were not material.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2023 are expected to be recognized as follows:

(in thousands)	2024		2025		2026		2027		2028		2029 and thereafter
Eastern Shore and Peninsula Pipeline	$	36,657	$	30,330	$	26,547	$	23,433	$	22,559	$	149,124
Natural gas distribution operations	9,680		9,216		8,501		6,472		5,252		28,428
FPU electric distribution	652		275		275		275		275		—
Total revenue contracts with remaining performance obligations	$	46,989	$	39,821	$	35,323	$	30,180	$	28,086	$	177,552

6. SEGMENT INFORMATION

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief decision maker (our Chief Executive Officer, or "CEO") in order to make decisions about resources and to assess performance.

Our operations are entirely domestic and are comprised of two reportable segments:

•Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services.

Chesapeake Utilities Corporation 2023 Form 10-K Page 77

Notes to the Consolidated Financial Statements

The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

The following tables present information about our reportable segments:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	471,591	$	422,894	$	381,879
Unregulated Energy	199,013		257,810		188,089
Total operating revenues, unaffiliated customers	$	670,604	$	680,704	$	569,968
Intersegment Revenues (1)
Regulated Energy	$	2,004	$	6,530	$	2,041
Unregulated Energy	24,135		22,940		18,780
Other businesses	182		308		527
Total intersegment revenues	$	26,321	$	29,778	$	21,348
Operating Income
Regulated Energy	$	126,199	$	115,317	$	106,174
Unregulated Energy	24,426		27,350		24,427
Other businesses and eliminations	178		266		511
Operating Income	150,803		142,933		131,112
Other income, net	1,438		5,051		1,720
Interest charges	36,951		24,356		20,135
Income before Income Taxes	115,290		123,628		112,697
Income Taxes	28,078		33,832		29,231
Net Income	$	87,212	$	89,796	$	83,466
Depreciation and Amortization
Regulated Energy (2)	$	48,162	$	52,707	$	48,748
Unregulated Energy	17,347		16,257		13,869
Other businesses and eliminations	(8)		9		44
Total depreciation and amortization	$	65,501	$	68,973	$	62,661
Capital Expenditures
Regulated Energy (3)	$	1,095,871	$	97,554	$	139,733
Unregulated Energy	40,264		40,773		81,651
Other businesses	1,762		2,355		6,425
Total capital expenditures	$	1,137,897	$	140,682	$	227,809

     (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

 (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details.

 (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details.

	As of December 31,
(in thousands)	2023		2022
Identifiable Assets
Regulated Energy segment	$	2,781,581	$	1,716,255
Unregulated Energy segment	477,402		463,239
Other businesses and eliminations	45,721		35,543
Total identifiable assets	$	3,304,704	$	2,215,037

Chesapeake Utilities Corporation 2023 Form 10-K     Page 78

Notes to the Consolidated Financial Statements

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2023, 2022 and 2021 were as follows:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Cash paid for interest	$	30,525	$	24,267	$	20,809
Cash (received) paid for income taxes, net of refunds	$	21,920	$	(4,963)	$	8,395

Non-cash investing and financing activities during the years ended December 31, 2023, 2022, and 2021 were as follows: 

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31,	$	33,334	$	13,211	$	16,164
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	1,712
Common stock issued under the SICP	$	3,740	$	2,868	$	2,834

8. DERIVATIVE INSTRUMENTS

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. Occasionally, we may enter into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of December 31, 2023 and 2022, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of December 31, 2023, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	Purchases	18.1	Cash flow hedges	June 2026
Sharp	Propane (gallons)	Sales	3.2	Cash flow hedges	March 2024

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2023 through June 2026) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is initially recorded as a component of accumulated other comprehensive income (loss) and later recognized in our consolidated statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.3 million of unrealized losses from accumulated other comprehensive income (loss) to earnings during the next 12-month period.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In September 2022, we entered into an interest rate swap with a notional amount of $50.0 million through September 2025, with pricing of 3.98 percent.

Chesapeake Utilities Corporation 2023 Form 10-K Page 79

Notes to the Consolidated Financial Statements

In February 2021, we entered into an interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. In the fourth quarter of 2020, we entered into interest rate swaps with notional amounts totaling $60.0 million through December 2021 with pricing of approximately 0.20 percent for the period associated with our outstanding borrowing under the Revolver.

In August 2022, we amended and restated the Revolver and transitioned the benchmark interest rate to the 30-day SOFR as a result of the expiration of LIBOR. Accordingly, our current interest rate swap is cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate. Prior to August 2022, our short-term borrowing interest rate was based on the 30-day LIBOR rate. Our pre-2022 interest rate swaps were cash settled monthly as the counter-party paid us the 30-day LIBOR rate less the fixed rate.

We designate and account for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are initially recorded as a component of accumulated other comprehensive income (loss). As the interest rate swap settles each month, the realized gain or loss is recorded in the income statement and is recognized as a component of interest charges.

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp included within other current assets on the consolidated balance sheet with a balance of $2.1 million as of December 31, 2023 compared to a current liability of $0.1 million at December 31, 2022.

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2023 and 2022 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value (1)	$	702	$	3,317
Interest rate swap agreements	Derivative assets, at fair value (1)	365		452
Total Derivative Assets		$	1,067	$	3,769

 (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value (1)	$	1,078	$	1,810
Interest rate swap agreements	Derivative liabilities, at fair value (1)	203		405
Total Derivative Liabilities		$	1,281	$	2,215

(1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 80

Notes to the Consolidated Financial Statements

The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2023		2022		2021
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	—	$	56	$	(1)
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	—		—		(24)
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	1,221		(373)		(536)
Propane swap agreements	Propane and natural gas costs	(1,160)		3,881		7,187
Interest rate swap agreements	Interest expense	523		(47)		(40)
Total		$	584	$	3,517	$	6,586

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are as follows:

Fair Value Hierarchy	Description of Fair Value Level	Fair Value Technique Utilized
Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities	Investments - equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. Investments - mutual funds and other - The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability	Derivative assets and liabilities - The fair value of the propane put/call options, propane and interest rate swap agreements are measured using market transactions for similar assets and liabilities in either the listed or over-the-counter markets.
Level 3	Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity)	Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value.

Chesapeake Utilities Corporation 2023 Form 10-K Page 81

Notes to the Consolidated Financial Statements

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2023 and 2022, respectively:

			Fair Value Measurements Using:
As of December 31, 2023	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	1,489		—		—		1,489
Investments—mutual funds and other	10,772		10,772		—		—
Total investments	12,282		10,793		—		1,489
Derivative assets	1,067		—		1,067		—
Total assets	$	13,349	$	10,793	$	1,067	$	1,489
Liabilities:
Derivative liabilities	$	1,281	$	—	$	1,281	$	—

			Fair Value Measurements Using:
As of December 31, 2022	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	24	$	24	$	—	$	—
Investments—guaranteed income fund	1,853		—		—		1,853
Investments—mutual funds and other	8,699		8,699		—		—
Total investments	10,576		8,723		—		1,853
Derivative assets	3,769		—		3,769		—
Total assets	$	14,345	$	8,723	$	3,769	$	1,853
Liabilities:
Derivative liabilities	$	2,215	$	—	$	2,215	$	—

The changes in the fair value of our Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

At December 31, 2023 and 2022, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 82

Notes to the Consolidated Financial Statements

At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.2 billion, compared to the estimated fair value of $1.2 billion. At December 31, 2022, long-term debt, which includes the current maturities and excludes debt issuance costs, had a carrying value of $600.8 million, compared to a fair value of $505.0 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 2 measurement.

See Note 16, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

10. GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2023 and 2022 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2022	$	7,689	$	38,524	$	46,213
Additions (1)	461,025		936		461,961
Balance at December 31, 2023	$	468,714	$	39,460	$	508,174

(1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details.

There were no goodwill impairments recognized during the three-year period ended December 31, 2023.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2023 and 2022 was as follows:

	As of December 31,
	2023				2022
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	17,004	$	7,146	$	16,965	$	6,131
Non-Compete agreements	3,125		1,855		3,105		1,411
Patents (1)	6,558		859		5,819		533
Other	270		232		270		225
Total	$	26,957	$	10,092	$	26,159	$	8,300

(1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found.

The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted average of 14 years. Amortization expense of intangible assets for the year ended December 31, 2023, 2022 and 2021 was $1.8 million, $1.5 million and $1.3 million, respectively. Amortization expense of intangible assets is expected to be $1.8 million for the years 2024 through 2025, $1.6 million for 2026, $1.5 million for 2027 and $1.3 million for 2028.

11. INCOME TAXES

We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our state returns for tax years after 2017 are subject to examination. At December 31, 2023, the 2015 through 2019 federal income tax returns are no longer under examination.

For state income tax purposes, we had NOL in various states of $72.9 million and $67.7 million as of December 31, 2023 and 2022, respectively, almost all of which will expire in 2040. Excluding NOLs from discontinued operations, we have recorded deferred tax assets of $1.8 million and $1.5 million related to state NOL carry-forwards at December 31, 2023 and 2022, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized.

Tax Law Changes

Chesapeake Utilities Corporation 2023 Form 10-K Page 83

Notes to the Consolidated Financial Statements

In March 2020, the CARES Act was signed into law and included several significant changes to the Internal Revenue Code. The CARES Act includes certain tax relief provisions including the ability to carryback five years net operating losses arising in a tax year beginning in 2018, 2019, or 2020. This provision allows a taxpayer to recover taxes previously paid at a 35 percent federal income tax rate during tax years prior to 2018. In addition, the CARES Act removed the taxable income limitation to allow a tax NOL to fully offset taxable income for tax years beginning before January 1, 2021. As a result, our income tax expense for the year ended December 31, 2021 included a tax benefit $0.9 million, attributable to the tax NOL carryback provided under the CARES Act for losses generated in 2018 and 2019 and then applied back to our 2013 and 2015 tax years in which we paid federal income taxes at a 35 percent tax rate. Tax benefits associated with this legislation were not available for the year ended December 31, 2023.

On December 22, 2017, the TCJA was signed into law. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 18, Rates and Other Regulatory Activities, for further discussion of the TCJA's impact on our regulated businesses.

The following tables provide: (a) the components of income tax expense in 2023, 2022, and 2021; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2023, 2022, and 2021; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2023 and 2022.

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Current Income Tax Expense
Federal	$	14,736	$	8,284	$	2,775
State	5,496		1,948		(96)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	20,185		10,185		2,632
Deferred Income Tax Expense (1)
Property, plant and equipment	17,797		14,968		24,074
Deferred gas costs	(7,739)		8,923		1,857
Pensions and other employee benefits	(974)		1,109		(655)
FPU merger-related premium cost and deferred gain	(351)		(351)		(351)
Net operating loss carryforwards	(370)		2		97
Other	(470)		(1,004)		1,577
Total deferred income tax expense	7,893		23,647		26,599
Total Income Tax	$	28,078	$	33,832	$	29,231

(1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 84

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
	2023			2022			2021
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	24,214		$	25,982		$	23,666
State income taxes, net of federal benefit	4,377			7,714			6,371
ESOP dividend deduction	(184)			(177)			(180)
CARES Act Tax Benefit	—			—			(919)
Other	(329)			313			293
Total Income Tax Expense	$	28,078		$	33,832		$	29,231
Effective Income Tax Rate	24.35		%	27.34		%	25.94		%

(1) Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021.

	As of December 31,
	2023		2022
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	252,125	$	238,687
Acquisition adjustment	5,564		5,915
Loss on reacquired debt	145		164
Deferred gas costs	3,550		11,288
Natural gas conversion costs	4,824		5,026
Storm reserve liability	5,797		5,791
Other	9,655		8,236
Total deferred income tax liabilities	$	281,660	$	275,107
Deferred income tax assets:
Pension and other employee benefits	$	4,993	$	3,985
Environmental costs	951		1,052
Net operating loss carryforwards	1,847		1,488
Storm reserve liability	213		453
Accrued expenses	3,335		9,007
Other	11,239		2,955
Total deferred income tax assets	$	22,578	$	18,940
Deferred Income Taxes Per Consolidated Balance Sheets	$	259,082	$	256,167

Chesapeake Utilities Corporation 2023 Form 10-K Page 85

Notes to the Consolidated Financial Statements

12. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2023		2022
Uncollateralized Senior Notes:
5.93% notes, due October 31, 2023	$	—	$	3,000
5.68% notes, due June 30, 2026	8,700		11,600
6.43% notes, due May 2, 2028	3,500		4,200
3.73% notes, due December 16, 2028	10,000		12,000
3.88% notes, due May 15, 2029	30,000		35,000
3.25% notes, due April 30, 2032	59,500		66,500
3.48% notes, due May 31, 2038	50,000		50,000
3.58% notes, due November 30, 2038	50,000		50,000
3.98% notes, due August 20, 2039	100,000		100,000
2.98% notes, due December 20, 2034	70,000		70,000
3.00% notes, due July 15, 2035	50,000		50,000
2.96% notes, due August 15, 2035	40,000		40,000
2.49% notes, due January 25, 2037	50,000		50,000
2.95% notes, due March 15, 2042	50,000		50,000
5.43% notes, due March 14, 2038	80,000		—
6.39% notes, due December 2026	100,000		—
6.44% notes, due December 2027	100,000		—
6.45% notes, due December 2028	100,000		—
6.62% notes, due December 2030	100,000		—
6.71% notes, due December 2033	100,000		—
6.73% notes, due December 2038	50,000		—
Equipment security note
2.46% note, due September 24, 2031	7,633		8,517
Less: debt issuance costs	(3,753)		(946)
Total long-term debt	1,205,580		599,871
Less: current maturities	(18,505)		(21,483)
Total long-term debt, net of current maturities	$	1,187,075	$	578,388

Terms of the Senior Notes

All of our outstanding Senior Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

Senior Notes

On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG which closed during the fourth quarter of 2023. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes 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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 86

Notes to the Consolidated Financial Statements

On March 14, 2023 we issued 5.43 percent Senior Notes due March 14, 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.

Annual Maturities

Annual maturities and principal repayments of long-term debt are as follows:

Year	2024		2025		2026		2027		2028		Thereafter		Total
(in thousands)
Payments	$	18,505	$	25,528	$	134,551	$	131,674	$	136,699	$	762,376	$	1,209,333

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended these Shelf Agreements, which expanded the total borrowing capacity and extended the term of the agreements for an additional three years to 2026. The following table summarizes the current available capacity under our Shelf Agreements at December 31, 2023:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	405,000	$	(300,000)	$	—	$	105,000
MetLife Shelf Agreement	200,000		(50,000)		—		150,000
Total	$	605,000	$	(350,000)	$	—	$	255,000

13. SHORT-TERM BORROWINGS

We are authorized by our Board of Directors to borrow up to $375.0 million of short-term debt, as required. At December 31, 2023 and 2022, we had $179.9 million and $202.2 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.83 percent and 5.04 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2023.

We have entered into several amendments to our Revolver which resulted in modifications to both tranches of the facility. The most recent amendment in October 2023 allowed for a change in our funded indebtedness ratio from 65 percent to 70 percent during the quarter in which the acquisition of FCG is consummated and the quarter subsequent to the closing of the acquisition. The amendment in August 2023 served to renew the 364-day tranche of the Revolver, providing for $175.0 million of short-term debt capacity. Additionally, the amendment for borrowings under the 364-day tranche shall now 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. Further, the amendment provided that borrowings under the 364-day green loan sublimit shall now bear interest at (i) the SOFR rate plus a 10-basis point credit spread adjustment and an applicable margin of 1.00 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate plus 0.05 percent or less, solely at our discretion. The amendment entered into in 2022 served to reset the benchmark interest rate to SOFR and to eliminate a previous covenant which capped our investment limit to $150.0 million for investments where we maintain less than 50 percent ownership.

The 364-day tranche of the Revolver expires in August 2024 and the five-year tranche expires in August 2026. Borrowings under both tranches of the Revolver are 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. As of December 31, 2023, the pricing under the 364-day tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 75-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances. As of December 31, 2023, the pricing under the five-year tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 95-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances.

Chesapeake Utilities Corporation 2023 Form 10-K Page 87

Notes to the Consolidated Financial Statements

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio as described above. As of December 31, 2023, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, 2023 was $188.1 million. As of December 31, 2023, we had issued $7.0 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 15, Stockholders Equity.

For additional information on interest rate swaps related to our short-term borrowings, see Note 8, Derivative Instruments.

14. LEASES

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These lease arrangements enable us to better conduct business operations in the regions in which we operate. Office space is leased to provide adequate workspace for our employees in several locations throughout our service territories. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at December 31, 2023, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of December 31, 2023, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income:

		Year Ended
		December 31,
(in thousands)	Classification	2023		2022
Operating lease cost (1)	Operations expense	$	3,040	$	2,883

(1) Includes short-term leases and variable lease costs, which are immaterial.

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2023 and 2022:

Chesapeake Utilities Corporation 2023 Form 10-K     Page 88

Notes to the Consolidated Financial Statements

(in thousands)	Balance sheet classification	December 31, 2023		December 31, 2022
Assets
Operating lease assets	Operating lease right-of-use assets	$	12,426	$	14,421
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	2,454	$	2,552
Noncurrent
Operating lease liabilities	Operating lease - liabilities	10,550		12,392
Total lease liabilities		$	13,004	$	14,944

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2023 and 2022:

	December 31, 2023		December 31, 2022
Weighted-average remaining lease term (in years)
Operating leases	8.1		8.5
Weighted-average discount rate
Operating leases	3.5	%	3.4	%

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2023 and 2022:

	Year Ended December 31,
(in thousands)	2023		2022
Operating cash flows from operating leases	$	2,906	$	2,931

The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2023 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2024	$	2,771
2025	2,288
2026	1,774
2027	1,583
2028	1,205
Thereafter	5,243
Total lease payments	14,864
Less: Interest	(1,860)
Present value of lease liabilities	$	13,004

(1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised.

Chesapeake Utilities Corporation 2023 Form 10-K Page 89

Notes to the Consolidated Financial Statements

15. STOCKHOLDERS' EQUITY

Common Stock Issuances

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.

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and our previous ATM programs. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. There were no issuances under the DRIP in 2023. In 2022, we issued less than 0.1 million shares at an average price per share of $136.26 and received net proceeds of $4.5 million under the DRIP. Our most recent ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $75 million, expired in June 2023.

Net proceeds from share issuances under our DRIP and ATM programs are used for general corporate purposes including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Accumulated Other Comprehensive Income (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contract cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2023 and 2022. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items		Commodity Contract Cash Flow Hedges		Interest Rate Swap Cash Flow Hedges		Total
(in thousands)
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303
Other comprehensive income (loss) before reclassifications	705		(934)		—		(229)
Amounts reclassified from accumulated other comprehensive income (loss)	57		(2,545)		35		(2,453)
Net current-period other comprehensive income (loss)	762		(3,479)		35		(2,682)
As of December 31, 2022	(2,506)		1,092		35		(1,379)
Other comprehensive income (loss) before reclassifications	(110)		(1,322)		473		(959)
Amounts reclassified from accumulated other comprehensive income (loss)	32		(44)		(388)		(400)
Net current-period other comprehensive income (loss)	(78)		(1,366)		85		(1,359)
As of December 31, 2023	$	(2,584)	$	(274)	$	120	$	(2,738)

Deferred gains or losses for our commodity contract and interest rate swap cash flow hedges are recognized in earnings upon settlement and are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details. Amortization of the net loss related to the defined benefit pension plan and postretirement plans is included in the computation of net periodic costs (benefits). See Note 16, Employee Benefit Plans, for additional details.

16. EMPLOYEE BENEFIT PLANS

We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year. The changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs are recorded as a component of other comprehensive income (loss) or a regulatory asset.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 90

Notes to the Consolidated Financial Statements

Defined Benefit Pension Plans

At December 31, 2023 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake Supplemental Executive Retirement Plan ("SERP").

The FPU Pension Plan, a qualified plan, covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the FPU merger, the FPU Pension Plan was frozen with respect to additional years of service and compensation, effective December 31, 2009.

The Chesapeake SERP, a nonqualified plan, is comprised of two sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. The second sub-plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit.

The unfunded liability for all plans at both December 31, 2023 and 2022, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedules set forth the funded status at December 31, 2023 and 2022 and the net periodic cost (benefit) for the years ended December 31, 2023, 2022 and 2021 for the FPU Pension Plan and the Chesapeake SERP:

	FPU Pension Plan						Chesapeake SERP
At December 31,	2023			2022			2023			2022
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	49,941		$	67,030		$	1,659		$	2,096
Interest cost	2,495			1,781			81			50
Actuarial (gain) loss	454			(15,713)			48			(335)
Benefits paid	(3,233)			(3,157)			(152)			(152)
Benefit obligation — end of year	49,657			49,941			1,636			1,659
Change in plan assets:
Fair value of plan assets — beginning of year	46,203			58,712			—			—
Actual return on plan assets	6,462			(9,552)			—			—
Employer contributions	—			200			152			152
Benefits paid	(3,233)			(3,157)			(152)			(152)
Fair value of plan assets — end of year	49,432			46,203			—			—
Accrued pension cost / funded status	$	(225)		$	(3,738)		$	(1,636)		$	(1,659)
Assumptions:
Discount rate	5.00		%	5.25		%	4.88		%	5.00		%
Expected return on plan assets	6.00		%	6.00		%	—		%	—		%

	FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2023			2022			2021			2023			2022			2021
(in thousands)
Components of net periodic pension cost:
Interest cost	$	2,495		$	1,781		$	1,714		$	81		$	50		$	48
Expected return on assets	(2,670)			(3,430)			(3,306)			—			—			—
Amortization of actuarial loss	407			466			612			8			28			28
Total periodic cost	$	232		$	(1,183)		$	(980)		$	89		$	78		$	76
Assumptions:
Discount rate	5.25		%	2.75		%	2.50		%	5.00		%	2.50		%	2.25		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	—		%	—		%	—		%

Chesapeake Utilities Corporation 2023 Form 10-K Page 91

Notes to the Consolidated Financial Statements

During the fourth quarter of 2021, we formally terminated the Chesapeake Pension Plan. Total periodic cost for the plan during that year was $2.0 million attributable to a settlement charge.

Our funding policy provides that payments to the trust of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2023, 2022 and 2021:

	FPU Pension Plan
At December 31,	2023		2022		2021
Asset Category
Equity securities	50	%	53	%	52	%
Debt securities	49	%	38	%	38	%
Other	1	%	9	%	10	%
Total	100	%	100	%	100	%

The investment policy of the FPU Pension Plan is designed to provide the capital assets necessary to meet the financial obligations of the plan. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plan, earn a competitive return to increasingly fund a large portion of the plan’s retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain the appropriate mix of investments to reduce the risk of large losses over the expected remaining life of the plan.

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives:

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	33	%	57	%
Fixed Income (Inflation Bond and Taxable Fixed)	38	%	58	%
Foreign Equities (Developed and Emerging Markets)	3	%	7	%
Cash	0	%	5	%

Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance. At December 31, 2023 and 2022, the assets of the FPU Pension Plan were comprised of the following investments:

Chesapeake Utilities Corporation 2023 Form 10-K     Page 92

Notes to the Consolidated Financial Statements

	Fair Value Measurement Hierarchy
	For Year Ended December 31,
Asset Category	2023		2022
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	15,360	$	3,413
U.S. Mid Cap (1)	4,271		1,425
U.S. Small Cap (1)	2,518		692
International (2)	2,499		9,352
Alternative Strategies (3)	—		4,824
	24,648		19,706
Mutual Funds - Debt securities
Fixed income (4)	24,228		15,343
High Yield (4)	—		2,269
	24,228		17,612
Mutual Funds - Other
Commodities (5)	—		1,832
Real Estate (6)	—		1,709
Guaranteed deposit (7)	556		398
	556		3,939
Total Pension Plan Assets in fair value hierarchy (8)	49,432		41,257
Investments measured at net asset value (9)	—		4,946
Total Pension Plan Assets	$	49,432	$	46,203

(1) Includes funds that invest primarily in United States common stocks.

(2) Includes funds that invest primarily in foreign equities and emerging markets equities.

(3) Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

(4) Includes funds that invest in investment grade and fixed income securities.

(5) Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

(6) Includes funds that invest primarily in real estate.

(7) Includes investment in a group annuity product issued by an insurance company.

(8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

(9) Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

At December 31, 2023 and 2022, our pension plan investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees. Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy and are presented in the table above to reconcile to total pension plan assets.

The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial.

Other Postretirement Benefits Plans

We sponsor two defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. At December 31, 2023 and 2022, the funded status of the Chesapeake Postretirement Plan was $1.1 million and $0.6 million, respectively. The funded status of the FPU Medical Plan was $0.4 million and $0.7 million as of December 31, 2023 and 2022, respectively.

Chesapeake Utilities Corporation 2023 Form 10-K Page 93

Notes to the Consolidated Financial Statements

Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2023, 2022, and 2021.

As of December 31, 2023, there was $12.8 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $10.8 million and $1.2 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $3.2 million recorded in accumulated other comprehensive income (loss) and $8.7 million recorded as a regulatory asset at December 31, 2023.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset the portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2023, considering the expected lives of each of the plans. In determining the average expected return on plan assets for the FPU Pension Plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the FPU Pension Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable.

The health care inflation rate for 2023 used to calculate the benefit obligation is 5 percent for medical and 6 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5 percent for both medical and prescription drugs for the FPU Medical Plan.

Estimated Future Benefit Payments

In 2024, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.2 million are expected for the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan combined.

The schedule below shows the estimated future benefit payments for each of the plans previously described:

	FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2024	$	3,528	$	151	$	42	$	35
2025	$	3,603	$	164	$	46	$	35
2026	$	3,617	$	161	$	45	$	34
2027	$	3,616	$	158	$	48	$	33
2028	$	3,651	$	154	$	49	$	32
Years 2029 through 2033	$	17,951	$	689	$	299	$	143

(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

(2) Benefit payments are expected to be paid out of our general funds.

Retirement Savings Plan

We sponsor a 401(k) Retirement Savings Plan which is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum of six percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of ten percent. All contributions and matched funds can be invested among the mutual funds available for investment.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 94

Notes to the Consolidated Financial Statements

Employer contributions to our Retirement Savings Plan totaled $6.6 million, $6.2 million, and $5.9 million for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023, there were 798,586 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan.

Non-Qualified Deferred Compensation Plan

Members of our Board of Directors and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up to six percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of deferred compensation to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier or later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years.

All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of cash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. Deferred stock compensation may not be diversified. The participants are credited with dividends on their deferred common stock units in the same amount that is received by all other stockholders. Such dividends are reinvested into additional deferred common stock units. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheet, had a fair value of $12.3 million and $10.6 million at December 31, 2023 and 2022, respectively. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

Deferrals of officer base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares and directors' stock retainers are made in the form of deferred common stock units and are paid out in shares of our common stock, on a one-for-one basis, except that cash is paid in lieu of fractional shares. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheets and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Non-Qualified Deferred Compensation Plan totaled $9.1 million and $7.1 million at December 31, 2023 and 2022, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheet.

17. SHARE-BASED COMPENSATION PLANS

Our key employees and non-employee directors have been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted, and the number of shares to be issued at the end of the service period. We have 561,115 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2023, 2022 and 2021:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Awards to key employees	$	6,716	$	5,479	$	5,163
Awards to non-employee directors	906		959		782
Total compensation expense	7,622		6,438		5,945
Less: tax benefit	(1,947)		(1,663)		(1,535)
Share-based compensation amounts included in net income	$	5,675	$	4,775	$	4,410

Officers and Key Employees

Our Compensation Committee is authorized to grant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals and subject to SEC transfer restrictions once awarded. Our President and CEO has the right to issue awards of shares of our common stock, to other officers and key employees of the Company, contingent upon various performance goals and subject to SEC transfer restrictions.

Chesapeake Utilities Corporation 2023 Form 10-K Page 95

Notes to the Consolidated Financial Statements

We currently have several outstanding multi-year performance plans, which are based upon the successful achievement of long-term goals, growth and financial results and comprise both market-based and performance-based conditions and targets. The fair value per share, tied to a performance-based condition or target, is equal to the market price per share on the grant date. For the market-based conditions, we used a Monte Carlo valuation to estimate the fair value of each share granted.

The table below presents the summary of the stock activity for awards to all officers:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2021	197,398	$	94.15
Granted	69,620	117.61
Vested	(60,191)	90.60
Expired	(2,678)	91.42
Outstanding — December 31, 2022	204,149	103.17
Granted	80,820	126.06
Vested	(68,302)	91.59
Expired	(2,053)	94.64
Forfeited	(1,490)	113.44
Outstanding — December 31, 2023	213,124	$	117.74

During the year ended December 31, 2023, we granted awards of 80,820 shares of common stock to officers and key employees under the SICP, including awards granted in February 2023 and to key employees appointed to officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2025.

The aggregate intrinsic value of the SICP awards granted was $22.5 million, $24.1 million, and $28.8 million at December 31, 2023, 2022 and 2021, respectively. At December 31, 2023, there was $6.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2025.

In March 2023, 2022 and 2021, upon the election by certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in March 2023, 2022 and 2021 for the performance periods ended December 31, 2022, 2021, and 2020. We paid the balance of such awarded shares to each such executive officer and remitted the cash equivalent of the withheld shares to the appropriate taxing authorities. The below table presents the number of shares withheld and amounts remitted:

	For the Year Ended December 31,
	2023		2022		2021
(amounts in thousands, except shares)
Shares withheld to satisfy tax obligations	19,859		21,832		14,020
Amounts remitted to tax authorities to satisfy obligations	$	2,455	$	2,838	$	1,478

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year or less.

Our directors receive an annual retainer of shares of common stock under the SICP for services rendered through the subsequent Annual Meeting of Shareholders. Accordingly, our directors that served on the Board as of May 2023 and 2022 each received 765 and 652 shares of common stock, respectively, with a weighted average fair value of $124.12 and $130.36 per share, respectively.

At December 31, 2023, there was $0.3 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May 2024.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 96

Notes to the Consolidated Financial Statements

18. RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively.

Refer to the additional details below pertaining to the Customer Information System Regulatory Asset Petition and COVID-19 impact.

Delaware

The October 2, 2023, application for the issuance of common stock and long-term debt was unanimously approved on October 25, 2023, by the Delaware PSC.

In September 2023, the Delaware Division submitted the Energy Efficiency Rider application for natural gas with the Delaware PSC after obtaining an affirmative recommendation from the Delaware Energy Efficiency Advisory Council (“EEAC”). The application is the first in the state and applies to a portfolio of four programs including, Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and standard Offer Program in which customers can participate and allow for recovery. The evidentiary hearing on this matter is set for April 2024. If approved as filed, rates will be effective May 1, 2024.

Maryland

On October 2, 2023, Chesapeake filed a notification of the financing plans associated with the FCG acquisition with the Maryland PSC. The filing was successfully noted during the November 1, 2023, Maryland PSC administrative meeting.

Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $6.9 million; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses under the new corporate entity which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. The outcome of the application is subject to review and approval by the Maryland PSC.

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. If approved, new rates will become effective retroactively on January 1, 2023.

Ocean City Maryland Reinforcement: During the second quarter of 2022, we began construction of an extension of service into North Ocean City, Maryland. Our Delaware natural gas division and Sandpiper installed approximately 5.4 miles of pipeline across southern Sussex County, Delaware to Fenwick Island, Delaware and Worcester County, Maryland. The project reinforces our existing system in Ocean City, Maryland and enables incremental growth along the pipeline. Construction of this project was completed in the second quarter of 2023. The Company filed a natural gas rate case application with the PSC for the state of Maryland in January 2024 as discussed above.

Florida

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

Florida Natural Gas Rate Case: In May 2022, our legacy natural gas distribution businesses in Florida filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 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 rate structure across the businesses and to unify the Florida Natural Gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment

Chesapeake Utilities Corporation 2023 Form 10-K Page 97

Notes to the Consolidated Financial Statements

recorded at the time of the FPU merger in our revenue requirement; and (v) 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. The discovery process and subsequent hearings were concluded during the fourth quarter of 2022 and briefs were submitted during the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023.

FCG Natural Gas Rate Case: In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed RSAM with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. On June 23, 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied on September 12, 2023. On July 7, 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief on January 31, 2024.

The RSAM is recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM is calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve months regulatory base net operating income, which primarily includes the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items is adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. For the year ended December 31, 2023, the Company recorded decreases to asset removal costs and depreciation expense of $5.1 million as a result of the RSAM adjustment.

Beachside Pipeline Extension: 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 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida area, traveling east under the Intercoastal Waterway and southward on the barrier island. The project was placed in-service during April 2023.

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 Dt/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. The petition was approved by the Florida PSC in October 2022, and the expansion was placed into service during the third quarter of 2023.

Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operations' SPP was filed during the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. The Company filed 2024 SPPCRC projections on May 1, 2023. A hearing was held on September 12, 2023. The Commission voted to approve the projections on November 9, 2023. FPU projects to spend $13.6 million on the program in 2024.

Lake Wales Pipeline Acquisition: 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 Dt/d of firm service in the Lake Wales, Florida area. The Commission approved the petition in April 2023. Approval of the agreement allowed Peninsula Pipeline to complete the acquisition of the existing pipeline in May 2023 which is being utilized to serve both current and new natural gas customers.

GUARD: 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

Chesapeake Utilities Corporation 2023 Form 10-K     Page 98

Notes to the Consolidated Financial Statements

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.

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 Dt/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 propane community gas systems in Newberry was made in November 2023, and the Florida PSC is scheduled to vote on this in March 2024. The Company anticipates beginning the conversions of the community gas systems in the second quarter of 2024.

Amendment to Escambia County Agreement: In April of 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to an existing contract with FPU. This amendment will allow Peninsula Pipeline to construct an additional delivery point on a pipeline located in Escambia County. The additional delivery point comes at the request of an FPU customer and will be used to enhance natural gas service in the area. The amendment was approved by the Florida PSC in the third quarter of 2023.

Florida Electric Depreciation Study: The Florida PSC requires electric utilities to file a depreciation study every four years to reevaluate and set depreciation rates for the utility's plant assets. In June 2023, FPU filed a petition with the Florida PSC for approval of its proposed depreciation rates, which was approved in December 2023.

East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that 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/day and 3,400 Dts/day, respectively.

Eastern Shore

Southern Expansion Project: In January 2022, Eastern Shore submitted a prior notice filing with the FERC pursuant to blanket certificate procedures, regarding its proposal to install an additional compressor unit and related facilities at Eastern Shore's compressor station in Bridgeville, Sussex County, Delaware. The project enables Eastern Shore to provide additional firm natural gas transportation service to an existing shipper on its pipeline system. The project obtained FERC approval in December 2022 and went into service in October 2023.

Capital Cost Surcharge: In December 2022, 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 as a result of mandated highway relocation projects as well as compliance with the 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 on December 19, 2022. The combined revised surcharge became effective January 1, 2023.

Worcester Resiliency Upgrade: In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. Eastern Shore has requested certificate authorization by December 2024, with a target in-service date by the third quarter of 2025.

Various Jurisdictional Activity Related to the Joint Customer Information System Project

In July 2022, we filed a joint petition for our natural gas divisions in Maryland (Maryland Division, Sandpiper, and Elkton Gas) for the approval to establish a regulatory asset for non-capitalizable expenses related to the initial development and implementation of our new Customer Information System ("CIS") system. The petition was approved by the Maryland PSC in August 2022. A similar petition for our Florida Regulated Energy businesses was filed during the same time frame, however, the Florida PSC approved capitalization of these expenses in lieu of establishment of regulatory assets. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. We have completed the system selection process and the CIS implementation began during the first quarter of 2023.

COVID-19 Impact

Chesapeake Utilities Corporation 2023 Form 10-K Page 99

Notes to the Consolidated Financial Statements

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued to impact economic conditions, to a lesser extent, through 2021 and 2022. Chesapeake Utilities is considered an “essential business,” which allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place.

In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during the height of the pandemic. In April and May 2020, we were authorized by the Maryland and Delaware PSCs, respectively, to record regulatory assets for COVID-19 related costs which offered us the ability to seek recovery of those costs. In July 2021, the Florida PSC issued an order that approved incremental expenses we incurred due to COVID-19. The order allowed us to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021 for natural gas and electric distribution operations. The regulatory asset is being amortized over two years and is recovered through the Purchased Gas Adjustment and Swing Service mechanisms for our natural gas distribution businesses and through the Fuel Purchased Power Cost Recovery clause for our electric division. As of December 31, 2023 and 2022, our total COVID-19 regulatory asset balance was $0.2 million and $1.2 million, respectively.

Summary TCJA Table

Customer rates for our regulated business were adjusted, as approved by the regulators, prior to 2020 except for Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarized the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of December 31, 2023 and 2022:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	December 31, 2023	December 31, 2022	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Chesapeake Delaware natural gas division (Delaware PSC)	$12,038	$12,230	PSC approved amortization of ADIT in January 2019.
Chesapeake Maryland natural gas division (Maryland PSC)	$3,585	$3,703	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,487	$3,597	PSC approved amortization of ADIT in May 2018.
Florida Natural Gas distribution (Florida PSC) (1)	$26,757	$27,179	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU electric division (Florida PSC)	$4,760	$4,993	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,027	$1,059	PSC approved amortization of ADIT in March 2018.

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

Regulatory Assets and Liabilities

At December 31, 2023 and 2022, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 100

Notes to the Consolidated Financial Statements

	As of December 31,
	2023		2022
(in thousands)
Regulatory Assets
Under-recovered purchased fuel, gas and conservation cost recovery (1) (2)	$	13,696	$	43,583
Under-recovered GRIP revenue (3)	1,777		1,705
Deferred postretirement benefits (4)	10,802		13,927
Deferred conversion and development costs (1)	21,466		23,653
Acquisition adjustment (5)	31,857		25,609
Deferred costs associated with COVID-19 (6)	190		1,233
Deferred storm costs (7)	19,370		27,687
Deferred rate case expenses - current	1,171		—
Other	15,573		12,256
Total Regulatory Assets	$	115,902	$	149,653
Regulatory Liabilities
Self-insurance (8)	$	521	$	339
Over-recovered purchased fuel and conservation cost recovery (1)	12,340		3,827
Over-recovered GRIP revenue (3)	501		—
Storm reserve (8)	1,900		2,845
Accrued asset removal cost (9)	86,534		50,261
Deferred income taxes due to rate change (10)	105,055		87,690
Interest related to storm recovery (7)	536		1,207
Other	1,611		1,851
Total Regulatory Liabilities	$	208,998	$	148,020

(1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

(2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

(3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16, Employee Benefit Plans, for additional information.

(5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above.

(6) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs.

(7) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets.

(8) We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

(9) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(10) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

Chesapeake Utilities Corporation 2023 Form 10-K Page 101

Notes to the Consolidated Financial Statements

19. ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

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

MGP Sites

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

As of December 31, 2023 and 2022, we had approximately $3.6 million and $4.3 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2023 and 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs from customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval for and has recovered, through a combination of insurance and customer rates, $14.0 million of its environmental costs related to its MGP sites as of December 31, 2023.

Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial.

The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million.

20. OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

In March 2023, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2023 and expire in March 2026.

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

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

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of December 31, 2023, FPU was in compliance with all of the requirements of its supply contracts.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 102

Notes to the Consolidated Financial Statements

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

The total purchase obligations for natural gas, electric and propane supplies are as follows:

Year	2024		2025-2026		2027-2028		Beyond 2028		Total
(in thousands)
Purchase Obligations	$	86,040	$	105,082	$	83,851	$	141,287	$	416,260

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of December 31, 2023 was $35.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2023 was approximately $24.3 million with the guarantees expiring on various dates through December 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2023 was $4.0 million.

As of December 31, 2023, we have issued letters of credit totaling approximately $7.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the capacity agreement between NEXUS and Aspire, and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 2024 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future.

Chesapeake Utilities Corporation 2023 Form 10-K Page 103

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLS AND PROCEDURES.

EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES

Our Chief Executive Officer and Chief Financial Officer, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2023. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2023.

CHANGE IN INTERNAL CONTROLS

During the quarter ended December 31, 2023, other than the ongoing changes resulting from the FCG acquisition discussed below, there have been no changes in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

On November 30, 2023, we completed the acquisition of FCG. We are currently integrating processes, procedures, and internal controls related to the acquisition. See Note 4, Acquisitions, to the consolidated financial statements and Management's Report on Internal Control Over Financial Reporting for additional information related to the acquisition of FCG. The scope of that assessment excluded FCG, which we acquired on November 30, 2023. FCG's total assets and loss before taxes represented approximately 31 percent and 4 percent, respectively, of the Company’s consolidated total assets and earnings before taxes as of December 31, 2023 and for the year then ended. This exclusion is permitted based upon current guidance of the U.S. Securities & Exchange Commission.

CEO AND CFO CERTIFICATIONS

Our Chief Executive Officer and Chief Financial Officer have filed with the SEC the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2023. In addition, on May 31, 2023 our Chief Executive Officer certified to the NYSE that he was not aware of any violation by us of the NYSE corporate governance listing standards.

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. 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 GAAP. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records which in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) 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.

Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in an updated report entitled “Internal Control - Integrated Framework,” issued in May 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. The scope of that assessment excluded FCG, which we acquired on November 30, 2023. FCG's total assets and loss before taxes represented approximately 31 percent and 4 percent, respectively, of the Company’s consolidated total assets and earnings before taxes as of December 31, 2023 and for the year then ended. This exclusion is permitted based upon current guidance of the U.S. Securities & Exchange Commission.

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.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 104

Our management has evaluated and concluded that our internal control over financial reporting was effective as of December 31, 2023.

Our independent registered public accounting firm, Baker Tilly US, LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2023, as stated in its attestation report which appears under Part II, Item 8. Financial Statements and Supplementary Data. 

ITEM 9B. OTHER INFORMATION.

None.

ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE.

We have adopted a Code of Ethics that applies to our Principal Executive Officer, President, Principal Financial Officer, Principal Accounting Officer, Treasurer, Assistant Treasurer, Corporate Controller and persons performing similar functions, which is a “code of ethics” as defined by applicable rules of the SEC. This Code of Ethics is publicly available on our website at https://www.chpk.com. If we make any amendments to this code other than technical, administrative or other non-substantive amendments, or grant any waivers, including implicit waivers, from a provision of this code to the individuals and roles noted above, or persons performing similar functions, we intend to disclose the nature of the amendment or waiver, its effective date and to whom it applies by posting such information on our website at the address and location specified above.

The remaining information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Election of Directors (Proposal 1),” “Governance Trends and Director Education," "Corporate Governance Practices,” “Board of Directors and its Committees” and “Delinquent Section 16(a) Reports.”

ITEM 11. EXECUTIVE COMPENSATION.

The information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Director Compensation,” “Executive Compensation” and “Compensation Discussion and Analysis".

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.

The information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Security Ownership of Certain Beneficial Owners and Management” and "Equity Compensation Plan Information."

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.

The information required by this Item is incorporated herein by reference to the section of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Corporate Governance Practices” and "Director Independence."

ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.

The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Fees and Services of Independent Registered Public Accounting Firm." The Company's independent registered public accounting firm is Baker Tilly US, LLP, PCAOB ID: (23)

Chesapeake Utilities Corporation 2023 Form 10-K Page 105

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

The following documents are filed as part of this Annual Report:

(a)(1) All of the financial statements, reports and notes to the financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.

(a)(2) Schedule II—Valuation and Qualifying Accounts.

(a)(3) The Exhibits below.

•     Exhibit 2.1	Stock Purchase Agreement, dated September 26, 2023, by and among Florida Power & Light Company and Chesapeake Utilities Corporation (incorporated by reference to the Company’s Current Report on Form 8-K filed with the SEC on September 27, 2023).
•     Exhibit 3.1	Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q for the period ended June 30, 2010, File No. 001-11590.
•     Exhibit 3.2	Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective May 3, 2023, are incorporated herein by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 3, 2023, File No. 001-11590.
•     Exhibit 3.3	Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 9, 2017, File No. 001-11590.
•     Exhibit 3.4	Certificate of Elimination of Series A Participating Cumulative Preferred Stock of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.6 to our Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-11590.
•     Exhibit 3.4	Note Purchase Agreement, dated November 20, 2023, by and among Chesapeake Utilities Corporation and the purchasers party thereto (incorporated by reference to the Company’s Current Report on Form 8-K filed with the SEC on November 21, 2023).
•     Exhibit 4.2	Note Agreement dated June 29, 2010, among Chesapeake Utilities Corporation, as issuer, Metropolitan Life Insurance Company and New England Life Insurance Company, relating to the private placement of Chesapeake Utilities Corporation’s 5.68% Senior Notes due 2026 and Chesapeake Utilities Corporation’s 6.43% Senior Notes due 2028.†
•     Exhibit 4.3	Note Agreement dated September 5, 2013, among Chesapeake Utilities Corporation, as issuer, and certain note holders, relating to the private placement of Chesapeake Utilities Corporation’s 3.73% Senior Notes due 2028 and Chesapeake Utilities Corporation’s 3.88% Senior Notes due 2029.†
•     Exhibit 4.4	Private Shelf Agreement dated October 8, 2015, between Chesapeake Utilities Corporation, as issuer, and Prudential Investment Management Inc., relating to the private placement of Chesapeake Utilities Corporation's 3.25% Senior Notes due 2032, 3.98% Senior Notes due 2039, 3.0% Senior Notes due 2035, and the sale of other Chesapeake Utilities Corporation unsecured Senior Notes from time to time, is incorporated herein by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2015, File No. 001-11590.
•     Exhibit 4.5	First Amendment to Private Shelf Agreement dated September 14, 2018, between Chesapeake Utilities Corporation, as issuer, and PGIM, Inc. (formerly known as Prudential Investment Management, Inc.), and other purchasers that may become party thereto. †
•     Exhibit 4.6	Master Note Agreement dated March 2, 2017, among Chesapeake Utilities Corporation, as issuer, NYL Investors LLC, and other certain note holders that may become party thereto from time to time relating to the private placement of Chesapeake Utilities Corporation’s 3.48% Senior Notes due 2038 and Chesapeake Utilities Corporation’s 3.58% Senior Notes due 2038, and Chesapeake Utilities Corporation’s 2.96% Senior Notes due 2035. †

Chesapeake Utilities Corporation 2023 Form 10-K     Page 106

•     Exhibit 4.7	Note Purchase Agreement, dated August 25, 2021, by and among Chesapeake Utilities Corporation, MetLife Insurance K.K., Thrivent Financial For Lutherans, CMFG Life Insurance Company, and American Memorial Life Insurance Company relating to the placement of Chesapeake Utilities Corporation's 2.49% Senior Notes due 2037. †
•     Exhibit 4.8	Private Shelf Agreement, dated March 2, 2017, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC, relating to the private placement of Chesapeake Utilities Corporation’s 2.95% Senior Notes due 2042.†
•     Exhibit 4.9	First Amendment to Private Shelf Agreement, dated May 14, 2020, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC. †
•     Exhibit 4.10	Third Amendment to Private Shelf Agreement dated February 8, 2023, between Chesapeake Utilities Corporation, as issuer, and PGIM, Inc. (formerly known as Prudential Investment Management, Inc.), and other purchasers that may become party thereto is filed herewith.
•     Exhibit 4.11	Second Amendment to Private Shelf Agreement, dated February 21, 2023, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC is filed herewith.
• Exhibit 4.12	Description of Chesapeake Utilities Corporation's Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, is incorporated by reference to Exhibit 4.10 of our Annual Report on Form 10-K for the year ended December 31, 2021, File No. 001-11590.
•     Exhibit 10.1*	Chesapeake Utilities Corporation Cash Bonus Incentive Plan, effective January 1, 2015, is incorporated herein by reference to our Proxy Statement dated March 31, 2015, in connection with our Annual Meeting held on May 6, 2015, File No. 001-11590.
•     Exhibit 10.2*	Non-Qualified Deferred Compensation Plan, effective January 1, 2014, is incorporated herein by reference to Exhibit 10.8 of our Annual Report on Form 10-K for the year ended December 31, 2013, File No. 001-11590.
•     Exhibit 10.3*	Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.27 of our Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
•     Exhibit 10.4*	First Amendment to the Chesapeake Utilities Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.30 of our Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-11590.
•     Exhibit 10.5	Revolving Credit Agreement dated October 8, 2015, between Chesapeake Utilities Corporation and PNC Bank, National Association, Bank of America, N.A., Citizens Bank N.A., Royal Bank of Canada and Wells Fargo Bank, National Association as lenders, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2015, File No. 001-11590.
•     Exhibit 10.6	First Amendment dated February 25, 2016 to the Revolving Credit Agreement dated October 8, 2015, between Chesapeake Utilities Corporation and PNC Bank, National Association, Bank of America, N.A., Citizens Bank N.A., Royal Bank of Canada and Wells Fargo Bank, National Association as lenders, is incorporated herein by reference to Exhibit 10.24 of our Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-11590.
•     Exhibit 10.7	Credit Agreement, dated November 28, 2017, by and between Chesapeake Utilities Corporation and Branch Banking and Trust Company is incorporated herein by reference to Exhibit 10.20 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.
•     Exhibit 10.8*	Form of Performance Share Agreement, effective February 25, 2019 for the period January 1, 2019 to December 31, 2021, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and Jeffry M. Householder is incorporated herein by reference to Exhibit 10.24 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.

Chesapeake Utilities Corporation 2023 Form 10-K Page 107

•      Exhibit 10.9	Note Agreement dated September 28, 2022, among Chesapeake Utilities Corporation, as issuer, PGIM, Inc. (formerly known as Prudential Investment Management, Inc.) and each of its affiliates relating to the private placement of Chesapeake Utilities Corporation's 5.43% Senior Notes due 2038.†
•      Exhibit 10.10*	Executive Retirement Agreement dated October 9, 2019, between Chesapeake Utilities Corporation and Stephen C. Thompson is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-11590.
•      Exhibit 10.11	Note Purchase Agreement dated November 19, 2019, between Chesapeake Utilities Corporation, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Berkshire Life Insurance Company of America, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and CMFG Life Insurance Company is incorporated herein by reference to our Current Report on Form 8-K filed on November 20, 2019, File No. 001-11590.
•      Exhibit 10.12*	Form of Performance Share Agreement, effective December 3, 2019 for the period 2019 to 2021, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty and Kevin Webber is incorporated herein by reference to Exhibit 10.26 to our Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-11590.
•      Exhibit 10.13*	Form of Performance Share Agreement dated February 22, 2023 for the period 2023-2025, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin Webber and Jeffrey S. Sylvester is incorporated herein by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2022. File No. 001-11590
•      Exhibit 10.14*	Form of Performance Share Agreement, effective February 25, 2020 for the period 2020 to 2022, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty and Kevin Webber is incorporated herein by reference to Exhibit 10.28 to our Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-11590.
• Exhibit 10.15*	Form of Performance Share Agreement, effective February 24, 2021, for the period 2021 to 2023, pursuant to the Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin Webber, and Jeffrey S. Sylvester is incorporated herein by reference to Exhibit 10.18 to our Annual Report on Form 10-K for the year ended December31, 2021, File No. 001-11590.
• Exhibit 10.16	Loan Agreement dated April 24, 2020, between Chesapeake Utilities Corporation and PNC Bank, National Association is incorporated herein by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.17	Loan Agreement dated April 27, 2020, between Chesapeake Utilities Corporation and Bank of America, N.A. is incorporated herein by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.18	Revolving Line of Credit Note dated April 24, 2020 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is incorporated herein by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.19	Promissory Note dated April 22, 2020, issued by Chesapeake Utilities Corporation and in favor of Bank of America, N.A. is incorporated herein by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.20	Credit Agreement dated May 29, 2020, between Chesapeake Utilities Corporation and Citizens Bank National Association is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 108

• Exhibit 10.21	Loan Agreement dated May 6, 2020 between Chesapeake Utilities Corporation and Royal bank of Canada is incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.22	Form of Revolving Loan Note in favor of Citizens Bank National Association is incorporated herein by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.23	Form of Revolving Credit Note in favor of Royal Bank of Canada is incorporated herein by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.24	Credit Agreement, dated September 30, 2020, by and between Chesapeake Utilities Corporation, PNC Bank, National Association, and several other financial institutions named therein is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, File No. 001-11590.
• Exhibit 10.25	Amended and Restated Credit Agreement, dated August 12, 2021, by and between Chesapeake Utilities Corporation, PNC Bank, National Association, and several other financial institutions named therein is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, File No. 001-11590
• Exhibit 10.26*	Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Jeffrey S. Sylvester is incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590
• Exhibit 10.27*	Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Jeffry M. Householder is incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590
• Exhibit 10.28*	Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Beth W. Cooper is incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590
• Exhibit 10.29*	Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and James F. Moriarty is incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590
• Exhibit 10.30*	Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Kevin J. Webber is incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590
• Exhibit 10.31*	Form of Performance Share Agreement, effective February 23, 2022, for the period 2022 to 2024, pursuant to the Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin J. Webber, and Jeffrey S. Sylvester is incorporated herein by reference to Exhibit 10.34 to our Annual Report on Form 10-K for the year ended December 31, 2021, File No. 001-11590.
• Exhibit 10.32*	Chesapeake Utilities Corporation 2023 Stock and Incentive Compensation Plan as approved by stockholders and effective on May 3, 2023 is incorporated herein by reference to Exhibit 10.1 to our Registration Statement on Form S-8 filed May 3, 2023, File No. 001-11590.
• Exhibit 10.33*	Second Amendment to the Non-Qualified Deferred Compensation Plan, effective October 2, 2023, is filed herewith.
• Exhibit 10.34*	Form of Amendment to the Executive Employment Agreement, effective October 2, 2023, for each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin J. Webber and Jeffrey S. Sylvester is filed herewith.
• Exhibit 10.35	Second Amendment to Amended and Restated Credit Agreement, dated August 9, 2023, by and between Chesapeake Utilities Corporation and PNC Bank, National Association, and several other financial institutions is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2023, File No. 001-11590.

Chesapeake Utilities Corporation 2023 Form 10-K Page 109

• Exhibit 10.36	Commitment Letter for Bridge Facility, dated September 26, 2023, by and between Chesapeake Utilities Corporation and Barclays Bank PLC is incorporated herein by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q for the period ended September 30, 2023, File No. 001-11590.
• Exhibit 10.37	Third Amendment to Amended and Restated Credit Agreement, dated October 13, 2023, by and between Chesapeake Utilities Corporation and PNC Bank, National Association is incorporated herein by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q for the period ended September 30, 2023, File No. 001-11590.
•       Exhibit 21	Subsidiaries of the Registrant is filed herewith.
•       Exhibit 23.1	Consent of Independent Registered Public Accounting Firm is filed herewith.
•       Exhibit 31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
•       Exhibit 32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
• Exhibit 97	Chesapeake Utilities Corporation Incentive-Based Compensation Clawback Policy effective October 2, 2023, is filed herewith.
•       Exhibit 101.INS XBRL Instance Document is filed herewith.
•       Exhibit 101.SCH XBRL Taxonomy Extension Schema Document is filed herewith.
•       Exhibit 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document is filed herewith.
•       Exhibit 101.DEF XBRL Taxonomy Extension Definition Linkbase Document is filed herewith.
•       Exhibit 101.LAB XBRL Taxonomy Extension Label Linkbase Document is filed herewith.
•       Exhibit 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document is filed herewith.
•       Exhibit 104	Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101.

*	Management contract or compensatory plan or agreement.
†	These agreements have not been filed herewith pursuant to Item 601(b)(4)(v) of Regulation S-K under the Securities Act of 1933, as amended. We hereby agree to furnish copies to the SEC upon request.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 110

ITEM 16. FORM 10-K SUMMARY.

None.

SIGNATURES

Pursuant to the requirements of Section 13 or 15 (d) of the Securities Exchange Act of 1934, Chesapeake Utilities Corporation has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CHESAPEAKE UTILITIES CORPORATION
By:	/s/ JEFFRY M. HOUSEHOLDER
	Jeffry M. Householder
	President, Chief Executive Officer and Director
	February 21, 2024

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. 

/s/ JEFFRY M. HOUSEHOLDER	/S/ BETH W. COOPER
Jeffry M. Householder	Beth W. Cooper, Executive Vice President,
President, Chief Executive Officer and Director	Chief Financial Officer, Treasurer
February 21, 2024	and Assistant Corporate Secretary
	(Principal Financial and Accounting Officer)
	February 21, 2024
/S/ LISA G. BISACCIA	/S/ LILA A. JABER
Lisa G. Bisaccia, Director	Lila A. Jaber, Director
February 21, 2024	February 21, 2024
/S/ THOMAS J. BRESNAN	/S/ PAUL L. MADDOCK, JR.
Thomas J. Bresnan, Lead Director	Paul L. Maddock, Jr., Director
February 21, 2024	February 21, 2024
/S/ RONALD G. FORSYTHE, JR.	/S/ SHEREE M. PETRONE
Dr. Ronald G. Forsythe, Jr., Director	Sheree M. Petrone, Director
February 21, 2024	February 21, 2024
/S/ STEPHANIE N. GARY
Stephanie N. Gary, Director
February 21, 2024
/S/ THOMAS P. HILL, JR.
Thomas P. Hill, Jr., Director
February 21, 2024
/S/ DENNIS S. HUDSON, III
Dennis S. Hudson, III, Director
February 21, 2024

Chesapeake Utilities Corporation 2023 Form 10-K Page 111

Chesapeake Utilities Corporation and Subsidiaries

Schedule II

Valuation and Qualifying Accounts

			Additions
For the Year Ended December 31,	Balance at Beginning of Year		Charged to Income		Other Accounts (1)		Deductions (2)		Balance at End of Year
(in thousands)
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
2023	$	2,877	$	2,340	$	166	$	(2,684)	$	2,699
2022	$	3,141	$	1,550	$	172	$	(1,986)	$	2,877
2021	$	4,785	$	134	$	(125)	$	(1,653)	$	3,141

(1) Recoveries and other allowance adjustments.

(2) Uncollectible accounts charged off.

Chesapeake Utilities Corporation 2023 Form 10-K     Page 112

EX-10.33

SECOND AMENDMENT

TO THE

CHESAPEAKE UTILITIES CORPORATION

NON-QUALIFIED DEFERRED COMPENSATION PLAN

(As Amended and Restated Effective January 1, 2014)

Chesapeake Utilities Corporation (the “Company”) hereby adopts this Second Amendment to the Chesapeake Utilities Corporation Non-Qualified Deferred Compensation Plan, as amended and restated effective January 1, 2014 (the “Plan”), as set forth herein.

BACKGROUND INFORMATION

A.The Company maintains the Plan for the benefit of its eligible officers, directors, and employees.

B.The Company desires to amend the Plan to implement the clawback rules found in Section 954 of the Dodd-Frank Wall Street Reform and Consumer Protection Act of 2010, Section 10D of the Securities Exchange Act of 1934, 17 C.F.R. §240.10D, and NYSE Listing Rule 303A.14, which will take effect on October 2, 2023.

C.Section 7.1 of the Plan permits the Company to amend the Plan at any time through action of the Board of Directors, the Compensation Committee of the Board of Directors, or the Employee Benefits Committee (to the extent the Board of Directors or Compensation Committee of the Board of Directors has delegated authority to amend the Plan to the Employee Benefits Committee).

AMENDMENT

The Plan is hereby amended as follows, effective October 2, 2023:

1.A new Section 8.12 is hereby added to the Plan to read as follows:

    “8.12    Application of Clawback Policy. All benefits under the Plan shall be subject to reduction, cancellation, forfeiture, or recoupment to the extent necessary to comply with (a) any clawback, forfeiture, or other similar policy adopted by the Board or Committee and as in effect from time to time; and (b) applicable law. Further, to the extent that the Participant receives any amount in excess of the amount that the Participant should otherwise have received under the Plan for any reason (including, without limitation, by reason of a financial restatement, mistake in calculations, or other administrative error), the Participant shall be required to repay any such excess amount to the Company.”

2.The Plan shall otherwise remain unchanged.

                            CHESAPEAKE UTILITIES CORPORATION

                            By:

                            Title:

                            Date:

1

EX-10.34

AMENDMENT TO EXECUTIVE EMPLOYMENT AGREEMENT

    This Amendment to the Executive Employment Agreement is made and entered into by and between Chesapeake Utilities Corporation, a Delaware corporation (the “Company”) and _______________ (the “Executive”).

BACKGROUND INFORMATION

    A.    The Company is currently obtaining the benefit of the Executive’s services as a full-time executive employee in the capacity of ____________________Officer.

B.    The Company and the Executive entered into an Executive Employment Agreement effective _______________ (the “Agreement”).

C.    Effective as of October 2, 2023, the Company is required to comply with the clawback rules found in 17 C.F.R. §240.10D and associated Section 303A.14 of the NYSE Listed Company Manual (collectively, the “Rule”), which requires issuers to develop and implement a policy providing for the recovery of erroneously awarded incentive based compensation received by current or former executive officers.

    D.    Under Section 5(d) of the Agreement, the Company may unilaterally amend such Section at any time to comply with applicable law or securities exchange listing rules, as the same may be in effect from time to time, during the current term or the extended term of the Agreement.

E.    The Company desires to amend the Agreement to reflect those changes required by the Rule.

AMENDMENT

    1.    The Company hereby amends and restates Section 5(d) of the Agreement in its entirety to provide as follows:

(d)    Recovery of Compensation. The Executive acknowledges and agrees that all or any portion of an incentive award under the above described bonus and incentive compensation plans or any future arrangement established by the Company to provide incentive or bonus compensation, whether payable in cash, Company common stock or other property, (“Award”) is subject to the clawback rules found in 17 C.F.R. §240.10D, Section 303A.14 of the NYSE Listed Company Manual, and any clawback, forfeiture, or other similar policy adopted by the Compensation Committee of the Board of Directors and as in effect from time to time (collectively, the “Rule”). The Executive acknowledges and agrees that, under the Rule, the Executive is subject to an obligation of repayment to the Company if the amount of the Award was calculated based upon the achievement of certain financial results (as reflected in the financial statement of the Company or otherwise) or other performance metrics that, in either case, were subsequently found to be materially inaccurate for any reason (including, without limitation, by reason of a financial restatement, mistake in calculations, or other administrative error). The amount that shall be repaid by the Executive to the Company shall be based on the excess amount paid or awarded to the Executive under the Award as compared to the amount that would have been paid or awarded had the material inaccuracy not occurred. If the Compensation Committee determines that the Executive engaged in misconduct, malfeasance or gross negligence in the performance of his or her duties that either caused or significantly contributed to the material inaccuracy in financial statements or other performance metrics, there shall be no time limit on this right of recovery, which shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this Agreement. In all other circumstances, this right of recovery shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this agreement for a period not exceeding three years after the date of receipt of each such Award. In addition, the Executive hereby agrees that, if he or she does not

promptly repay the amount recoverable hereunder within thirty (30) days of a demand therefore, such amount may be withheld from compensation of any type not yet due and payable to the Executive, including, but not limited to, the cancellation of future Awards, as determined by the Compensation Committee in its sole discretion. In addition, to the extent permitted under the Rule, the Compensation Committee is granted the discretionary authority to interpret and enforce this provision as it determines to be in the best interest of the Company and equitable to the parties. Notwithstanding anything herein, this provision shall not be the Company’s exclusive remedy with respect to such matters. In addition, the parties agree that the Company may unilaterally amend this provision at any time to comply with applicable law or securities exchange listing rules, as the same may be in effect from time to time, during the Current Term or the Extended Term of this Agreement.

2.    This Amendment shall be deemed effective October 2, 2023 (the “Effective Date”) and this Amendment shall govern the terms and conditions of the Agreement and the relations between the Parties as of the Effective Date.

3.    Except as provided in this Amendment, all terms and conditions of the Agreement shall remain in effect and shall not be altered by this Amendment.

IN WITNESS WHEREOF, the parties hereto have executed this Amendment as of the date(s) indicated below.

CHESAPEAKE UTILITIES CORPORATION

By: _______________________________

Title: ______________________________

Date: _____________________________

2

EX-21

EXHIBIT 21

Chesapeake Utilities Corporation

Subsidiaries of the Registrant

Subsidiaries	State Incorporated
Eastern Shore Natural Gas Company	Delaware
Sharp Energy, Inc.	Delaware
Chesapeake Service Company	Delaware
Chesapeake OnSight Services LLC	Delaware
Peninsula Energy Services Company, Inc.	Delaware
Peninsula Pipeline Company, Inc.	Delaware
Florida Public Utilities Company	Florida
Sandpiper Energy, Inc.	Delaware
Aspire Energy of Ohio, LLC	Delaware
Aspire Energy Express, LLC	Delaware
Marlin Gas Services, LLC	Delaware
CPK Elkton, LLC	Delaware
Elkton Gas Company	Maryland
OnSight Renewables, LLC	Delaware
Chesapeake Emergency Energy Recipient Program, Inc	Delaware
CUC Shared Services, Inc.	Delaware
Pivotal Utility Holdings, Inc.	New Jersey
Subsidiary of Sharp Energy, Inc.	State Incorporated
Sharpgas, Inc.	Delaware
Subsidiary of Florida Public Utilities Company	State Incorporated
Flo-Gas Corporation	Florida
FPU Renewables, LLC	Delaware
Subsidiaries of Chesapeake Service Company	State Incorporated
Skipjack, Inc.	Delaware
Chesapeake Investment Company	Delaware
Eastern Shore Real Estate, Inc.	Delaware
Subsidiaries of Chesapeake OnSight Services LLC	State Incorporated
Eight Flags Energy, LLC	Delaware
Amelia Island Energy, LLC	Delaware
Subsidiaries of OnSight Renewables, LLC	State Incorporated
Amelia Renewables, LLC	Delaware
Blue Peake LNG, LLC	Delaware
Marlin Compression, LLC	Delaware
Subsidiary of Amelia Renewables, LLC	State Incorporated
Planet Found Energy Development, LLC	Maryland

EX-23.1

EXHIBIT 23.1

CONSENTOF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We hereby consent to the incorporation by reference in the Registration Statements on Form S-3ASR (Nos. 333-274284 and 333-274203), Form S-8 (No. 333-271610) and Form S-4 (No. 333-201992) of Chesapeake Utilities Corporation of our report dated February 21, 2024, relating to the consolidated financial statements, financial statement schedule, and the effectiveness of internal control over financial reporting, which appears in this Form 10-K for the year ended December 31, 2023.

/s/ Baker Tilly US, LLP

Lancaster, Pennsylvania

February 21, 2024

EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Jeffry M. Householder, certify that:

1.I have reviewed this annual report on Form 10-K for the year ended December 31, 2023 of Chesapeake Utilities Corporation;

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

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

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

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

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

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

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

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

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

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

Date: February 21, 2024

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder
President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1.I have reviewed this annual report on Form 10-K for the year ended December 31, 2023 of Chesapeake Utilities Corporation;

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

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

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

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

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

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

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

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

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

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

Date: February 21, 2024

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President, Chief Financial Officer,Treasurer, and Assistant Corporate Secretary

EX-32.1

EXHIBIT 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Jeffry M. Householder, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation for the year ended December 31, 2023, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake Utilities Corporation.

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder

February 21, 2024

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

EX-32.2

EXHIBIT 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Executive Vice President, Chief Financial Officer, Treasurer and Assistant Corporate Secretary of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Annual Report on Form 10-K of Chesapeake Utilities Corporation for the year ended December 31, 2023, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake Utilities Corporation.

/S/ BETH W. COOPER

Beth W. Cooper

February 21, 2024

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

EX-97

CHESAPEAKE UTILITIES CORPORATION

INCENTIVE-BASED COMPENSATION CLAWBACK POLICY

Chesapeake Utilities Corporation (the “Company”) has adopted this Incentive-Based Compensation Clawback Policy (the “Policy”) as a supplement to any other clawback policies in effect now or in the future at the Company. To the extent this Policy applies to compensation payable to a person covered by this Policy, it shall be the only clawback policy applicable to such compensation and no other clawback policy shall apply; provided that, if such other policy provides that a greater amount of such compensation shall be subject to clawback, such other policy shall apply to the amount in excess of the amount subject to clawback under this Policy.

This Policy shall be interpreted to comply with the clawback rules found in 17 C.F.R. §240.10D and NYSE Listing Rule 303A.14, which will take effect on October 2, 2023 (collectively, the “Rule”). To the extent this Policy is in any manner deemed inconsistent with the Rule, this Policy shall be treated as retroactively amended to be compliant with the Rule.

1. Definitions. As used in the Policy, the following capitalized terms shall have the meanings set forth in this Section 1. Terms used herein shall at all times be interpreted in accordance with 17 C.F.R. §240.10D-1(d) and any other guidance that may be issued under the Rule.

(a) “Executive Officer” shall mean the Company’s president, principal financial officer, principal accounting officer, any vice president of the Company in charge of a principal business unit, division, or function (such as sales, administration, or finance), any other officer who performs a policy-making function, or any other person who performs similar policy-making functions for the Company. Executive Officers of the Company’s subsidiaries are deemed Executive Officers of the Company if they perform such policy-making functions for the Company. Identification of an Executive Officer for purposes of this Policy includes, at a minimum, Executive Officers identified pursuant to 17 C.F.R. §229.401(b).

(b) “Financial Reporting Measure” means measures, including but not limited to stock price and total shareholder return, that are determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, and any measures that are derived wholly or in part from such measures. A Financial Reporting Measure need not be presented within the financial statements or included in a filing with the Securities and Exchange Commission (“SEC”).

(c) “Incentive-Based Compensation” means any compensation that is granted, earned, or vested based wholly or in part upon the attainment of a Financial Reporting Measure.

2. Application of the Policy. This Policy shall only apply in the event that the Company is required to prepare an accounting restatement due to the material noncompliance of the Company with any financial reporting requirement under the securities laws, including any required accounting restatement to correct an error in previously issued financial statements that is material to the previously issued financial statements, or that would result in a material misstatement if the error were corrected in the current period or left uncorrected in the current period.

3. Recovery Period. The Incentive-Based Compensation subject to clawback is the Incentive-Based Compensation Received during the three completed fiscal years immediately preceding the date that the Company is required to prepare an accounting restatement as described in Section 2, provided that the person served as an Executive Officer at any time during the performance period applicable to the Incentive-Based Compensation in question. The date that the Company is required to prepare an accounting restatement shall be determined pursuant to 17 C.F.R. §240.10D-1(b)(1)(ii).

(a) For purposes of this Policy, Incentive-Based Compensation is deemed “Received” in the Company’s fiscal period during which the Financial Reporting Measure specified in the Incentive-Based Compensation award is attained, even if the payment or grant of the Incentive-Based Compensation occurs after the end of that period.

(b) Notwithstanding anything to the contrary, the Policy shall only apply if the Incentive-Based Compensation is Received (1) on or after October 2, 2023, and (2) while the Company has a class of securities listed on a national securities exchange or a national securities association.

(c) To the extent applicable, 17 C.F.R. §240.10D-1(b)(1)(i) shall govern certain circumstances under which the Policy will apply to Incentive-Based Compensation Received during a transition period arising due to a change in the Company’s fiscal year.

4. Erroneously Awarded Compensation. The amount of Incentive-Based Compensation subject to the Policy (“Erroneously Awarded Compensation”) is the amount of Incentive-Based Compensation Received that exceeds the amount of Incentive Based-Compensation that otherwise would have been Received had it been determined based on

the restated amounts and shall be computed without regard to any taxes paid. For Incentive-Based Compensation based on stock price or total shareholder return, where the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in an accounting restatement:

(a) the amount shall be based on a reasonable estimate of the effect of the accounting restatement on the stock price or total shareholder return upon which the Incentive-Based Compensation was received; and

(b) the Company must maintain documentation of the determination of that reasonable estimate and provide such documentation to the New York Stock Exchange (“NYSE”).

5. Recovery of Erroneously Awarded Compensation. The Company shall recover in a reasonably prompt manner any Erroneously Awarded Compensation except to the extent that the conditions of paragraphs (a), (b), or (c) below apply. The Compensation Committee of the Company’s Board of Directors (the “Committee”) shall determine the repayment schedule for each amount of Erroneously Awarded Compensation in a manner that complies with this “reasonably promptly” requirement. Such determination shall be consistent with any applicable legal guidance, by the SEC, judicial opinion, or otherwise. The determination of “reasonably promptly” may vary from case to case and the Committee is authorized to adopt additional requirements to further describe what repayment schedules satisfy this requirement.

(a) Erroneously Awarded Compensation need not be recovered if the direct expense paid to a third party to assist in enforcing the Policy (e.g., reasonable legal expenses and consulting fees) would exceed the amount to be recovered and the Committee makes a determination that recovery would be impracticable. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on the expense of enforcement, the Company shall make a reasonable attempt to recover such Erroneously Awarded Compensation, establish that the direct costs of recovery exceed the recovery amounts, document such reasonable attempt(s) to recover the amounts, and provide that documentation to the NYSE.

(b) Erroneously Awarded Compensation need not be recovered if recovery would violate home country law where that law was adopted prior to November 28, 2022. Before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation based on violation of home country law, the Company shall obtain an opinion of home country counsel, acceptable to the NYSE, that recovery would result in such a violation and shall provide the opinion to the NYSE.

(c) Erroneously Awarded Compensation need not be recovered if recovery would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company or its subsidiaries, to fail to meet the requirements of Sections 401(a)(13) or 411(a) of the Internal Revenue Code of 1986, as amended, and regulations thereunder.

6. Committee Decisions. Decisions of the Committee with respect to this Policy shall be final, conclusive, and binding on all Executive Officers subject to this Policy, unless determined to be an abuse of discretion.

7. No Indemnification. Notwithstanding anything to the contrary in any other policy of the Company or any agreement between the Company and an Executive Officer, no Executive Officer shall be indemnified by the Company against the loss of any Erroneously Awarded Compensation.

8. Agreement to Policy by Executive Officers. The Committee shall take reasonable steps to inform Executive Officers of this Policy and obtain their agreement to this Policy, which steps may constitute the inclusion of this Policy as an attachment to any award that is or has been accepted by the Executive Officer.

XML

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2023	Feb. 16, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Document Transition Report	false
Entity File Number	001-11590
Entity Registrant Name	CHESAPEAKE UTILITIES CORPORATION
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0064146
Entity Address, Address Line One	500 Energy Lane
Entity Address, City or Town	Dover
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19901
City Area Code	302
Local Phone Number	734-6799
Title of 12(b) Security	Common Stock—par value per share $0.4867
Trading Symbol	CPK
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Public Float			$ 2.1
Entity Common Stock, Shares Outstanding		22,238,384
Documents Incorporated by Reference	Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2024 Annual Meeting of Shareholders are incorporated by reference in Part II and Part III hereof
Entity Central Index Key	0000019745
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction [Flag]	false

XML

Audit Information	12 Months Ended
	Dec. 31, 2023
Auditor Information [Abstract]
Auditor Name	Baker Tilly US, LLP
Auditor Location	Lancaster, Pennsylvania
Auditor Firm ID	23

XML

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Revenues
Regulated Energy	$ 473,595	$ 429,424	$ 383,920
Unregulated Energy	223,148	280,750	206,869
Other	(26,139)	(29,470)	(20,821)
Total operating revenues	670,604	680,704	569,968
Operating Expenses
Natural gas and electricity costs	140,008	127,172	100,737
Propane and natural gas costs	76,474	133,334	86,213
Operations	178,437	164,505	148,294
Maintenance	20,401	18,176	16,793
Depreciation and amortization	65,501	68,973	62,661
Other taxes	28,625	25,611	24,158
Total operating expenses	519,801	537,771	438,856
Operating Income	150,803	142,933	131,112
Other income, net	1,438	5,051	1,720
Interest charges	36,951	24,356	20,135
Income Before Income Taxes	115,290	123,628	112,697
Income taxes	28,078	33,832	29,231
Net Income (Loss) Attributable to Parent	$ 87,212	$ 89,796	$ 83,466
Weighted Average Common Shares Outstanding:
Basic (in shares)	18,370,758	17,722,227	17,558,078
Diluted (in shares)	18,434,857	17,804,294	17,633,029
Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share	$ 4.75	$ 5.07	$ 4.75
Basic (in usd per share)	4.75	5.07	4.75
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share	4.73	5.04	4.73
Diluted (in usd per share)	$ 4.73	$ 5.04	$ 4.73
Transaction-related expenses	$ 10,355	$ 0	$ 0

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income	$ 87,212	$ 89,796	$ 83,466
Employee Benefits, net of tax:
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $11, $18 and $550, respectively	32	57	1,616
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	110	(705)	(262)
Cash Flow Hedges, net of tax:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent		0	0
Total Other Comprehensive (Loss) Income	(1,359)	(2,682)	4,168
Comprehensive Income	85,853	87,114	87,634
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(400)	(2,453)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	400	2,453
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $11, $18 and $550, respectively	32	57	1,616
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	110	(705)	(262)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(959)	(229)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent		0	0
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
Cash Flow Hedges, net of tax:
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(388)	35	28
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	388	(35)	(28)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Cash Flow Hedges, net of tax:
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(501), $(369) and $2,702, respectively		(934)	7,075
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(44)	(2,545)	(4,813)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	44	2,545	4,813
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(1,322)	(934)
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(501), $(369) and $2,702, respectively		(934)	$ 7,075
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Cash Flow Hedges, net of tax:
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(388)	35
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	388	(35)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	$ 473	$ 0

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ 11,000	$ 18,082	$ 550,000
Tax expense recognized on the net gain (loss)	(37,000)	242,699	93,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	(165,000)	0	0
Accumulated Other Comprehensive Income (Loss) [Line Items]
Tax expense recognized on the amortization of prior service cost	11,000	18,082	550,000
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, Tax	37,000	(242,699)	(93,000)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	(165,000)	0	0
Unrealized Gain (Loss) On Cash Flow Hedging Instruments, Tax	(501,000)	(369,000)	2,702,000
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	(17,000)	(963,000)	(1,838,000)
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	$ 135,000	$ (12,000)	$ 12,000

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Activities
Net Income	$ 87,212	$ 89,796	$ 83,466
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	65,501	68,973	62,661
Depreciation and accretion included in operations expenses	11,934	11,044	10,228
Deferred income taxes, net	3,413	23,705	26,658
Realized (loss) on sale of assets/commodity contracts	(824)	(7,532)	(9,026)
Unrealized loss (gain) on investments/commodity contracts	(1,916)	1,817	(1,464)
Employee benefits and compensation	342	(1,111)	(53)
Share-based compensation	7,622	6,438	5,945
Changes in assets and liabilities:
Accounts receivable and accrued revenue	2,270	(11,159)	(1,634)
Propane inventory, storage gas and other inventory	293	(7,847)	(9,517)
Regulatory assets/liabilities, net	20,102	(38,671)	(18,464)
Prepaid expenses and other current assets	18,689	9,124	(1,520)
Accounts payable and other accrued liabilities	(16,795)	2,724	8,285
Income taxes receivable	(1,288)	14,919	(4,575)
Customer deposits and refunds	3,928	664	3,176
Accrued compensation	1,462	(1,231)	1,198
Other assets and liabilities, net	1,367	(2,771)	(4,860)
Net cash provided by operating activities	203,482	158,882	150,504
Investing Activities
Property, plant and equipment expenditures	(188,618)	(128,276)	(186,924)
Proceeds from sale of assets	2,926	3,860	1,033
Acquisitions, net of cash acquired	(925,034)	(11,766)	(36,371)
Environmental expenditures	(665)	(266)	(761)
Net cash used in investing activities	(1,111,391)	(136,448)	(223,023)
Financing Activities
Common stock dividends	(40,009)	(35,147)	(31,537)
Issuance of stock for Dividend Reinvestment Plan	(28)	4,534	15,851
Proceeds from issuance of common stock, net of expenses	366,417	0	0
Payment, Tax Withholding, Share-based Payment Arrangement	(2,455)	(2,838)	(1,478)
Change in cash overdrafts due to outstanding checks	(301)	955	(1,154)
Net borrowings (repayments) under line of credit agreements	(22,544)	(20,608)	46,647
Proceeds from issuance of long-term debt	627,011	49,859	59,478
Repayment of long-term debt and finance lease obligation	(21,482)	(17,961)	(13,811)
Net cash provided by (used in) financing activities	906,609	(21,206)	73,996
Net (Decrease) Increase in Cash and Cash Equivalents	(1,300)	1,228	1,477
Other Operating Activities, Cash Flow Statement	170	0	0
Cash and Cash Equivalents — Beginning of Period	6,204	4,976	3,499
Cash and Cash Equivalents — End of Period	$ 4,904	$ 6,204	$ 4,976

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment
Regulated Energy	$ 2,418,494	$ 1,802,999
Unregulated Energy	410,807	393,215
Other businesses and eliminations	30,310	29,890
Total property, plant and equipment	2,859,611	2,226,104
Accumulated depreciation	516,429	462,926
Construction Work in Progress	113,192	47,295
Net property, plant and equipment	2,456,374	1,810,473
Current Assets
Cash and cash equivalents	4,904	6,204
Accounts Receivable, before Allowance for Credit Loss, Current	74,485	65,758
Allowance for uncollectible accounts	2,699	2,877
Trade receivables, net	71,786	62,881
Accrued Revenue	32,597	29,206
Propane inventory, at average cost	9,313	9,365
Other inventory, at average cost	19,912	16,896
Regulatory assets	19,506	41,439
Storage gas prepayments	4,695	6,364
Income taxes receivable	3,829	2,541
Prepaid expenses	15,407	15,865
Derivative assets, at fair value	1,027	2,787
Other current assets	2,723	428
Total current assets	185,699	193,976
Deferred Charges and Other Assets
Goodwill	508,174	46,213
Other intangible assets, net	16,865	17,859
Investments, Fair Value Disclosure	12,282	10,576
Operating Lease, Right-of-Use Asset	12,426	14,421
Regulatory assets	96,396	108,214
Receivables and other deferred charges	16,448	12,323
Total deferred charges and other assets	662,631	210,588
Total Assets	3,304,704	2,215,037
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	0	0
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	10,823	8,635
Additional paid-in capital	749,356	380,036
Retained earnings	488,663	445,509
Accumulated other comprehensive loss	(2,738)	(1,379)
Deferred compensation obligation	9,050	7,060
Treasury Stock, Value	(9,050)	(7,060)
Total stockholders’ equity	1,246,104	832,801
Long-term debt, net of current maturities	1,187,075	578,388
Total capitalization	2,433,179	1,411,189
Current Liabilities
Current portion of long-term debt	18,505	21,483
Short-term borrowing	179,853	202,157
Accounts payable	77,481	61,496
Customer deposits and refunds	46,427	37,152
Accrued interest	7,020	3,349
Dividends payable	13,119	9,492
Accrued compensation	16,544	14,660
Regulatory liabilities	13,719	5,031
Derivative liabilities, at fair value	354	585
Other accrued liabilities	13,362	13,618
Total current liabilities	386,384	369,023
Deferred Credits and Other Liabilities
Deferred income taxes	259,082	256,167
Regulatory liabilities	195,279	142,989
Environmental liabilities	2,607	3,272
Other pension and benefit costs	15,330	16,965
Operating Lease, Liability, Noncurrent	10,550	12,392
Deferred investment tax credits and other liabilities	1,366	1,410
Total deferred credits and other liabilities	485,141	434,825
Commitments and Contingencies
Total Capitalization and Liabilities	3,304,704	2,215,037
Regulated Energy	2,418,494	1,802,999
Unregulated Energy	410,807	393,215
Other businesses and eliminations	30,310	29,890
Total property, plant and equipment	2,859,611	2,226,104
Accumulated depreciation	516,429	462,926
Construction Work in Progress	113,192	47,295
Net property, plant and equipment	2,456,374	1,810,473
Cash and cash equivalents	4,904	6,204
Accounts Receivable, before Allowance for Credit Loss, Current	74,485	65,758
Allowance for uncollectible accounts	2,699	2,877
Trade receivables, net	71,786	62,881
Accrued Revenue	32,597	29,206
Propane inventory, at average cost	9,313	9,365
Other inventory, at average cost	19,912	16,896
Regulatory assets	19,506	41,439
Storage gas prepayments	4,695	6,364
Income taxes receivable	3,829	2,541
Prepaid expenses	15,407	15,865
Derivative assets, at fair value	1,027	2,787
Other current assets	2,723	428
Disposal Group, Including Discontinued Operation, Assets, Current	185,699	193,976
Goodwill	508,174	46,213
Other intangible assets, net	16,865	17,859
Investments, Fair Value Disclosure	12,282	10,576
Energy Marketing Contracts Assets, Noncurrent	40	982
Operating Lease, Right-of-Use Asset	12,426	14,421
Regulatory assets	96,396	108,214
Receivables and other deferred charges	16,448	12,323
Deferred Charges And Other Assets	662,631	210,588
Total identifiable assets	3,304,704	2,215,037
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	0	0
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	10,823	8,635
Additional paid-in capital	749,356	380,036
Retained earnings	488,663	445,509
Accumulated other comprehensive loss	(2,738)	(1,379)
Deferred compensation obligation	9,050	7,060
Treasury Stock, Value	9,050	7,060
Stockholders' Equity Attributable to Parent	1,246,104	832,801
Long-term debt, net of current maturities	1,187,075	578,388
Total capitalization	2,433,179	1,411,189
Current portion of long-term debt	18,505	21,483
Short-term borrowing	179,853	202,157
Accounts payable	77,481	61,496
Customer deposits and refunds	46,427	37,152
Accrued interest	7,020	3,349
Dividends payable	13,119	9,492
Accrued compensation	16,544	14,660
Regulatory liabilities	13,719	5,031
Derivative liabilities, at fair value	354	585
Other accrued liabilities	13,362	13,618
Liabilities, Current	386,384	369,023
Deferred income taxes	259,082	256,167
Regulatory liabilities	195,279	142,989
Environmental liabilities	2,607	3,272
Other pension and benefit costs	15,330	16,965
Energy Marketing Contract Liabilities, Noncurrent	927	1,630
Operating Lease, Liability, Noncurrent	10,550	12,392
Deferred investment tax credits and other liabilities	1,366	1,410
Deferred Credits and Other Liabilities	485,141	434,825
Liabilities and Equity	$ 3,304,704	$ 2,215,037

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 2,699	$ 2,877
Common stock, par value	$ 0.4867	$ 0.4867
Common stock, shares authorized	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01

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Consolidated Statements of Stockholders' Equity - USD ($)		Total		Florida City Gas	Common Stock [Member]	Common Stock [Member] Florida City Gas	Additional Paid-In Capital [Member]	Additional Paid-In Capital [Member] Florida City Gas	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock, Common
Shares, Issued	[1],[2]				17,461,841
Stockholders' Equity Attributable to Parent		$ 697,085,000	[2]		$ 8,499,000		$ 348,482,000		$ 342,969,000	$ (2,865,000)	$ 5,679,000	$ (5,679,000)
Net Income		83,466,000							83,466,000
Other comprehensive loss		4,168,000								4,168,000
Dividends		(33,363,000)							(33,363,000)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan					$ 72,000
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan					147,256
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		18,248,000					18,176,000
Share-based compensation, shares					46,313
Share-based compensation		4,526,000	[3],[4]		$ 22,000		4,504,000					0
Treasury stock activities		0									1,561,000	(1,561,000)
Shares, Issued	[1],[2]				17,655,410
Stockholders' Equity Attributable to Parent		774,130,000	[2]		$ 8,593,000		371,162,000		393,072,000	1,303,000	7,240,000	(7,240,000)
Net Income		89,796,000							89,796,000
Other comprehensive loss		(2,682,000)								(2,682,000)
Dividends		(37,359,000)							(37,359,000)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan					$ 19,000		5,273,000
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		5,292,000
Share-based compensation, shares	[3],[4]				46,590
Share-based compensation		3,624,000	[3],[4]		$ 23,000		3,601,000
Treasury stock activities		$ 0									(180,000)	180,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan		100,000			39,418
Stock Issued During Period, Value, Dividend Reinvestment Plan		$ 136.26
Shares, Issued	[1],[2]				17,741,418
Stockholders' Equity Attributable to Parent		832,801,000			$ 8,635,000		380,036,000		445,509,000	(1,379,000)	7,060,000	(7,060,000)
Net Income		87,212,000							87,212,000
Stock Issued During Period, Value, Acquisitions				$ 366,417,000		$ 2,160,000		$ 364,257,000
Other comprehensive loss		(1,359,000)								(1,359,000)
Dividends		(44,058,000)							(44,058,000)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan		(26,000)			$ 0		(26,000)
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan					0
Share-based compensation, shares	[3],[4]				55,323
Share-based compensation		5,117,000	[3],[4]		$ 28,000		5,089,000
Treasury stock activities		0									1,990,000	(1,990,000)
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares				4,438,596		4,400,000
Shares, Issued	[1],[2]				22,235,337
Stockholders' Equity Attributable to Parent		$ 1,246,104,000			$ 10,823,000		$ 749,356,000		$ 488,663,000	$ (2,738,000)	$ 9,050,000	$ (9,050,000)

[1] 2,000,000 shares of preferred stock at $0.01 par value per share have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity.

[2] Includes 107,623, 108,143 and 116,238 shares at December 31, 2023, 2022 and 2021, 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 2023, 2022 and 2021, we withheld 19,859, 21,832 and 14,020 shares, respectively, for taxes. (5) Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM equity issuances, as applicable.

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Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Shares Held In Trust For Deferred Compensation Plan	107,623	108,143	116,238
Dividends Declared	$ 2.3050	$ 2.0850	$ 1.8800
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes		21,832	14,020

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

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 owned by 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, 2023 and 2022 is provided in the following table:

	As of December 31,
(in thousands)	2023		2022
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida (1)	$	1,486,796	$	925,501
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	788,185		741,865
Electric distribution	143,513		135,633
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	194,918		185,090
Natural gas transmission and supply – Ohio	134,192		128,620
Electricity and steam generation	37,064		36,886
Mobile CNG and pipeline solutions	40,558		38,543
Sustainable energy investments, including renewable natural gas	4,076		4,076
Other	30,309		29,890
Total property, plant and equipment	2,859,611		2,226,104
Less: Accumulated depreciation and amortization	(516,429)		(462,926)
Plus: Construction work in progress	113,192		47,295
Net property, plant and equipment	$	2,456,374	$	1,810,473

(1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition.

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, 2023 and 2022, the non-refundable contributions totaled $4.2 million and $7.6 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 the years ended December 31, 2023, 2022 and 2021, AFUDC was immaterial and was reflected as a reduction of interest charges.

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.

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.

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. See Note 14, Leases, for additional information.

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, 2023, 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 $2.2 million and $1.5 million at December 31, 2023 and 2022, 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, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 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, 2023, 2022 and 2021:

	2023	2022	2021
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida (1) (2)	2.2%	2.5%	2.5%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.4%	2.4%	2.3%
Natural gas transmission – Ohio	5.0%	5.0%	N/A
Electric distribution	2.4%	2.8%	2.8%

(1) Excludes the acquisition of FCG which was completed on November 30, 2023.

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

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

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.

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. The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2023:

(in thousands)
Balance at December 31, 2022	$	2,877
Additions:
Provision for credit losses	2,340
Recoveries	166
Deductions:
Write offs	(2,684)
Balance at December 31, 2023	$	2,699

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, 2023, 2022 or 2021.

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, 2023, 2022 and 2021. 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 18, 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 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 net of any valuation allowance when it is more likely than not that such income tax benefits will 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.

Recent Accounting Standards Yet to be Adopted

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

Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2024. ASU 2023-09 only impacts disclosures, and as a result, will not have a material impact on our financial position or results of operations.

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Earnings Per Share

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Earnings Per Share

3. EARNINGS PER SHARE

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

	For the Year Ended December 31,
	2023		2022		2021
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	87,212	$	89,796	$	83,466
Weighted average shares outstanding (1)	18,370,758		17,722,227		17,558,078
Basic Earnings Per Share	$	4.75	$	5.07	$	4.75
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic (1)	18,370,758		17,722,227		17,558,078
Effect of dilutive securities — Share-based compensation	64,099		82,067		74,951
Adjusted denominator — Diluted (1)	18,434,857		17,804,294		17,633,029
Diluted Earnings Per Share	$	4.73	$	5.04	$	4.73

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Acquisitions

12 Months Ended

Dec. 31, 2023

Business Combinations [Abstract]

Acquisitions

4. ACQUISITIONS

Acquisition of Florida City Gas

On November 30, 2023, we completed the acquisition of FCG for $923.4 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, a regulated utility, serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe.

The purchase price of the acquisition was funded with $366.4 million of net proceeds from the issuance of 4.4 million shares of our common stock, the issuance of approximately $550.0 million principal amount of uncollateralized senior notes, and borrowings under the Company's Revolver. See Note 12, Long-Term Debt, and Note 15, Stockholders' Equity, for additional details on these financing activities.

We accounted for the acquisition of FCG using the acquisition method. At December 31, 2023, the allocation of the purchase price remains preliminary pending finalizing of certain working capital balances. As such, the fair value measurements presented below are subject to change within the measurement period not to exceed one year from the date of the acquisition. As FCG is a regulated utility, the measurement of the fair value of most of the assets acquired and liabilities assumed were determined using the predecessor’s carrying value. In certain other instances where assets and liabilities are not subject to regulation, we determined the fair value in accordance with the principles of ASC Topic 820, Fair Value Measurements.

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

The components of the preliminary purchase price allocation are as follows:

(in thousands)
Assets acquired:	Acquisition Date Fair Value
Cash	$	2,270
Accounts receivable, net	14,396
Regulatory assets - current	2,983
Other current assets	2,707
Property, plant and equipment	453,845
Goodwill	461,193
Regulatory assets - non-current	3,381
Other deferred charges and other assets,	18,309
Total assets acquired	959,084
Liabilities assumed:
Current liabilities	(20,954)
Regulatory liabilities	(14,137)
Other deferred credits and other liabilities	(548)
Total liabilities assumed	(35,639)
Net purchase price	$	923,445

Direct transaction costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges include $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 have been deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate.

For 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-related expenses described above. For additional information on FCG's results, see discussion under Item 7, Management's Discussion

and Analysis of Financial Condition and Results of Operations. The following unaudited financial information reflects our pro forma operating revenues and net income assuming the FCG acquisition had occurred on January 1, 2022. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the results of operations that would have been achieved or the future results of operations of FCG.

For the Year Ended December 31,
	2023		2022
(in thousands)
Operating Revenue	$	786,473	$	798,355
Net Income	$	85,398	$	81,508

Acquisition of J.T. Lee and Son's

In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $3.9 million. In connection with this acquisition, we recorded a $0.3 million liability which is subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. 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 amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the year ended December 31, 2023.

Acquisition of Planet Found Energy Development

In October 2022, we acquired Planet Found Energy Development, LLC ("Planet Found") for $9.5 million. In connection with this acquisition, we recorded a $0.9 million liability which was released after the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy segment beginning in the fourth quarter of 2022. Planet Found's farm scale anaerobic digestion pilot system and technology produces biogas from 1200 tons of poultry litter annually. The transaction accelerated our efforts in converting poultry waste to renewable, sustainable energy while simultaneously improving the local environments in our service territories.

In connection with this acquisition, we recorded $4.4 million in intangible assets associated primarily with intellectual property and non-compete agreements, $4.0 million in property plant and equipment, $1.1 million in goodwill, and less than $0.1 million in working capital, all of which are deductible for income tax purposes. The operating revenues and net income of Planet Found were not material to our consolidated results for the years ended December 31, 2023 and 2022.

Acquisition of Davenport Energy

In June 2022, Sharp acquired the propane operating assets of Davenport Energy's Siler City, North Carolina propane division for approximately $2.0 million. Through this acquisition, the Company expanded its operating footprint further into North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. Sharp added approximately 850 customers, and expected distribution of approximately 0.4 million gallons of propane annually. We recorded $1.5 million in property plant and equipment, $0.5 million in goodwill, and immaterial amounts associated with customer relationships and non-compete agreements, all of which are deductible for income tax purposes. The financial results associated with this acquisition are included within the Company's propane distribution operations within its Unregulated Energy segment. The operating revenues and net income of Davenport Energy were not material to our consolidated results for the years ended December 31, 2023 and 2022.

Acquisitions Florida City Gas Pro forma

For the Year Ended December 31,
	2023		2022
(in thousands)
Operating Revenue	$	786,473	$	798,355
Net Income	$	85,398	$	81,508

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2023

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

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 table displays revenue by major source based on product and service type for the years ended December 31, 2023, 2022 and 2021:

	For the year ended December 31, 2023
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	83,882	$	—	$	—	$	83,882
Florida Natural Gas distribution (1)	168,360		—		—		168,360
Florida City Gas (2)	12,073		—		—		12,073
FPU electric distribution	99,474		—		—		99,474
Maryland natural gas division	28,092		—		—		28,092
Sandpiper natural gas/propane operations	20,185		—		—		20,185
Elkton Gas	8,814		—		—		8,814
Total energy distribution	420,880		—		—		420,880
Energy transmission
Aspire Energy	—		37,139		—		37,139
Aspire Energy Express	1,478		—		—		1,478
Eastern Shore	79,923		—		—		79,923
Peninsula Pipeline	30,400		—		—		30,400
Total energy transmission	111,801		37,139		—		148,940
Energy generation
Eight Flags	—		19,207		—		19,207
Propane operations
Propane distribution operations	—		154,748		—		154,748
Compressed Natural Gas Services
Marlin Gas Services	—		12,300		—		12,300
Other and eliminations
Eliminations	(59,086)		(246)		(26,321)		(85,653)
Other	—		—		182		182
Total other and eliminations	(59,086)		(246)		(26,139)		(85,471)
Total operating revenues (3)	$	473,595	$	223,148	$	(26,139)	$	670,604

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions, and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

(3) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 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 for Maryland division and Sandpiper and late fees.

	For the year ended December 31, 2022
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	82,176	$	—	$	—	$	82,176
Florida Natural Gas distribution (1)	155,870		—		—		155,870
FPU electric distribution	81,714		—		—		81,714
Maryland natural gas division	26,607		—		—		26,607
Sandpiper natural gas/propane operations	21,278		—		—		21,278
Elkton Gas	9,198		—		—		9,198
Total energy distribution	376,843		—		—		376,843
Energy transmission
Aspire Energy	—		56,225		—		56,225
Aspire Energy Express	1,377		—		—		1,377
Eastern Shore	78,624		—		—		78,624
Peninsula Pipeline	27,263		—		—		27,263
Total energy transmission	107,264		56,225		—		163,489
Energy generation
Eight Flags	—		25,318		—		25,318
Propane operations
Propane distribution operations	—		188,412		—		188,412
Compressed Natural Gas Services
Marlin Gas Services	—		11,159		—		11,159
Other and eliminations
Eliminations	(54,683)		(364)		(29,778)		(84,825)
Other	—		—		308		308
Total other and eliminations	(54,683)		(364)		(29,470)		(84,517)
Total operating revenues (2)	$	429,424	$	280,750	$	(29,470)	$	680,704

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 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 for Maryland division and Sandpiper and late fees.

	For the year ended December 31, 2021
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	71,195	$	—	$	—	$	71,195
Florida Natural Gas distribution (1)	134,609		—		—		134,609
FPU electric distribution	78,300		—		—		78,300
Maryland natural gas division	22,449		—		—		22,449
Sandpiper natural gas/propane operations	20,746		—		—		20,746
Elkton Gas	7,105		—		—		7,105
Total energy distribution	334,404		—		—		334,404
Energy transmission
Aspire Energy	—		38,163		—		38,163
Aspire Energy Express	187		—		—		187
Eastern Shore	76,911		—		—		76,911
Peninsula Pipeline	26,630		—		—		26,630
Total energy transmission	103,728		38,163		—		141,891
Energy generation
Eight Flags	—		18,652		—		18,652
Propane operations
Propane distribution operations	—		142,082		—		142,082
Compressed Natural Gas Services
Marlin Gas Services	—		8,315		—		8,315
Other and eliminations
Eliminations	(54,212)		(343)		(21,348)		(75,903)
Other	—		—		527		527
Total other and eliminations	(54,212)		(343)		(20,821)		(75,376)
Total operating revenues (2)	$	383,920	$	206,869	$	(20,821)	$	569,968

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 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 for Maryland division and Sandpiper and late fees.

Regulated Energy Segment

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide.

Revenues for Eastern Shore 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 the FERC-approved maximum rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers receive service only when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Aspire Energy Express is engaged in natural gas intrastate transmission in the State of Ohio. We currently serve the Guernsey power plant and our performance obligation is satisfied over time as the natural gas is transported to the plant. We recognize revenue based on rates approved by the Ohio PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Unregulated Energy Segment

Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Eight Flags' CHP plant, which is located on land leased from a customer, produces three sources of energy: electricity, steam and heated water. This customer purchases the steam (unfired and fired) and heated water, which are used in the customer’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.

For our propane distribution operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane distribution customers with meters, we satisfy our performance obligation over time. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane distribution metered customers, we accrue unbilled revenues for propane that is estimated to have been consumed, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.

Marlin Gas Services provides mobile CNG and pipeline solutions primarily to utilities and pipelines. 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. Marlin Gas Services' performance obligations are comprised of the compression of natural gas, mobilization of CNG equipment, utilization of equipment and on-site CNG support. Our performance obligations for the compression of natural gas, utilization of mobile CNG equipment and for the on-site CNG staff support are satisfied over time when the natural gas is compressed, equipment is utilized or as our staff provide support services to our customers. Our performance obligation for the mobilization of CNG equipment is satisfied at a point-in-time when the equipment is delivered to the customer project location. We recognize revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2023 and 2022 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2022	$	61,687	$	18	$	4,321	$	983
Balance at 12/31/2023	67,741		18		3,524		1,022
Increase (decrease)	$	6,054	$	—	$	(797)	$	39

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

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2023 and 2022, the amounts recognized in revenue were not material.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2023 are expected to be recognized as follows:

(in thousands)	2024		2025		2026		2027		2028		2029 and thereafter
Eastern Shore and Peninsula Pipeline	$	36,657	$	30,330	$	26,547	$	23,433	$	22,559	$	149,124
Natural gas distribution operations	9,680		9,216		8,501		6,472		5,252		28,428
FPU electric distribution	652		275		275		275		275		—
Total revenue contracts with remaining performance obligations	$	46,989	$	39,821	$	35,323	$	30,180	$	28,086	$	177,552

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Segment Information

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Segment Information

SEGMENT INFORMATION

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief decision maker (our Chief Executive Officer, or "CEO") in order to make decisions about resources and to assess performance.

Our operations are entirely domestic and are comprised of two reportable segments:

•Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services.

The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

The following tables present information about our reportable segments:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	471,591	$	422,894	$	381,879
Unregulated Energy	199,013		257,810		188,089
Total operating revenues, unaffiliated customers	$	670,604	$	680,704	$	569,968
Intersegment Revenues (1)
Regulated Energy	$	2,004	$	6,530	$	2,041
Unregulated Energy	24,135		22,940		18,780
Other businesses	182		308		527
Total intersegment revenues	$	26,321	$	29,778	$	21,348
Operating Income
Regulated Energy	$	126,199	$	115,317	$	106,174
Unregulated Energy	24,426		27,350		24,427
Other businesses and eliminations	178		266		511
Operating Income	150,803		142,933		131,112
Other income, net	1,438		5,051		1,720
Interest charges	36,951		24,356		20,135
Income before Income Taxes	115,290		123,628		112,697
Income Taxes	28,078		33,832		29,231
Net Income	$	87,212	$	89,796	$	83,466
Depreciation and Amortization
Regulated Energy (2)	$	48,162	$	52,707	$	48,748
Unregulated Energy	17,347		16,257		13,869
Other businesses and eliminations	(8)		9		44
Total depreciation and amortization	$	65,501	$	68,973	$	62,661
Capital Expenditures
Regulated Energy (3)	$	1,095,871	$	97,554	$	139,733
Unregulated Energy	40,264		40,773		81,651
Other businesses	1,762		2,355		6,425
Total capital expenditures	$	1,137,897	$	140,682	$	227,809

     (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

 (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details.

 (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details.

	As of December 31,
(in thousands)	2023		2022
Identifiable Assets
Regulated Energy segment	$	2,781,581	$	1,716,255
Unregulated Energy segment	477,402		463,239
Other businesses and eliminations	45,721		35,543
Total identifiable assets	$	3,304,704	$	2,215,037

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Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2023, 2022 and 2021 were as follows:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Cash paid for interest	$	30,525	$	24,267	$	20,809
Cash (received) paid for income taxes, net of refunds	$	21,920	$	(4,963)	$	8,395

Non-cash investing and financing activities during the years ended December 31, 2023, 2022, and 2021 were as follows: 

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31,	$	33,334	$	13,211	$	16,164
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	1,712
Common stock issued under the SICP	$	3,740	$	2,868	$	2,834

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Derivative Instruments

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Derivative Instruments

8. DERIVATIVE INSTRUMENTS

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. Occasionally, we may enter into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of December 31, 2023 and 2022, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of December 31, 2023, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	Purchases	18.1	Cash flow hedges	June 2026
Sharp	Propane (gallons)	Sales	3.2	Cash flow hedges	March 2024

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2023 through June 2026) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is initially recorded as a component of accumulated other comprehensive income (loss) and later recognized in our consolidated statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.3 million of unrealized losses from accumulated other comprehensive income (loss) to earnings during the next 12-month period.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In September 2022, we entered into an interest rate swap with a notional amount of $50.0 million through September 2025, with pricing of 3.98 percent.

In February 2021, we entered into an interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. In the fourth quarter of 2020, we entered into interest rate swaps with notional amounts totaling $60.0 million through December 2021 with pricing of approximately 0.20 percent for the period associated with our outstanding borrowing under the Revolver.

In August 2022, we amended and restated the Revolver and transitioned the benchmark interest rate to the 30-day SOFR as a result of the expiration of LIBOR. Accordingly, our current interest rate swap is cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate. Prior to August 2022, our short-term borrowing interest rate was based on the 30-day LIBOR rate. Our pre-2022 interest rate swaps were cash settled monthly as the counter-party paid us the 30-day LIBOR rate less the fixed rate.

We designate and account for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are initially recorded as a component of accumulated other comprehensive income (loss). As the interest rate swap settles each month, the realized gain or loss is recorded in the income statement and is recognized as a component of interest charges.

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp included within other current assets on the consolidated balance sheet with a balance of $2.1 million as of December 31, 2023 compared to a current liability of $0.1 million at December 31, 2022.

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2023 and 2022 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value (1)	$	702	$	3,317
Interest rate swap agreements	Derivative assets, at fair value (1)	365		452
Total Derivative Assets		$	1,067	$	3,769

 (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value (1)	$	1,078	$	1,810
Interest rate swap agreements	Derivative liabilities, at fair value (1)	203		405
Total Derivative Liabilities		$	1,281	$	2,215

(1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2023		2022		2021
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	—	$	56	$	(1)
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	—		—		(24)
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	1,221		(373)		(536)
Propane swap agreements	Propane and natural gas costs	(1,160)		3,881		7,187
Interest rate swap agreements	Interest expense	523		(47)		(40)
Total		$	584	$	3,517	$	6,586

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Fair Value of Financial Instruments

FAIR VALUE OF FINANCIAL INSTRUMENTS

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are as follows:

Fair Value Hierarchy	Description of Fair Value Level	Fair Value Technique Utilized
Level 1	Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities	Investments - equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. Investments - mutual funds and other - The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2	Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability	Derivative assets and liabilities - The fair value of the propane put/call options, propane and interest rate swap agreements are measured using market transactions for similar assets and liabilities in either the listed or over-the-counter markets.
Level 3	Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e., supported by little or no market activity)	Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value.

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2023 and 2022, respectively:

			Fair Value Measurements Using:
As of December 31, 2023	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	1,489		—		—		1,489
Investments—mutual funds and other	10,772		10,772		—		—
Total investments	12,282		10,793		—		1,489
Derivative assets	1,067		—		1,067		—
Total assets	$	13,349	$	10,793	$	1,067	$	1,489
Liabilities:
Derivative liabilities	$	1,281	$	—	$	1,281	$	—

			Fair Value Measurements Using:
As of December 31, 2022	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	24	$	24	$	—	$	—
Investments—guaranteed income fund	1,853		—		—		1,853
Investments—mutual funds and other	8,699		8,699		—		—
Total investments	10,576		8,723		—		1,853
Derivative assets	3,769		—		3,769		—
Total assets	$	14,345	$	8,723	$	3,769	$	1,853
Liabilities:
Derivative liabilities	$	2,215	$	—	$	2,215	$	—

The changes in the fair value of our Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

At December 31, 2023 and 2022, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.2 billion, compared to the estimated fair value of $1.2 billion. At December 31, 2022, long-term debt, which includes the current maturities and excludes debt issuance costs, had a carrying value of $600.8 million, compared to a fair value of $505.0 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 2 measurement.

See Note 16, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Goodwill and Other Intangible Assets

GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2023 and 2022 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2022	$	7,689	$	38,524	$	46,213
Additions (1)	461,025		936		461,961
Balance at December 31, 2023	$	468,714	$	39,460	$	508,174

(1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details.

There were no goodwill impairments recognized during the three-year period ended December 31, 2023.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2023 and 2022 was as follows:

	As of December 31,
	2023				2022
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	17,004	$	7,146	$	16,965	$	6,131
Non-Compete agreements	3,125		1,855		3,105		1,411
Patents (1)	6,558		859		5,819		533
Other	270		232		270		225
Total	$	26,957	$	10,092	$	26,159	$	8,300

(1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found.

The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted average of 14 years. Amortization expense of intangible assets for the year ended December 31, 2023, 2022 and 2021 was $1.8 million, $1.5 million and $1.3 million, respectively. Amortization expense of intangible assets is expected to be $1.8 million for the years 2024 through 2025, $1.6 million for 2026, $1.5 million for 2027

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Income Taxes

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Income Taxes

INCOME TAXES

We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our state returns for tax years after 2017 are subject to examination. At December 31, 2023, the 2015 through 2019 federal income tax returns are no longer under examination.

For state income tax purposes, we had NOL in various states of $72.9 million and $67.7 million as of December 31, 2023 and 2022, respectively, almost all of which will expire in 2040. Excluding NOLs from discontinued operations, we have recorded deferred tax assets of $1.8 million and $1.5 million related to state NOL carry-forwards at December 31, 2023 and 2022, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized.

Tax Law Changes

In March 2020, the CARES Act was signed into law and included several significant changes to the Internal Revenue Code. The CARES Act includes certain tax relief provisions including the ability to carryback five years net operating losses arising in a tax year beginning in 2018, 2019, or 2020. This provision allows a taxpayer to recover taxes previously paid at a 35 percent federal income tax rate during tax years prior to 2018. In addition, the CARES Act removed the taxable income limitation to allow a tax NOL to fully offset taxable income for tax years beginning before January 1, 2021. As a result, our income tax expense for the year ended December 31, 2021 included a tax benefit $0.9 million, attributable to the tax NOL carryback provided under the CARES Act for losses generated in 2018 and 2019 and then applied back to our 2013 and 2015 tax years in which we paid federal income taxes at a 35 percent tax rate. Tax benefits associated with this legislation were not available for the year ended December 31, 2023.

On December 22, 2017, the TCJA was signed into law. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 18, Rates and Other Regulatory Activities, for further discussion of the TCJA's impact on our regulated businesses.

The following tables provide: (a) the components of income tax expense in 2023, 2022, and 2021; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2023, 2022, and 2021; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2023 and 2022.

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Current Income Tax Expense
Federal	$	14,736	$	8,284	$	2,775
State	5,496		1,948		(96)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	20,185		10,185		2,632
Deferred Income Tax Expense (1)
Property, plant and equipment	17,797		14,968		24,074
Deferred gas costs	(7,739)		8,923		1,857
Pensions and other employee benefits	(974)		1,109		(655)
FPU merger-related premium cost and deferred gain	(351)		(351)		(351)
Net operating loss carryforwards	(370)		2		97
Other	(470)		(1,004)		1,577
Total deferred income tax expense	7,893		23,647		26,599
Total Income Tax	$	28,078	$	33,832	$	29,231

(1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively.

	For the Year Ended December 31,
	2023			2022			2021
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	24,214		$	25,982		$	23,666
State income taxes, net of federal benefit	4,377			7,714			6,371
ESOP dividend deduction	(184)			(177)			(180)
CARES Act Tax Benefit	—			—			(919)
Other	(329)			313			293
Total Income Tax Expense	$	28,078		$	33,832		$	29,231
Effective Income Tax Rate	24.35		%	27.34		%	25.94		%

(1) Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021.

	As of December 31,
	2023		2022
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	252,125	$	238,687
Acquisition adjustment	5,564		5,915
Loss on reacquired debt	145		164
Deferred gas costs	3,550		11,288
Natural gas conversion costs	4,824		5,026
Storm reserve liability	5,797		5,791
Other	9,655		8,236
Total deferred income tax liabilities	$	281,660	$	275,107
Deferred income tax assets:
Pension and other employee benefits	$	4,993	$	3,985
Environmental costs	951		1,052
Net operating loss carryforwards	1,847		1,488
Storm reserve liability	213		453
Accrued expenses	3,335		9,007
Other	11,239		2,955
Total deferred income tax assets	$	22,578	$	18,940
Deferred Income Taxes Per Consolidated Balance Sheets	$	259,082	$	256,167

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Long-Term Debt

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2023		2022
Uncollateralized Senior Notes:
5.93% notes, due October 31, 2023	$	—	$	3,000
5.68% notes, due June 30, 2026	8,700		11,600
6.43% notes, due May 2, 2028	3,500		4,200
3.73% notes, due December 16, 2028	10,000		12,000
3.88% notes, due May 15, 2029	30,000		35,000
3.25% notes, due April 30, 2032	59,500		66,500
3.48% notes, due May 31, 2038	50,000		50,000
3.58% notes, due November 30, 2038	50,000		50,000
3.98% notes, due August 20, 2039	100,000		100,000
2.98% notes, due December 20, 2034	70,000		70,000
3.00% notes, due July 15, 2035	50,000		50,000
2.96% notes, due August 15, 2035	40,000		40,000
2.49% notes, due January 25, 2037	50,000		50,000
2.95% notes, due March 15, 2042	50,000		50,000
5.43% notes, due March 14, 2038	80,000		—
6.39% notes, due December 2026	100,000		—
6.44% notes, due December 2027	100,000		—
6.45% notes, due December 2028	100,000		—
6.62% notes, due December 2030	100,000		—
6.71% notes, due December 2033	100,000		—
6.73% notes, due December 2038	50,000		—
Equipment security note
2.46% note, due September 24, 2031	7,633		8,517
Less: debt issuance costs	(3,753)		(946)
Total long-term debt	1,205,580		599,871
Less: current maturities	(18,505)		(21,483)
Total long-term debt, net of current maturities	$	1,187,075	$	578,388

Terms of the Senior Notes

All of our outstanding Senior Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

Senior Notes

On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG which closed during the fourth quarter of 2023. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes 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 March 14, 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.

Annual Maturities

Annual maturities and principal repayments of long-term debt are as follows:

Year	2024		2025		2026		2027		2028		Thereafter		Total
(in thousands)
Payments	$	18,505	$	25,528	$	134,551	$	131,674	$	136,699	$	762,376	$	1,209,333

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended these Shelf Agreements, which expanded the total borrowing capacity and extended the term of the agreements for an additional three years to 2026. The following table summarizes the current available capacity under our Shelf Agreements at December 31, 2023:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	405,000	$	(300,000)	$	—	$	105,000
MetLife Shelf Agreement	200,000		(50,000)		—		150,000
Total	$	605,000	$	(350,000)	$	—	$	255,000

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Short-Term Borrowing

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Short-Term Borrowing

SHORT-TERM BORROWINGS

We are authorized by our Board of Directors to borrow up to $375.0 million of short-term debt, as required. At December 31, 2023 and 2022, we had $179.9 million and $202.2 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.83 percent and 5.04 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2023.

We have entered into several amendments to our Revolver which resulted in modifications to both tranches of the facility. The most recent amendment in October 2023 allowed for a change in our funded indebtedness ratio from 65 percent to 70 percent during the quarter in which the acquisition of FCG is consummated and the quarter subsequent to the closing of the acquisition. The amendment in August 2023 served to renew the 364-day tranche of the Revolver, providing for $175.0 million of short-term debt capacity. Additionally, the amendment for borrowings under the 364-day tranche shall now 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. Further, the amendment provided that borrowings under the 364-day green loan sublimit shall now bear interest at (i) the SOFR rate plus a 10-basis point credit spread adjustment and an applicable margin of 1.00 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate plus 0.05 percent or less, solely at our discretion. The amendment entered into in 2022 served to reset the benchmark interest rate to SOFR and to eliminate a previous covenant which capped our investment limit to $150.0 million for investments where we maintain less than 50 percent ownership.

The 364-day tranche of the Revolver expires in August 2024 and the five-year tranche expires in August 2026. Borrowings under both tranches of the Revolver are 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. As of December 31, 2023, the pricing under the 364-day tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 75-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances. As of December 31, 2023, the pricing under the five-year tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 95-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances.

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio as described above. As of December 31, 2023, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, 2023 was $188.1 million. As of December 31, 2023, we had issued $7.0 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.

In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 15, Stockholders Equity.

For additional information on interest rate swaps related to our short-term borrowings, see Note 8, Derivative Instruments.

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Leases

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Leases

LEASES

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These lease arrangements enable us to better conduct business operations in the regions in which we operate. Office space is leased to provide adequate workspace for our employees in several locations throughout our service territories. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at December 31, 2023, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of December 31, 2023, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income:

		Year Ended
		December 31,
(in thousands)	Classification	2023		2022
Operating lease cost (1)	Operations expense	$	3,040	$	2,883

(1) Includes short-term leases and variable lease costs, which are immaterial.

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2023 and 2022:

(in thousands)	Balance sheet classification	December 31, 2023		December 31, 2022
Assets
Operating lease assets	Operating lease right-of-use assets	$	12,426	$	14,421
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	2,454	$	2,552
Noncurrent
Operating lease liabilities	Operating lease - liabilities	10,550		12,392
Total lease liabilities		$	13,004	$	14,944

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2023 and 2022:

	December 31, 2023		December 31, 2022
Weighted-average remaining lease term (in years)
Operating leases	8.1		8.5
Weighted-average discount rate
Operating leases	3.5	%	3.4	%

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2023 and 2022:

	Year Ended December 31,
(in thousands)	2023		2022
Operating cash flows from operating leases	$	2,906	$	2,931

The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2023 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2024	$	2,771
2025	2,288
2026	1,774
2027	1,583
2028	1,205
Thereafter	5,243
Total lease payments	14,864
Less: Interest	(1,860)
Present value of lease liabilities	$	13,004

(1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

STOCKHOLDERS' EQUITY

Common Stock Issuances

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.

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and our previous ATM programs. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. There were no issuances under the DRIP in 2023. In 2022, we issued less than 0.1 million shares at an average price per share of $136.26 and received net proceeds of $4.5 million under the DRIP. Our most recent ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $75 million, expired in June 2023.

Net proceeds from share issuances under our DRIP and ATM programs are used for general corporate purposes including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Accumulated Other Comprehensive Income (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contract cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2023 and 2022. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items		Commodity Contract Cash Flow Hedges		Interest Rate Swap Cash Flow Hedges		Total
(in thousands)
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303
Other comprehensive income (loss) before reclassifications	705		(934)		—		(229)
Amounts reclassified from accumulated other comprehensive income (loss)	57		(2,545)		35		(2,453)
Net current-period other comprehensive income (loss)	762		(3,479)		35		(2,682)
As of December 31, 2022	(2,506)		1,092		35		(1,379)
Other comprehensive income (loss) before reclassifications	(110)		(1,322)		473		(959)
Amounts reclassified from accumulated other comprehensive income (loss)	32		(44)		(388)		(400)
Net current-period other comprehensive income (loss)	(78)		(1,366)		85		(1,359)
As of December 31, 2023	$	(2,584)	$	(274)	$	120	$	(2,738)

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Employee Benefit Plans

EMPLOYEE BENEFIT PLANS

We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year. The changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs are recorded as a component of other comprehensive income (loss) or a regulatory asset.

Defined Benefit Pension Plans

At December 31, 2023 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake Supplemental Executive Retirement Plan ("SERP").

The FPU Pension Plan, a qualified plan, covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the FPU merger, the FPU Pension Plan was frozen with respect to additional years of service and compensation, effective December 31, 2009.

The Chesapeake SERP, a nonqualified plan, is comprised of two sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. The second sub-plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit.

The unfunded liability for all plans at both December 31, 2023 and 2022, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedules set forth the funded status at December 31, 2023 and 2022 and the net periodic cost (benefit) for the years ended December 31, 2023, 2022 and 2021 for the FPU Pension Plan and the Chesapeake SERP:

	FPU Pension Plan						Chesapeake SERP
At December 31,	2023			2022			2023			2022
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	49,941		$	67,030		$	1,659		$	2,096
Interest cost	2,495			1,781			81			50
Actuarial (gain) loss	454			(15,713)			48			(335)
Benefits paid	(3,233)			(3,157)			(152)			(152)
Benefit obligation — end of year	49,657			49,941			1,636			1,659
Change in plan assets:
Fair value of plan assets — beginning of year	46,203			58,712			—			—
Actual return on plan assets	6,462			(9,552)			—			—
Employer contributions	—			200			152			152
Benefits paid	(3,233)			(3,157)			(152)			(152)
Fair value of plan assets — end of year	49,432			46,203			—			—
Accrued pension cost / funded status	$	(225)		$	(3,738)		$	(1,636)		$	(1,659)
Assumptions:
Discount rate	5.00		%	5.25		%	4.88		%	5.00		%
Expected return on plan assets	6.00		%	6.00		%	—		%	—		%

	FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2023			2022			2021			2023			2022			2021
(in thousands)
Components of net periodic pension cost:
Interest cost	$	2,495		$	1,781		$	1,714		$	81		$	50		$	48
Expected return on assets	(2,670)			(3,430)			(3,306)			—			—			—
Amortization of actuarial loss	407			466			612			8			28			28
Total periodic cost	$	232		$	(1,183)		$	(980)		$	89		$	78		$	76
Assumptions:
Discount rate	5.25		%	2.75		%	2.50		%	5.00		%	2.50		%	2.25		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	—		%	—		%	—		%

During the fourth quarter of 2021, we formally terminated the Chesapeake Pension Plan. Total periodic cost for the plan during that year was $2.0 million attributable to a settlement charge.

Our funding policy provides that payments to the trust of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2023, 2022 and 2021:

	FPU Pension Plan
At December 31,	2023		2022		2021
Asset Category
Equity securities	50	%	53	%	52	%
Debt securities	49	%	38	%	38	%
Other	1	%	9	%	10	%
Total	100	%	100	%	100	%

The investment policy of the FPU Pension Plan is designed to provide the capital assets necessary to meet the financial obligations of the plan. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plan, earn a competitive return to increasingly fund a large portion of the plan’s retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain the appropriate mix of investments to reduce the risk of large losses over the expected remaining life of the plan.

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives:

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	33	%	57	%
Fixed Income (Inflation Bond and Taxable Fixed)	38	%	58	%
Foreign Equities (Developed and Emerging Markets)	3	%	7	%
Cash	0	%	5	%

Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance. At December 31, 2023 and 2022, the assets of the FPU Pension Plan were comprised of the following investments:

	Fair Value Measurement Hierarchy
	For Year Ended December 31,
Asset Category	2023		2022
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	15,360	$	3,413
U.S. Mid Cap (1)	4,271		1,425
U.S. Small Cap (1)	2,518		692
International (2)	2,499		9,352
Alternative Strategies (3)	—		4,824
	24,648		19,706
Mutual Funds - Debt securities
Fixed income (4)	24,228		15,343
High Yield (4)	—		2,269
	24,228		17,612
Mutual Funds - Other
Commodities (5)	—		1,832
Real Estate (6)	—		1,709
Guaranteed deposit (7)	556		398
	556		3,939
Total Pension Plan Assets in fair value hierarchy (8)	49,432		41,257
Investments measured at net asset value (9)	—		4,946
Total Pension Plan Assets	$	49,432	$	46,203

(1) Includes funds that invest primarily in United States common stocks.

(2) Includes funds that invest primarily in foreign equities and emerging markets equities.

(3) Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

(4) Includes funds that invest in investment grade and fixed income securities.

(5) Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

(6) Includes funds that invest primarily in real estate.

(7) Includes investment in a group annuity product issued by an insurance company.

(8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

(9) Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

At December 31, 2023 and 2022, our pension plan investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees. Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy and are presented in the table above to reconcile to total pension plan assets.

The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial.

Other Postretirement Benefits Plans

We sponsor two defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. At December 31, 2023 and 2022, the funded status of the Chesapeake Postretirement Plan was $1.1 million and $0.6 million, respectively. The funded status of the FPU Medical Plan was $0.4 million and $0.7 million as of December 31, 2023 and 2022, respectively.

Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2023, 2022, and 2021.

As of December 31, 2023, there was $12.8 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $10.8 million and $1.2 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $3.2 million recorded in accumulated other comprehensive income (loss) and $8.7 million recorded as a regulatory asset at December 31, 2023.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset the portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2023, considering the expected lives of each of the plans. In determining the average expected return on plan assets for the FPU Pension Plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the FPU Pension Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable.

The health care inflation rate for 2023 used to calculate the benefit obligation is 5 percent for medical and 6 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5 percent for both medical and prescription drugs for the FPU Medical Plan.

Estimated Future Benefit Payments

In 2024, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.2 million are expected for the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan combined.

The schedule below shows the estimated future benefit payments for each of the plans previously described:

	FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2024	$	3,528	$	151	$	42	$	35
2025	$	3,603	$	164	$	46	$	35
2026	$	3,617	$	161	$	45	$	34
2027	$	3,616	$	158	$	48	$	33
2028	$	3,651	$	154	$	49	$	32
Years 2029 through 2033	$	17,951	$	689	$	299	$	143

(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

(2) Benefit payments are expected to be paid out of our general funds.

Retirement Savings Plan

We sponsor a 401(k) Retirement Savings Plan which is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum of six percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of ten percent. All contributions and matched funds can be invested among the mutual funds available for investment.

Employer contributions to our Retirement Savings Plan totaled $6.6 million, $6.2 million, and $5.9 million for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023, there were 798,586 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan.

Non-Qualified Deferred Compensation Plan

Members of our Board of Directors and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up to six percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of deferred compensation to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier or later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years.

All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of cash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. Deferred stock compensation may not be diversified. The participants are credited with dividends on their deferred common stock units in the same amount that is received by all other stockholders. Such dividends are reinvested into additional deferred common stock units. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheet, had a fair value of $12.3 million and $10.6 million at December 31, 2023 and 2022, respectively. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

Deferrals of officer base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares and directors' stock retainers are made in the form of deferred common stock units and are paid out in shares of our common stock, on a one-for-one basis, except that cash is paid in lieu of fractional shares. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheets and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Non-Qualified Deferred Compensation Plan totaled $9.1 million and $7.1 million at December 31, 2023 and 2022, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheet.

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Share-Based Compensation Plans

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Share-Based Compensation Plans

SHARE-BASED COMPENSATION PLANS

Our key employees and non-employee directors have been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted, and the number of shares to be issued at the end of the service period. We have 561,115 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2023, 2022 and 2021:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Awards to key employees	$	6,716	$	5,479	$	5,163
Awards to non-employee directors	906		959		782
Total compensation expense	7,622		6,438		5,945
Less: tax benefit	(1,947)		(1,663)		(1,535)
Share-based compensation amounts included in net income	$	5,675	$	4,775	$	4,410

Officers and Key Employees

Our Compensation Committee is authorized to grant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals and subject to SEC transfer restrictions once awarded. Our President and CEO has the right to issue awards of shares of our common stock, to other officers and key employees of the Company, contingent upon various performance goals and subject to SEC transfer restrictions.

We currently have several outstanding multi-year performance plans, which are based upon the successful achievement of long-term goals, growth and financial results and comprise both market-based and performance-based conditions and targets. The fair value per share, tied to a performance-based condition or target, is equal to the market price per share on the grant date. For the market-based conditions, we used a Monte Carlo valuation to estimate the fair value of each share granted.

The table below presents the summary of the stock activity for awards to all officers:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2021	197,398	$	94.15
Granted	69,620	117.61
Vested	(60,191)	90.60
Expired	(2,678)	91.42
Outstanding — December 31, 2022	204,149	103.17
Granted	80,820	126.06
Vested	(68,302)	91.59
Expired	(2,053)	94.64
Forfeited	(1,490)	113.44
Outstanding — December 31, 2023	213,124	$	117.74

During the year ended December 31, 2023, we granted awards of 80,820 shares of common stock to officers and key employees under the SICP, including awards granted in February 2023 and to key employees appointed to officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2025.

The aggregate intrinsic value of the SICP awards granted was $22.5 million, $24.1 million, and $28.8 million at December 31, 2023, 2022 and 2021, respectively. At December 31, 2023, there was $6.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2025.

In March 2023, 2022 and 2021, upon the election by certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in March 2023, 2022 and 2021 for the performance periods ended December 31, 2022, 2021, and 2020. We paid the balance of such awarded shares to each such executive officer and remitted the cash equivalent of the withheld shares to the appropriate taxing authorities. The below table presents the number of shares withheld and amounts remitted:

	For the Year Ended December 31,
	2023		2022		2021
(amounts in thousands, except shares)
Shares withheld to satisfy tax obligations	19,859		21,832		14,020
Amounts remitted to tax authorities to satisfy obligations	$	2,455	$	2,838	$	1,478

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Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Rates and Other Regulatory Activities

RATES AND OTHER REGULATORY ACTIVITIES

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively.

Refer to the additional details below pertaining to the Customer Information System Regulatory Asset Petition and COVID-19 impact.

Delaware

The October 2, 2023, application for the issuance of common stock and long-term debt was unanimously approved on October 25, 2023, by the Delaware PSC.

In September 2023, the Delaware Division submitted the Energy Efficiency Rider application for natural gas with the Delaware PSC after obtaining an affirmative recommendation from the Delaware Energy Efficiency Advisory Council (“EEAC”). The application is the first in the state and applies to a portfolio of four programs including, Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and standard Offer Program in which customers can participate and allow for recovery. The evidentiary hearing on this matter is set for April 2024. If approved as filed, rates will be effective May 1, 2024.

Maryland

On October 2, 2023, Chesapeake filed a notification of the financing plans associated with the FCG acquisition with the Maryland PSC. The filing was successfully noted during the November 1, 2023, Maryland PSC administrative meeting.

Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $6.9 million; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses under the new corporate entity which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. The outcome of the application is subject to review and approval by the Maryland PSC.

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. If approved, new rates will become effective retroactively on January 1, 2023.

Ocean City Maryland Reinforcement: During the second quarter of 2022, we began construction of an extension of service into North Ocean City, Maryland. Our Delaware natural gas division and Sandpiper installed approximately 5.4 miles of pipeline across southern Sussex County, Delaware to Fenwick Island, Delaware and Worcester County, Maryland. The project reinforces our existing system in Ocean City, Maryland and enables incremental growth along the pipeline. Construction of this project was completed in the second quarter of 2023. The Company filed a natural gas rate case application with the PSC for the state of Maryland in January 2024 as discussed above.

Florida

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

Florida Natural Gas Rate Case: In May 2022, our legacy natural gas distribution businesses in Florida filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 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 rate structure across the businesses and to unify the Florida Natural Gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment

recorded at the time of the FPU merger in our revenue requirement; and (v) 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. The discovery process and subsequent hearings were concluded during the fourth quarter of 2022 and briefs were submitted during the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023.

FCG Natural Gas Rate Case: In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed RSAM with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. On June 23, 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied on September 12, 2023. On July 7, 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief on January 31, 2024.

The RSAM is recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM is calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve months regulatory base net operating income, which primarily includes the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items is adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. For the year ended December 31, 2023, the Company recorded decreases to asset removal costs and depreciation expense of $5.1 million as a result of the RSAM adjustment.

Beachside Pipeline Extension: 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 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida area, traveling east under the Intercoastal Waterway and southward on the barrier island. The project was placed in-service during April 2023.

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 Dt/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. The petition was approved by the Florida PSC in October 2022, and the expansion was placed into service during the third quarter of 2023.

Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operations' SPP was filed during the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. The Company filed 2024 SPPCRC projections on May 1, 2023. A hearing was held on September 12, 2023. The Commission voted to approve the projections on November 9, 2023. FPU projects to spend $13.6 million on the program in 2024.

Lake Wales Pipeline Acquisition: 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 Dt/d of firm service in the Lake Wales, Florida area. The Commission approved the petition in April 2023. Approval of the agreement allowed Peninsula Pipeline to complete the acquisition of the existing pipeline in May 2023 which is being utilized to serve both current and new natural gas customers.

GUARD: 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.

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 Dt/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 propane community gas systems in Newberry was made in November 2023, and the Florida PSC is scheduled to vote on this in March 2024. The Company anticipates beginning the conversions of the community gas systems in the second quarter of 2024.

Amendment to Escambia County Agreement: In April of 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to an existing contract with FPU. This amendment will allow Peninsula Pipeline to construct an additional delivery point on a pipeline located in Escambia County. The additional delivery point comes at the request of an FPU customer and will be used to enhance natural gas service in the area. The amendment was approved by the Florida PSC in the third quarter of 2023.

Florida Electric Depreciation Study: The Florida PSC requires electric utilities to file a depreciation study every four years to reevaluate and set depreciation rates for the utility's plant assets. In June 2023, FPU filed a petition with the Florida PSC for approval of its proposed depreciation rates, which was approved in December 2023.

East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that 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/day and 3,400 Dts/day, respectively.

Eastern Shore

Southern Expansion Project: In January 2022, Eastern Shore submitted a prior notice filing with the FERC pursuant to blanket certificate procedures, regarding its proposal to install an additional compressor unit and related facilities at Eastern Shore's compressor station in Bridgeville, Sussex County, Delaware. The project enables Eastern Shore to provide additional firm natural gas transportation service to an existing shipper on its pipeline system. The project obtained FERC approval in December 2022 and went into service in October 2023.

Capital Cost Surcharge: In December 2022, 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 as a result of mandated highway relocation projects as well as compliance with the 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 on December 19, 2022. The combined revised surcharge became effective January 1, 2023.

Worcester Resiliency Upgrade: In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. Eastern Shore has requested certificate authorization by December 2024, with a target in-service date by the third quarter of 2025.

Various Jurisdictional Activity Related to the Joint Customer Information System Project

In July 2022, we filed a joint petition for our natural gas divisions in Maryland (Maryland Division, Sandpiper, and Elkton Gas) for the approval to establish a regulatory asset for non-capitalizable expenses related to the initial development and implementation of our new Customer Information System ("CIS") system. The petition was approved by the Maryland PSC in August 2022. A similar petition for our Florida Regulated Energy businesses was filed during the same time frame, however, the Florida PSC approved capitalization of these expenses in lieu of establishment of regulatory assets. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. We have completed the system selection process and the CIS implementation began during the first quarter of 2023.

COVID-19 Impact

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued to impact economic conditions, to a lesser extent, through 2021 and 2022. Chesapeake Utilities is considered an “essential business,” which allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place.

In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during the height of the pandemic. In April and May 2020, we were authorized by the Maryland and Delaware PSCs, respectively, to record regulatory assets for COVID-19 related costs which offered us the ability to seek recovery of those costs. In July 2021, the Florida PSC issued an order that approved incremental expenses we incurred due to COVID-19. The order allowed us to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021 for natural gas and electric distribution operations. The regulatory asset is being amortized over two years and is recovered through the Purchased Gas Adjustment and Swing Service mechanisms for our natural gas distribution businesses and through the Fuel Purchased Power Cost Recovery clause for our electric division. As of December 31, 2023 and 2022, our total COVID-19 regulatory asset balance was $0.2 million and $1.2 million, respectively.

Summary TCJA Table

Customer rates for our regulated business were adjusted, as approved by the regulators, prior to 2020 except for Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarized the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of December 31, 2023 and 2022:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	December 31, 2023	December 31, 2022	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Chesapeake Delaware natural gas division (Delaware PSC)	$12,038	$12,230	PSC approved amortization of ADIT in January 2019.
Chesapeake Maryland natural gas division (Maryland PSC)	$3,585	$3,703	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,487	$3,597	PSC approved amortization of ADIT in May 2018.
Florida Natural Gas distribution (Florida PSC) (1)	$26,757	$27,179	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU electric division (Florida PSC)	$4,760	$4,993	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,027	$1,059	PSC approved amortization of ADIT in March 2018.

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

Regulatory Assets and Liabilities

At December 31, 2023 and 2022, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

	As of December 31,
	2023		2022
(in thousands)
Regulatory Assets
Under-recovered purchased fuel, gas and conservation cost recovery (1) (2)	$	13,696	$	43,583
Under-recovered GRIP revenue (3)	1,777		1,705
Deferred postretirement benefits (4)	10,802		13,927
Deferred conversion and development costs (1)	21,466		23,653
Acquisition adjustment (5)	31,857		25,609
Deferred costs associated with COVID-19 (6)	190		1,233
Deferred storm costs (7)	19,370		27,687
Deferred rate case expenses - current	1,171		—
Other	15,573		12,256
Total Regulatory Assets	$	115,902	$	149,653
Regulatory Liabilities
Self-insurance (8)	$	521	$	339
Over-recovered purchased fuel and conservation cost recovery (1)	12,340		3,827
Over-recovered GRIP revenue (3)	501		—
Storm reserve (8)	1,900		2,845
Accrued asset removal cost (9)	86,534		50,261
Deferred income taxes due to rate change (10)	105,055		87,690
Interest related to storm recovery (7)	536		1,207
Other	1,611		1,851
Total Regulatory Liabilities	$	208,998	$	148,020

(1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

(2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

(3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16, Employee Benefit Plans, for additional information.

(5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above.

(6) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs.

(7) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets.

(8) We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

(9) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(10) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

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Environmental Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Environmental Commitments and Contingencies

ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

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

MGP Sites

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

As of December 31, 2023 and 2022, we had approximately $3.6 million and $4.3 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2023 and 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs from customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval for and has recovered, through a combination of insurance and customer rates, $14.0 million of its environmental costs related to its MGP sites as of December 31, 2023.

Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial.

The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million.

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Other Commitments and Contingencies

OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

In March 2023, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2023 and expire in March 2026.

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

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

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of December 31, 2023, FPU was in compliance with all of the requirements of its supply contracts.

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

The total purchase obligations for natural gas, electric and propane supplies are as follows:

Year	2024		2025-2026		2027-2028		Beyond 2028		Total
(in thousands)
Purchase Obligations	$	86,040	$	105,082	$	83,851	$	141,287	$	416,260

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of December 31, 2023 was $35.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2023 was approximately $24.3 million with the guarantees expiring on various dates through December 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2023 was $4.0 million.

As of December 31, 2023, we have issued letters of credit totaling approximately $7.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the capacity agreement between NEXUS and Aspire, and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 2024 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Use of Estimates

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

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 owned by 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, 2023 and 2022 is provided in the following table:

	As of December 31,
(in thousands)	2023		2022
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida (1)	$	1,486,796	$	925,501
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	788,185		741,865
Electric distribution	143,513		135,633
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	194,918		185,090
Natural gas transmission and supply – Ohio	134,192		128,620
Electricity and steam generation	37,064		36,886
Mobile CNG and pipeline solutions	40,558		38,543
Sustainable energy investments, including renewable natural gas	4,076		4,076
Other	30,309		29,890
Total property, plant and equipment	2,859,611		2,226,104
Less: Accumulated depreciation and amortization	(516,429)		(462,926)
Plus: Construction work in progress	113,192		47,295
Net property, plant and equipment	$	2,456,374	$	1,810,473

(1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition.

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, 2023 and 2022, the non-refundable contributions totaled $4.2 million and $7.6 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 the years ended December 31, 2023, 2022 and 2021, AFUDC was immaterial and was reflected as a reduction of interest charges.

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.

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.

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. See Note 14, Leases, for additional information.

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, 2023, 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 $2.2 million and $1.5 million at December 31, 2023 and 2022, 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

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, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 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, 2023, 2022 and 2021:

	2023	2022	2021
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida (1) (2)	2.2%	2.5%	2.5%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.4%	2.4%	2.3%
Natural gas transmission – Ohio	5.0%	5.0%	N/A
Electric distribution	2.4%	2.8%	2.8%

(1) Excludes the acquisition of FCG which was completed on November 30, 2023.

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

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

Regulated Operations

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.

Operating Revenues

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.

Cost of Sales

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

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

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 Doubtful Accounts

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. The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2023:

(in thousands)
Balance at December 31, 2022	$	2,877
Additions:
Provision for credit losses	2,340
Recoveries	166
Deductions:
Write offs	(2,684)
Balance at December 31, 2023	$	2,699

Inventories

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, 2023, 2022 or 2021.

Goodwill and Other Intangible Assets

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, 2023, 2022 and 2021. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

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 Retirement Obligation [Policy Text Block]

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

Pension and Other Postretirement Plans

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 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 and Investment Tax Credit Adjustments

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 net of any valuation allowance when it is more likely than not that such income tax benefits will 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

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.

Recently Adopted Accounting Standards

Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]

Recent Accounting Standards Yet to be Adopted

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

Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2024. ASU 2023-09 only impacts disclosures, and as a result, will not have a material impact on our financial position or results of operations.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2023

Accounting Policies [Abstract]

Property, Plant and Equipment [Table Text Block]

A summary of property, plant and equipment by classification as of December 31, 2023 and 2022 is provided in the following table:

	As of December 31,
(in thousands)	2023		2022
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida (1)	$	1,486,796	$	925,501
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida	788,185		741,865
Electric distribution	143,513		135,633
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	194,918		185,090
Natural gas transmission and supply – Ohio	134,192		128,620
Electricity and steam generation	37,064		36,886
Mobile CNG and pipeline solutions	40,558		38,543
Sustainable energy investments, including renewable natural gas	4,076		4,076
Other	30,309		29,890
Total property, plant and equipment	2,859,611		2,226,104
Less: Accumulated depreciation and amortization	(516,429)		(462,926)
Plus: Construction work in progress	113,192		47,295
Net property, plant and equipment	$	2,456,374	$	1,810,473

(1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition.

Annual Depreciation Rates Table [Table Text Block]

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, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 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, 2023, 2022 and 2021:

	2023	2022	2021
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida (1) (2)	2.2%	2.5%	2.5%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.7%
Natural gas transmission – Florida	2.4%	2.4%	2.3%
Natural gas transmission – Ohio	5.0%	5.0%	N/A
Electric distribution	2.4%	2.8%	2.8%

(1) Excludes the acquisition of FCG which was completed on November 30, 2023.

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

Estimated Useful Life Of Assets Table [Table Text Block]

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

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Calculations of Basic and Diluted Earnings Per Share

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

	For the Year Ended December 31,
	2023		2022		2021
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	87,212	$	89,796	$	83,466
Weighted average shares outstanding (1)	18,370,758		17,722,227		17,558,078
Basic Earnings Per Share	$	4.75	$	5.07	$	4.75
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic (1)	18,370,758		17,722,227		17,558,078
Effect of dilutive securities — Share-based compensation	64,099		82,067		74,951
Adjusted denominator — Diluted (1)	18,434,857		17,804,294		17,633,029
Diluted Earnings Per Share	$	4.73	$	5.04	$	4.73

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Acquisitions (Tables)

12 Months Ended

Dec. 31, 2023

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Acquisitions Florida City Gas Pro forma

For the Year Ended December 31,
	2023		2022
(in thousands)
Operating Revenue	$	786,473	$	798,355
Net Income	$	85,398	$	81,508

Florida City Gas Purchas Price Allocation

(in thousands)
Assets acquired:	Acquisition Date Fair Value
Cash	$	2,270
Accounts receivable, net	14,396
Regulatory assets - current	2,983
Other current assets	2,707
Property, plant and equipment	453,845
Goodwill	461,193
Regulatory assets - non-current	3,381
Other deferred charges and other assets,	18,309
Total assets acquired	959,084
Liabilities assumed:
Current liabilities	(20,954)
Regulatory liabilities	(14,137)
Other deferred credits and other liabilities	(548)
Total liabilities assumed	(35,639)
Net purchase price	$	923,445

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Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2023

Dec. 31, 2022

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

for the years ended December 31, 2023, 2022 and 2021:

	For the year ended December 31, 2023
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	83,882	$	—	$	—	$	83,882
Florida Natural Gas distribution (1)	168,360		—		—		168,360
Florida City Gas (2)	12,073		—		—		12,073
FPU electric distribution	99,474		—		—		99,474
Maryland natural gas division	28,092		—		—		28,092
Sandpiper natural gas/propane operations	20,185		—		—		20,185
Elkton Gas	8,814		—		—		8,814
Total energy distribution	420,880		—		—		420,880
Energy transmission
Aspire Energy	—		37,139		—		37,139
Aspire Energy Express	1,478		—		—		1,478
Eastern Shore	79,923		—		—		79,923
Peninsula Pipeline	30,400		—		—		30,400
Total energy transmission	111,801		37,139		—		148,940
Energy generation
Eight Flags	—		19,207		—		19,207
Propane operations
Propane distribution operations	—		154,748		—		154,748
Compressed Natural Gas Services
Marlin Gas Services	—		12,300		—		12,300
Other and eliminations
Eliminations	(59,086)		(246)		(26,321)		(85,653)
Other	—		—		182		182
Total other and eliminations	(59,086)		(246)		(26,139)		(85,471)
Total operating revenues (3)	$	473,595	$	223,148	$	(26,139)	$	670,604

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions, and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

(3) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 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 for Maryland division and Sandpiper and late fees.

	For the year ended December 31, 2022
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	82,176	$	—	$	—	$	82,176
Florida Natural Gas distribution (1)	155,870		—		—		155,870
FPU electric distribution	81,714		—		—		81,714
Maryland natural gas division	26,607		—		—		26,607
Sandpiper natural gas/propane operations	21,278		—		—		21,278
Elkton Gas	9,198		—		—		9,198
Total energy distribution	376,843		—		—		376,843
Energy transmission
Aspire Energy	—		56,225		—		56,225
Aspire Energy Express	1,377		—		—		1,377
Eastern Shore	78,624		—		—		78,624
Peninsula Pipeline	27,263		—		—		27,263
Total energy transmission	107,264		56,225		—		163,489
Energy generation
Eight Flags	—		25,318		—		25,318
Propane operations
Propane distribution operations	—		188,412		—		188,412
Compressed Natural Gas Services
Marlin Gas Services	—		11,159		—		11,159
Other and eliminations
Eliminations	(54,683)		(364)		(29,778)		(84,825)
Other	—		—		308		308
Total other and eliminations	(54,683)		(364)		(29,470)		(84,517)
Total operating revenues (2)	$	429,424	$	280,750	$	(29,470)	$	680,704

    

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 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 for Maryland division and Sandpiper and late fees

	For the year ended December 31, 2021
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	71,195	$	—	$	—	$	71,195
Florida Natural Gas distribution (1)	134,609		—		—		134,609
FPU electric distribution	78,300		—		—		78,300
Maryland natural gas division	22,449		—		—		22,449
Sandpiper natural gas/propane operations	20,746		—		—		20,746
Elkton Gas	7,105		—		—		7,105
Total energy distribution	334,404		—		—		334,404
Energy transmission
Aspire Energy	—		38,163		—		38,163
Aspire Energy Express	187		—		—		187
Eastern Shore	76,911		—		—		76,911
Peninsula Pipeline	26,630		—		—		26,630
Total energy transmission	103,728		38,163		—		141,891
Energy generation
Eight Flags	—		18,652		—		18,652
Propane operations
Propane distribution operations	—		142,082		—		142,082
Compressed Natural Gas Services
Marlin Gas Services	—		8,315		—		8,315
Other and eliminations
Eliminations	(54,212)		(343)		(21,348)		(75,903)
Other	—		—		527		527
Total other and eliminations	(54,212)		(343)		(20,821)		(75,376)
Total operating revenues (2)	$	383,920	$	206,869	$	(20,821)	$	569,968

(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order.

(2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 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 for Maryland division and Sandpiper and late fees.

Contract with Customer, Asset and Liability [Table Text Block]

The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2023 and 2022 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2022	$	61,687	$	18	$	4,321	$	983
Balance at 12/31/2023	67,741		18		3,524		1,022
Increase (decrease)	$	6,054	$	—	$	(797)	$	39

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Revenue for these businesses for the remaining performance obligations at December 31, 2023 are expected to be recognized as follows:

(in thousands)	2024		2025		2026		2027		2028		2029 and thereafter
Eastern Shore and Peninsula Pipeline	$	36,657	$	30,330	$	26,547	$	23,433	$	22,559	$	149,124
Natural gas distribution operations	9,680		9,216		8,501		6,472		5,252		28,428
FPU electric distribution	652		275		275		275		275		—
Total revenue contracts with remaining performance obligations	$	46,989	$	39,821	$	35,323	$	30,180	$	28,086	$	177,552

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Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2023

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment

:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	471,591	$	422,894	$	381,879
Unregulated Energy	199,013		257,810		188,089
Total operating revenues, unaffiliated customers	$	670,604	$	680,704	$	569,968
Intersegment Revenues (1)
Regulated Energy	$	2,004	$	6,530	$	2,041
Unregulated Energy	24,135		22,940		18,780
Other businesses	182		308		527
Total intersegment revenues	$	26,321	$	29,778	$	21,348
Operating Income
Regulated Energy	$	126,199	$	115,317	$	106,174
Unregulated Energy	24,426		27,350		24,427
Other businesses and eliminations	178		266		511
Operating Income	150,803		142,933		131,112
Other income, net	1,438		5,051		1,720
Interest charges	36,951		24,356		20,135
Income before Income Taxes	115,290		123,628		112,697
Income Taxes	28,078		33,832		29,231
Net Income	$	87,212	$	89,796	$	83,466
Depreciation and Amortization
Regulated Energy (2)	$	48,162	$	52,707	$	48,748
Unregulated Energy	17,347		16,257		13,869
Other businesses and eliminations	(8)		9		44
Total depreciation and amortization	$	65,501	$	68,973	$	62,661
Capital Expenditures
Regulated Energy (3)	$	1,095,871	$	97,554	$	139,733
Unregulated Energy	40,264		40,773		81,651
Other businesses	1,762		2,355		6,425
Total capital expenditures	$	1,137,897	$	140,682	$	227,809

     (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

 (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details.

 (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details.

	As of December 31,
(in thousands)	2023		2022
Identifiable Assets
Regulated Energy segment	$	2,781,581	$	1,716,255
Unregulated Energy segment	477,402		463,239
Other businesses and eliminations	45,721		35,543
Total identifiable assets	$	3,304,704	$	2,215,037

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Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2023, 2022 and 2021 were as follows:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Cash paid for interest	$	30,525	$	24,267	$	20,809
Cash (received) paid for income taxes, net of refunds	$	21,920	$	(4,963)	$	8,395

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2023, 2022, and 2021 were as follows: 

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31,	$	33,334	$	13,211	$	16,164
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	1,712
Common stock issued under the SICP	$	3,740	$	2,868	$	2,834

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of December 31, 2023, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	Purchases	18.1	Cash flow hedges	June 2026
Sharp	Propane (gallons)	Sales	3.2	Cash flow hedges	March 2024

Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets

Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2023 and 2022 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value (1)	$	702	$	3,317
Interest rate swap agreements	Derivative assets, at fair value (1)	365		452
Total Derivative Assets		$	1,067	$	3,769

 (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2023		December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value (1)	$	1,078	$	1,810
Interest rate swap agreements	Derivative liabilities, at fair value (1)	203		405
Total Derivative Liabilities		$	1,281	$	2,215

(1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

Derivative Instruments, Gain (Loss) [Table Text Block]

The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2023		2022		2021
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	—	$	56	$	(1)
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	—		—		(24)
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	1,221		(373)		(536)
Propane swap agreements	Propane and natural gas costs	(1,160)		3,881		7,187
Interest rate swap agreements	Interest expense	523		(47)		(40)
Total		$	584	$	3,517	$	6,586

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2023 and 2022, respectively:

			Fair Value Measurements Using:
As of December 31, 2023	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	1,489		—		—		1,489
Investments—mutual funds and other	10,772		10,772		—		—
Total investments	12,282		10,793		—		1,489
Derivative assets	1,067		—		1,067		—
Total assets	$	13,349	$	10,793	$	1,067	$	1,489
Liabilities:
Derivative liabilities	$	1,281	$	—	$	1,281	$	—

			Fair Value Measurements Using:
As of December 31, 2022	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	24	$	24	$	—	$	—
Investments—guaranteed income fund	1,853		—		—		1,853
Investments—mutual funds and other	8,699		8,699		—		—
Total investments	10,576		8,723		—		1,853
Derivative assets	3,769		—		3,769		—
Total assets	$	14,345	$	8,723	$	3,769	$	1,853
Liabilities:
Derivative liabilities	$	2,215	$	—	$	2,215	$	—

Schedule of Changes in Fair Value of Plan Assets

The changes in the fair value of our Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Schedule of Carrying Value of Goodwill

The carrying value of goodwill as of December 31, 2023 and 2022 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2022	$	7,689	$	38,524	$	46,213
Additions (1)	461,025		936		461,961
Balance at December 31, 2023	$	468,714	$	39,460	$	508,174

(1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details.

Schedule of Carrying Value and Accumulated Amortization of Intangible Assets

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2023 and 2022 was as follows:

	As of December 31,
	2023				2022
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships	$	17,004	$	7,146	$	16,965	$	6,131
Non-Compete agreements	3,125		1,855		3,105		1,411
Patents (1)	6,558		859		5,819		533
Other	270		232		270		225
Total	$	26,957	$	10,092	$	26,159	$	8,300

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2023

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

The following tables provide: (a) the components of income tax expense in 2023, 2022, and 2021; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2023, 2022, and 2021; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2023 and 2022.

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Current Income Tax Expense
Federal	$	14,736	$	8,284	$	2,775
State	5,496		1,948		(96)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	20,185		10,185		2,632
Deferred Income Tax Expense (1)
Property, plant and equipment	17,797		14,968		24,074
Deferred gas costs	(7,739)		8,923		1,857
Pensions and other employee benefits	(974)		1,109		(655)
FPU merger-related premium cost and deferred gain	(351)		(351)		(351)
Net operating loss carryforwards	(370)		2		97
Other	(470)		(1,004)		1,577
Total deferred income tax expense	7,893		23,647		26,599
Total Income Tax	$	28,078	$	33,832	$	29,231

(1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively.

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates

	For the Year Ended December 31,
	2023			2022			2021
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	24,214		$	25,982		$	23,666
State income taxes, net of federal benefit	4,377			7,714			6,371
ESOP dividend deduction	(184)			(177)			(180)
CARES Act Tax Benefit	—			—			(919)
Other	(329)			313			293
Total Income Tax Expense	$	28,078		$	33,832		$	29,231
Effective Income Tax Rate	24.35		%	27.34		%	25.94		%

(1) Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021.

Schedule of Accumulated Deferred Income Tax Assets and Liabilities

	As of December 31,
	2023		2022
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	252,125	$	238,687
Acquisition adjustment	5,564		5,915
Loss on reacquired debt	145		164
Deferred gas costs	3,550		11,288
Natural gas conversion costs	4,824		5,026
Storm reserve liability	5,797		5,791
Other	9,655		8,236
Total deferred income tax liabilities	$	281,660	$	275,107
Deferred income tax assets:
Pension and other employee benefits	$	4,993	$	3,985
Environmental costs	951		1,052
Net operating loss carryforwards	1,847		1,488
Storm reserve liability	213		453
Accrued expenses	3,335		9,007
Other	11,239		2,955
Total deferred income tax assets	$	22,578	$	18,940
Deferred Income Taxes Per Consolidated Balance Sheets	$	259,082	$	256,167

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2023

Text Block [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2023		2022
Uncollateralized Senior Notes:
5.93% notes, due October 31, 2023	$	—	$	3,000
5.68% notes, due June 30, 2026	8,700		11,600
6.43% notes, due May 2, 2028	3,500		4,200
3.73% notes, due December 16, 2028	10,000		12,000
3.88% notes, due May 15, 2029	30,000		35,000
3.25% notes, due April 30, 2032	59,500		66,500
3.48% notes, due May 31, 2038	50,000		50,000
3.58% notes, due November 30, 2038	50,000		50,000
3.98% notes, due August 20, 2039	100,000		100,000
2.98% notes, due December 20, 2034	70,000		70,000
3.00% notes, due July 15, 2035	50,000		50,000
2.96% notes, due August 15, 2035	40,000		40,000
2.49% notes, due January 25, 2037	50,000		50,000
2.95% notes, due March 15, 2042	50,000		50,000
5.43% notes, due March 14, 2038	80,000		—
6.39% notes, due December 2026	100,000		—
6.44% notes, due December 2027	100,000		—
6.45% notes, due December 2028	100,000		—
6.62% notes, due December 2030	100,000		—
6.71% notes, due December 2033	100,000		—
6.73% notes, due December 2038	50,000		—
Equipment security note
2.46% note, due September 24, 2031	7,633		8,517
Less: debt issuance costs	(3,753)		(946)
Total long-term debt	1,205,580		599,871
Less: current maturities	(18,505)		(21,483)
Total long-term debt, net of current maturities	$	1,187,075	$	578,388

Line of Credit Facility [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

The following table summarizes the current available capacity under our Shelf Agreements at December 31, 2023:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	405,000	$	(300,000)	$	—	$	105,000
MetLife Shelf Agreement	200,000		(50,000)		—		150,000
Total	$	605,000	$	(350,000)	$	—	$	255,000

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2023

Leases [Abstract]

Lease, Cost [Table Text Block]

		Year Ended
		December 31,
(in thousands)	Classification	2023		2022
Operating lease cost (1)	Operations expense	$	3,040	$	2,883

(1) Includes short-term leases and variable lease costs, which are immaterial.

Schedule of Leases Reported on Consolidated Statement of Financial Position [Table Text Block]

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2023 and 2022:

(in thousands)	Balance sheet classification	December 31, 2023		December 31, 2022
Assets
Operating lease assets	Operating lease right-of-use assets	$	12,426	$	14,421
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	2,454	$	2,552
Noncurrent
Operating lease liabilities	Operating lease - liabilities	10,550		12,392
Total lease liabilities		$	13,004	$	14,944

Leases, Weighted Average Remaining Lease Term [Table Text Block]

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2023 and 2022:

	December 31, 2023		December 31, 2022
Weighted-average remaining lease term (in years)
Operating leases	8.1		8.5
Weighted-average discount rate
Operating leases	3.5	%	3.4	%

Lease, Cash Flow [Table Text Block]

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2023 and 2022:

	Year Ended December 31,
(in thousands)	2023		2022
Operating cash flows from operating leases	$	2,906	$	2,931

Lessee, Operating Lease, Liability, to be Paid, Maturity

The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2023 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2024	$	2,771
2025	2,288
2026	1,774
2027	1,583
2028	1,205
Thereafter	5,243
Total lease payments	14,864
Less: Interest	(1,860)
Present value of lease liabilities	$	13,004

(1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised.

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2023

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2023 and 2022. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items		Commodity Contract Cash Flow Hedges		Interest Rate Swap Cash Flow Hedges		Total
(in thousands)
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303
Other comprehensive income (loss) before reclassifications	705		(934)		—		(229)
Amounts reclassified from accumulated other comprehensive income (loss)	57		(2,545)		35		(2,453)
Net current-period other comprehensive income (loss)	762		(3,479)		35		(2,682)
As of December 31, 2022	(2,506)		1,092		35		(1,379)
Other comprehensive income (loss) before reclassifications	(110)		(1,322)		473		(959)
Amounts reclassified from accumulated other comprehensive income (loss)	32		(44)		(388)		(400)
Net current-period other comprehensive income (loss)	(78)		(1,366)		85		(1,359)
As of December 31, 2023	$	(2,584)	$	(274)	$	120	$	(2,738)

Reclassification out of Accumulated Other Comprehensive Income

D

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2023

Schedule of Assets by Investment Type

The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2023, 2022 and 2021:

	FPU Pension Plan
At December 31,	2023		2022		2021
Asset Category
Equity securities	50	%	53	%	52	%
Debt securities	49	%	38	%	38	%
Other	1	%	9	%	10	%
Total	100	%	100	%	100	%

Schedule of Asset Allocation Strategy

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives:

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	33	%	57	%
Fixed Income (Inflation Bond and Taxable Fixed)	38	%	58	%
Foreign Equities (Developed and Emerging Markets)	3	%	7	%
Cash	0	%	5	%

Summary of Pension Plan Assets

At December 31, 2023 and 2022, the assets of the FPU Pension Plan were comprised of the following investments:

	Fair Value Measurement Hierarchy
	For Year Ended December 31,
Asset Category	2023		2022
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	15,360	$	3,413
U.S. Mid Cap (1)	4,271		1,425
U.S. Small Cap (1)	2,518		692
International (2)	2,499		9,352
Alternative Strategies (3)	—		4,824
	24,648		19,706
Mutual Funds - Debt securities
Fixed income (4)	24,228		15,343
High Yield (4)	—		2,269
	24,228		17,612
Mutual Funds - Other
Commodities (5)	—		1,832
Real Estate (6)	—		1,709
Guaranteed deposit (7)	556		398
	556		3,939
Total Pension Plan Assets in fair value hierarchy (8)	49,432		41,257
Investments measured at net asset value (9)	—		4,946
Total Pension Plan Assets	$	49,432	$	46,203

Schedule of Level Three Defined Benefit Plan Assets Roll Forward

The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial.

Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets

As of December 31, 2023, there was $12.8 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $10.8 million and $1.2 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $3.2 million recorded in accumulated other comprehensive income (loss) and $8.7 million recorded as a regulatory asset at December 31, 2023.

Schedule of Estimated Future Benefit Payments

The schedule below shows the estimated future benefit payments for each of the plans previously described:

	FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2024	$	3,528	$	151	$	42	$	35
2025	$	3,603	$	164	$	46	$	35
2026	$	3,617	$	161	$	45	$	34
2027	$	3,616	$	158	$	48	$	33
2028	$	3,651	$	154	$	49	$	32
Years 2029 through 2033	$	17,951	$	689	$	299	$	143

(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

(2) Benefit payments are expected to be paid out of our general funds.

Pension benefit

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following schedules set forth the funded status at December 31, 2023 and 2022 and the net periodic cost (benefit) for the years ended December 31, 2023, 2022 and 2021 for the FPU Pension Plan and the Chesapeake SERP:

	FPU Pension Plan						Chesapeake SERP
At December 31,	2023			2022			2023			2022
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	49,941		$	67,030		$	1,659		$	2,096
Interest cost	2,495			1,781			81			50
Actuarial (gain) loss	454			(15,713)			48			(335)
Benefits paid	(3,233)			(3,157)			(152)			(152)
Benefit obligation — end of year	49,657			49,941			1,636			1,659
Change in plan assets:
Fair value of plan assets — beginning of year	46,203			58,712			—			—
Actual return on plan assets	6,462			(9,552)			—			—
Employer contributions	—			200			152			152
Benefits paid	(3,233)			(3,157)			(152)			(152)
Fair value of plan assets — end of year	49,432			46,203			—			—
Accrued pension cost / funded status	$	(225)		$	(3,738)		$	(1,636)		$	(1,659)
Assumptions:
Discount rate	5.00		%	5.25		%	4.88		%	5.00		%
Expected return on plan assets	6.00		%	6.00		%	—		%	—		%

Component of Net Periodic Pension Cost (Benefit)

	FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2023			2022			2021			2023			2022			2021
(in thousands)
Components of net periodic pension cost:
Interest cost	$	2,495		$	1,781		$	1,714		$	81		$	50		$	48
Expected return on assets	(2,670)			(3,430)			(3,306)			—			—			—
Amortization of actuarial loss	407			466			612			8			28			28
Total periodic cost	$	232		$	(1,183)		$	(980)		$	89		$	78		$	76
Assumptions:
Discount rate	5.25		%	2.75		%	2.50		%	5.00		%	2.50		%	2.25		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	—		%	—		%	—		%

Other Postretirement Benefit Plans

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2023, 2022, and 2021.

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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2023

Share-Based Compensation Amounts Included in Net Income

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2023, 2022 and 2021:

	For the Year Ended December 31,
	2023		2022		2021
(in thousands)
Awards to key employees	$	6,716	$	5,479	$	5,163
Awards to non-employee directors	906		959		782
Total compensation expense	7,622		6,438		5,945
Less: tax benefit	(1,947)		(1,663)		(1,535)
Share-based compensation amounts included in net income	$	5,675	$	4,775	$	4,410

Cash Proceeds Received and Tax Benefit from Share-based Payment Awards [Table Text Block]

The below table presents the number of shares withheld and amounts remitted:

	For the Year Ended December 31,
	2023		2022		2021
(amounts in thousands, except shares)
Shares withheld to satisfy tax obligations	19,859		21,832		14,020
Amounts remitted to tax authorities to satisfy obligations	$	2,455	$	2,838	$	1,478

SICP Awards to Key Employees

Summary of Stock Activity Non-employee directors

The table below presents the summary of the stock activity for awards to all officers:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2021	197,398	$	94.15
Granted	69,620	117.61
Vested	(60,191)	90.60
Expired	(2,678)	91.42
Outstanding — December 31, 2022	204,149	103.17
Granted	80,820	126.06
Vested	(68,302)	91.59
Expired	(2,053)	94.64
Forfeited	(1,490)	113.44
Outstanding — December 31, 2023	213,124	$	117.74

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Rates and Other Regulatory Activities Summary of Effects of Tax Reform Impact on Regulated Businesses (Tables)

12 Months Ended

Dec. 31, 2023

Summary of Effects of Federal Tax Reform on Regulated Businesses [Abstract]

Summary of Effects of Federal Tax Reform on Regulated Businesses [Table Text Block]

	Amount (in thousands)
Operation and Regulatory Jurisdiction	December 31, 2023	December 31, 2022	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Chesapeake Delaware natural gas division (Delaware PSC)	$12,038	$12,230	PSC approved amortization of ADIT in January 2019.
Chesapeake Maryland natural gas division (Maryland PSC)	$3,585	$3,703	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,487	$3,597	PSC approved amortization of ADIT in May 2018.
Florida Natural Gas distribution (Florida PSC) (1)	$26,757	$27,179	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU electric division (Florida PSC)	$4,760	$4,993	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,027	$1,059	PSC approved amortization of ADIT in March 2018.

Schedule of Regulatory Assets [Table Text Block]

At December 31, 2023 and 2022, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

	As of December 31,
	2023		2022
(in thousands)
Regulatory Assets
Under-recovered purchased fuel, gas and conservation cost recovery (1) (2)	$	13,696	$	43,583
Under-recovered GRIP revenue (3)	1,777		1,705
Deferred postretirement benefits (4)	10,802		13,927
Deferred conversion and development costs (1)	21,466		23,653
Acquisition adjustment (5)	31,857		25,609
Deferred costs associated with COVID-19 (6)	190		1,233
Deferred storm costs (7)	19,370		27,687
Deferred rate case expenses - current	1,171		—
Other	15,573		12,256
Total Regulatory Assets	$	115,902	$	149,653
Regulatory Liabilities
Self-insurance (8)	$	521	$	339
Over-recovered purchased fuel and conservation cost recovery (1)	12,340		3,827
Over-recovered GRIP revenue (3)	501		—
Storm reserve (8)	1,900		2,845
Accrued asset removal cost (9)	86,534		50,261
Deferred income taxes due to rate change (10)	105,055		87,690
Interest related to storm recovery (7)	536		1,207
Other	1,611		1,851
Total Regulatory Liabilities	$	208,998	$	148,020

(1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

(2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

(3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16, Employee Benefit Plans, for additional information.

(5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above.

(6) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs.

(7) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets.

(8) We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

(9) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(10) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

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Environmental Commitments and Contingencies Environmental Remediation Status (Tables)

12 Months Ended

Dec. 31, 2023

Environmental Remediation Obligations [Abstract]

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million.

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Other Commitments and Contingencies Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2023

Long-term Purchase Commitment [Line Items]

Long-term Purchase Commitment [Table Text Block]

The total purchase obligations for natural gas, electric and propane supplies are as follows:

Year	2024		2025-2026		2027-2028		Beyond 2028		Total
(in thousands)
Purchase Obligations	$	86,040	$	105,082	$	83,851	$	141,287	$	416,260

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Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) mi	Dec. 31, 2022 USD ($)
Property, Plant and Equipment [Line Items]
Contributions in Aid of Construction	$ 4,200	$ 7,600
Number of Months to Establish ROU Asset and Liability	12 months
Property, plant and equipment
Total property, plant and equipment	$ 2,859,611	2,226,104
Less: Accumulated depreciation and amortization	(516,429)	(462,926)
Net property, plant and equipment	2,456,374	1,810,473
Construction Work in Progress	113,192	47,295
Jointly Owned Pipeline [Member]
Property, plant and equipment
Net property, plant and equipment	28,400
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	2,200	1,500
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	1,486,796	925,501
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	788,185	741,865
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	134,192	128,620
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	143,513	135,633
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	194,918	185,090
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	37,064	36,886
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	40,558	38,543
Other
Property, plant and equipment
Total property, plant and equipment	30,309	29,890
Other unregulated energy | Other [Member]
Property, plant and equipment
Total property, plant and equipment	$ 4,076	$ 4,076
Natural Gas Operations
Property, plant and equipment
Miles Of Natural Gas Pipeline | mi	26

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2023 USD ($) mi	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Operating Lease, Liability	$ 13,004
Number of Utilities that do not have cost recovery mechanism	1
Maturity Period To Be Considered Cash Equivalents	3 months
Contributions or Advances in Aid of Construction	$ 4,200	$ 7,600
Net property, plant and equipment	2,456,374	1,810,473
Accumulated depreciation	516,429	462,926
Depreciation and accretion reported in operations expenses	11,900	11,000	$ 10,200
Operating Lease, Right-of-Use Asset	$ 12,426	$ 14,421
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Length of pipeline | mi	26
Minimum [Member]
Summary Of Accounting Policies [Line Items]
Operating Lease, Liability	$ 11,000
Maximum
Summary Of Accounting Policies [Line Items]
Operating Lease, Liability	$ 13,000

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Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Natural gas distribution | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.50%	2.50%	2.50%
Natural gas distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.20%	2.50%	2.50%
Natural gas transmission | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.70%	2.70%	2.70%
Natural gas transmission | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.40%	2.40%	2.30%
Natural gas transmission | OHIO
Property, Plant and Equipment [Line Items]
Average depreciation rates	5.00%	5.00%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.40%	2.80%	2.80%

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Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	Dec. 31, 2023
Propane Distribution Mains [Member] | Minimum
Useful Life of Assets	10 years
Propane Distribution Mains [Member] | Maximum
Useful Life of Assets	37 years
Propane Bulk Plants And Tanks [Member] | Minimum
Useful Life of Assets	10 years
Propane Bulk Plants And Tanks [Member] | Maximum
Useful Life of Assets	40 years
Liquefied Petroleum Gas Equipment [Member] | Minimum
Useful Life of Assets	5 years
Liquefied Petroleum Gas Equipment [Member] | Maximum
Useful Life of Assets	33 years
Meters And Meter Installations [Member] | Minimum
Useful Life of Assets	5 years
Meters And Meter Installations [Member] | Maximum
Useful Life of Assets	33 years
Measuring And Regulating Station Equipment [Member] | Minimum
Useful Life of Assets	5 years
Measuring And Regulating Station Equipment [Member] | Maximum
Useful Life of Assets	37 years
Natural gas pipelines [Member] | Maximum
Useful Life of Assets	45 years
Natural gas processing equipment [Member] | Minimum
Useful Life of Assets	20 years
Natural gas processing equipment [Member] | Maximum
Useful Life of Assets	25 years
Office Furniture And Equipment [Member] | Minimum
Useful Life of Assets	3 years
Office Furniture And Equipment [Member] | Maximum
Useful Life of Assets	10 years
Transportation Equipment [Member] | Minimum
Useful Life of Assets	4 years
Transportation Equipment [Member] | Maximum
Useful Life of Assets	20 years
Structures And Improvements [Member] | Minimum
Useful Life of Assets	5 years
Structures And Improvements [Member] | Maximum
Useful Life of Assets	45 years
CHP plant | Maximum
Useful Life of Assets	30 years

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Summary of Significant Accounting Policies Effects of New Accounting Pronouncements (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Accounting Policies [Abstract]
Additions, Charged to Income	$ 2,340
Additions, Other Accounts	166
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	(2,684)
Accounts Receivable, Allowance for Credit Losses, Current, Disclosure	$ 2,699	$ 2,877

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Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Per Basic Share	$ 4.75	$ 5.07	$ 4.75
Calculation of Basic Earnings Per Share:
Net Income	$ 87,212	$ 89,796	$ 83,466
Weighted shares outstanding - Basic (in shares)	18,370,758	17,722,227	17,558,078
Basic Earnings Per Share (in usd per share)	$ 4.75	$ 5.07	$ 4.75
Calculation of Diluted Earnings Per Share:
Net Income	$ 87,212	$ 89,796	$ 83,466
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)	18,370,758	17,722,227	17,558,078
Share-based Compensation	64,099	82,067	74,951
Adjusted denominator — Diluted	18,434,857	17,804,294	17,633,029
Income (Loss) from Continuing Operations, Per Diluted Share	$ 4.73	$ 5.04	$ 4.73
Diluted (in usd per share)	$ 4.73	$ 5.04	$ 4.73

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Acquisitions - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
Equity Issued in Business Combination, Fair Value Disclosure	$ 366,400,000
Proceeds from Issuance of Senior Long-Term Debt	550,000,000
Business Acquisition, Transaction Costs	4,100,000
Business Combination, Acquisition Related Costs	15,900,000
Revenues	670,604,000	$ 680,704,000	$ 569,968,000
Operating Income	150,803,000	142,933,000	131,112,000
Transaction-related expenses	10,355,000	0	0
Regulated Energy [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Operating Income	126,199,000	$ 115,317,000	$ 106,174,000
Common Stock [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Proceeds from Issuance of Senior Long-Term Debt	4,400,000
Florida City Gas
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Consideration Transferred	$ 923,400,000
Number of customers acquired through acquisition	120,000
Number of Miles of Distribution Mains	3,800
Number of Miles of Transmission Pipe	80
Business Combination, Integration Related Costs	$ 10,400,000
Transaction-related expenses	7,500,000
Property, Plant and Equipment, Acquired During Period	453,845,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	461,193,000
Florida City Gas | Regulated Energy [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Revenues	12,100,000
Operating Income	(3,300,000)
J.T. Lee and Son's
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Consideration Transferred	$ 3,900,000
Number of customers acquired through acquisition	3,000
Business Combination, Contingent Consideration, Liability	$ 300,000
Gallons acquired through acquisition	800,000
Bulk Plant Storage Acquired Through Acquisition	60,000
Property, Plant and Equipment, Acquired During Period	$ 2,700,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	900,000
Business Combination, Working Capital	200,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	100,000
Planet Found
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Consideration Transferred	9,500,000
Business Combination, Contingent Consideration, Liability	900,000
Property, Plant and Equipment, Acquired During Period	4,000,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	1,100,000
Business Combination, Working Capital	100,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 4,400,000
Tons of Poultry Litter	1,200
Davenport Energy
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Consideration Transferred	$ 2,000,000
Number of customers acquired through acquisition	850
Gallons acquired through acquisition	400,000
Property, Plant and Equipment, Acquired During Period	$ 1,500,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	$ 500,000

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Acquisitions - Summary of Purchase Price Allocation (Details) - Florida City Gas $ in Thousands	Dec. 31, 2023 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory	$ 2,270
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	14,396
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	2,983
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other	2,707
Property, Plant and Equipment, Acquired During Period	453,845
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	461,193
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets Regulatory assets - noncurrent	3,381
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	18,309
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets [Abstract]	959,084
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	(20,954)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	(14,137)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	(548)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	(35,639)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 923,445

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Acquisitions - Schedule of Pro Forma Information (Details) - Regulated Energy [Member] - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Business Combination, Separately Recognized Transactions [Line Items]
Business Acquisition, Pro Forma Information, Description	$ 786,473	$ 798,355
Business Acquisition, Pro Forma Net Income (Loss)	$ 85,398	$ 81,508

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Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 67,741	$ 61,687
Contract with Customer, Asset, Net, Noncurrent	3,524	4,321
Contract with Customer, Liability, Current	1,022	983
Increase (Decrease) in Receivables	6,054
Increase (Decrease) in Other Noncurrent Assets	(797)
Increase (Decrease) in Other Current Liabilities	39
Contract with Customer, Asset, after Allowance for Credit Loss, Current	18	$ 18
Increase (Decrease) in Other Current Assets	$ 0

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Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023		Dec. 31, 2022		Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Revenues	$ 670,604		$ 680,704		$ 569,968
Revenue from Contract with Customer, Excluding Assessed Tax	670,604	[1]	680,704	[2]	569,968	[3]
Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(26,139)	[1]	(29,470)	[2]	(20,821)	[3]
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	182		308		527
Other [Member] | Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	182		308		527
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	148,940		163,489		141,891
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(85,653)		(84,825)		(75,903)
Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(26,321)		(29,778)		(21,348)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	473,595	[1]	429,424	[2]	383,920	[3]
Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	420,880		376,843		334,404
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	111,801		107,264		103,728
Regulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(59,086)		(54,683)		(54,212)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	223,148	[1]	280,750	[2]	206,869	[3]
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	37,139		56,225		38,163
Unregulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(246)		(364)		(343)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues	1,200		500		200
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues	400		400		400
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax					134,609
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	83,882		82,176		71,195
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	99,474		81,714		78,300
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	168,360		155,870
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	28,092		26,607		22,449
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	20,185		21,278		20,746
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	37,139		56,225		38,163
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	79,923		78,624		76,911
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	30,400		27,263		26,630
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	19,207		25,318		18,652
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	154,748		188,412		142,082
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12,300		11,159		8,315
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(85,471)		(84,517)		(75,376)
Eliminations [Member] | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(26,139)		(29,470)		(20,821)
Eliminations [Member] | Regulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(59,086)		(54,683)		(54,212)
Eliminations [Member] | Unregulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(246)		(364)		(343)
Aspire Energy Express | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,478		1,377		187
Elkton Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	8,814		$ 9,198		$ 7,105
Florida City Gas | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 12,073

[1] Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 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 for Maryland division and Sandpiper and late fees

[2] Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 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 for Maryland division and Sandpiper and late fees

[3] (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 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 for Maryland division and Sandpiper and late fees

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Revenue Recognition Remaining performance obligations (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 36,657
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 9,680
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 652
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 46,989
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 30,330
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 9,216
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 275
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 39,821
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 26,547
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 8,501
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 275
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 35,323
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 23,433
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,472
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 275
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 30,180
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 22,559
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 5,252
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 275
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 28,086
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 149,124
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 28,428
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 177,552

XML

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		$ 670,604,000	$ 680,704,000	$ 569,968,000
Intersegment Revenues (1)
Total intersegment revenues		670,604,000	680,704,000	569,968,000
Operating Income
Operating Income		150,803,000	142,933,000	131,112,000
Other income		1,438,000	5,051,000	1,720,000
Interest charges		36,951,000	24,356,000	20,135,000
Income Before Income taxes		115,290,000	123,628,000	112,697,000
Income taxes		28,078,000	33,832,000	29,231,000
Net Income		87,212,000	89,796,000	83,466,000
Depreciation and Amortization
Total depreciation and amortization		65,501,000	68,973,000	62,661,000
Identifiable Assets
Total identifiable assets		3,304,704,000	2,215,037,000
RSAM Adjustment		5,100,000
Florida City Gas
Identifiable Assets
Business Combination, Consideration Transferred		923,400,000
Regulated Energy
Operating Income
Operating Income		126,199,000	115,317,000	106,174,000
Depreciation and Amortization
Total depreciation and amortization		48,162,000	52,707,000	48,748,000
Payments to Acquire Productive Assets		1,095,871,000	97,554,000	139,733,000
Regulated Energy | Florida City Gas
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		12,100,000
Intersegment Revenues (1)
Total intersegment revenues		12,100,000
Operating Income
Operating Income		(3,300,000)
Unregulated Energy
Operating Income
Operating Income		24,426,000	27,350,000	24,427,000
Depreciation and Amortization
Total depreciation and amortization		17,347,000	16,257,000	13,869,000
Payments to Acquire Productive Assets		40,264,000	40,773,000	81,651,000
Other
Operating Income
Operating Income		178,000	266,000	511,000
Depreciation and Amortization
Payments to Acquire Productive Assets		1,762,000	2,355,000	6,425,000
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization		(8,000)	9,000	44,000
Total for Segments [Member]
Depreciation and Amortization
Payments to Acquire Productive Assets		1,137,897,000	140,682,000	227,809,000
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		670,604,000	680,704,000	569,968,000
Intersegment Revenues (1)
Total intersegment revenues		670,604,000	680,704,000	569,968,000
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		471,591,000	422,894,000	381,879,000
Intersegment Revenues (1)
Total intersegment revenues		471,591,000	422,894,000	381,879,000
Identifiable Assets
Total identifiable assets		2,781,581,000	1,716,255,000
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		199,013,000	257,810,000	188,089,000
Intersegment Revenues (1)
Total intersegment revenues		199,013,000	257,810,000	188,089,000
Identifiable Assets
Total identifiable assets		477,402,000	463,239,000
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]	26,321,000	29,778,000	21,348,000
Intersegment Revenues (1)
Total intersegment revenues	[1]	26,321,000	29,778,000	21,348,000
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		2,004,000	6,530,000	2,041,000
Intersegment Revenues (1)
Total intersegment revenues		2,004,000	6,530,000	2,041,000
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		24,135,000	22,940,000	18,780,000
Intersegment Revenues (1)
Total intersegment revenues		24,135,000	22,940,000	18,780,000
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		182,000	308,000	527,000
Intersegment Revenues (1)
Total intersegment revenues		182,000	308,000	$ 527,000
Other And Intersegment Eliminations
Identifiable Assets
Total identifiable assets		$ 45,721,000	$ 35,543,000

[1] All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.  (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details.  (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details.

XML

Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 30,525	$ 24,267	$ 20,809
Cash paid for income taxes	$ 21,920	$ (4,963)	$ 8,395

XML

Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Supplemental Cash Flow Disclosures Noncash Investing And Financing Activities [Abstract]
Capital property and equipment acquired on account, but not paid as of December 31	$ 33,334	$ 13,211	$ 16,164
Non Cash Performance Incentive Plan DRP	0	0	1,712
Performance Incentive Plan	$ 3,740	$ 2,868	$ 2,834

XML

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands		1 Months Ended	3 Months Ended	12 Months Ended
		Feb. 28, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current				$ 354	$ 585
Unrealized Gain (Loss) on Derivatives				584	3,517	$ 6,586
Notional Amount of Nonderivative Instruments		$ 40,000	$ 60,000	50,000
Fixed Swap Rate		0.17%
Derivative assets, at fair value				$ 1,027	2,787
Interest Rate Swap Rate, Low Range [Member]
Derivative [Line Items]
Fixed Swap Rate			0.20%
Interest Rate Swap Rate, High Range [Member]
Derivative [Line Items]
Fixed Swap Rate				3.98%
Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net				$ 0	56	(1)
Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net				523	(47)	(40)
Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net				0	0	(24)
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	[1]			702	3,317
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, at fair value	[1]			365	452
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	[2]			1,078	1,810
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	[2]			203	405
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months				(300)
Other Payables to Broker-Dealers and Clearing Organizations				2,100	100
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net				$ (1,160)	$ 3,881	$ 7,187

[1]  (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term

[2] (1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

XML

Derivative Instruments Fair Value Hedges (Details) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2021	Dec. 31, 2021	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative liabilities, at fair value			$ 354	$ 585
Notional Amount of Nonderivative Instruments	$ 40,000	$ 60,000	$ 50,000

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands		Dec. 31, 2023	Dec. 31, 2022
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		$ 1,027	$ 2,787
Energy Marketing Contracts Assets, Total		1,067	3,769
Energy Marketing Contract Liabilities, Current		354	585
Energy Marketing Contract Liabilities, Total		1,281	2,215
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	[1]	1,078	1,810
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	[1]	203	405
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	[2]	702	3,317
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	[2]	$ 365	$ 452

[1] (1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

[2]  (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current		$ 354	$ 585
Gain (Loss) on derivatives		584	3,517	$ 6,586
Derivatives not designated as hedging instruments | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 0	$ 56	$ (1)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Propane and natural gas costs	Propane and natural gas costs	Propane and natural gas costs
Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 0	$ 0	$ (24)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Propane and natural gas costs	Propane and natural gas costs	Propane and natural gas costs
Derivatives designated as fair value hedges | Propane Swap Agreement | Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 1,221	$ (373)	$ (536)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Revenues	Revenues	Revenues
Derivatives designated as fair value hedges | Propane Swap Agreement | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (1,160)	$ 3,881	$ 7,187
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Propane and natural gas costs
Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 523	$ (47)	$ (40)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]		Interest charges	Interest charges	Interest charges
Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current	[1]	$ 1,078	$ 1,810
Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current	[1]	$ 203	$ 405

[1] (1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term.

XML

Derivative Instruments Volume of Derivative Activity (Details) - Sharp Energy Inc [Member]	12 Months Ended
	Dec. 31, 2023 gal
Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	18,100,000
Swap Sales
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	3,200,000

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 1,200.0	$ 600.8
Fair value of long-term debt	$ 1,200.0	$ 505.0

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Assets:
Investments	$ 12,282	$ 10,576
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	10,793	8,723
Fair Value, Inputs, Level 1 [Member] | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Significant Other Observable Inputs (Level 2)
Assets:
Assets, Fair Value Disclosure	1,067	3,769
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,281	2,215
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	1,489	1,853
Significant Unobservable Inputs (Level 3) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	21	24
Equity Securities [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Equity Securities [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	1,489	1,853
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	10,772	8,699
Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	10,793	8,723
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	1,489	1,853
Mark-to-market energy assets, including put option | Fair Value, Inputs, Level 1 [Member]
Assets:
Mark-to-market energy assets, including put option	0	0
Mark-to-market energy assets, including put option | Significant Other Observable Inputs (Level 2)
Assets:
Mark-to-market energy assets, including put option	1,067	3,769
Mark-to-market energy assets, including put option | Significant Unobservable Inputs (Level 3)
Assets:
Mark-to-market energy assets, including put option	0	0
Fair Value
Assets:
Assets, Fair Value Disclosure	13,349	14,345
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,281	2,215
Fair Value | Equity Securities [Member]
Assets:
Investments	21	24
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	1,489	1,853
Fair Value | Other Investments [Member]
Assets:
Investments	10,772	8,699
Fair Value | Investments [Member]
Assets:
Investments	12,282	10,576
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 1,067	$ 3,769

XML

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	$ 26,957	$ 26,159
Acquired finite-lived intangible assets, weighted average useful life	14 years
Goodwill	$ 508,174	46,213
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	1,800
Amortization of intangible assets	1,800	1,500	$ 1,300
Finite-Lived Intangible Assets, Amortization Expense, Year Four	1,500
Amortization of intangible assets, 2020	1,600
Amortization of intangible assets, 2022	1,300
Regulated Energy
Goodwill [Line Items]
Goodwill	468,714	7,689
Unregulated Energy
Goodwill [Line Items]
Goodwill	39,460	38,524
Customer list
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	$ 17,004	16,965
Customer list | Minimum [Member]
Goodwill [Line Items]
Amortized period of acquired intangible assets	5 years
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	$ 3,125	$ 3,105

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 26,957	$ 26,159
Finite-Lived Intangible Assets, Accumulated Amortization		10,092	8,300
Goodwill		508,174	46,213
Goodwill, Transfers	[1]	461,961
Regulated Energy
Goodwill [Line Items]
Goodwill		468,714	7,689
Goodwill, Transfers		461,025
Unregulated Energy
Goodwill [Line Items]
Goodwill		39,460	38,524
Goodwill, Transfers		936
Customer Lists [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		17,004	16,965
Finite-Lived Intangible Assets, Accumulated Amortization		7,146	6,131
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		3,125	3,105
Finite-Lived Intangible Assets, Accumulated Amortization		1,855	1,411
Patents [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	6,558	5,819
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	859	533
Other Intangible Assets [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		270	270
Finite-Lived Intangible Assets, Accumulated Amortization		$ 232	$ 225

[1] (1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details.

[2] (1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		$ 26,957	$ 26,159
Accumulated Amortization		10,092	8,300
Customer Lists [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		17,004	16,965
Accumulated Amortization		7,146	6,131
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		3,125	3,105
Accumulated Amortization		1,855	1,411
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	6,558	5,819
Accumulated Amortization	[1]	859	533
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		270	270
Accumulated Amortization		$ 232	$ 225

[1] (1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found

XML

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 1,847	$ 1,488
Net Operating Losses and Tax Carryback	0	0	$ 919
Deferred State and Local Income Tax Expense (Benefit)	$ 100	7,800	8,200
Net Operating Losses and Tax Carryback, Total			$ (900)
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Deferred Tax Assets, Operating Loss Carryforwards	$ 1,847	1,488
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
State
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax	$ 72,900	$ 67,700

XML

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current Income Tax Expense
Federal		$ 14,736	$ 8,284	$ 2,775
State		5,496	1,948	(96)
Other		(47)	(47)	(47)
Total current income tax expense (benefit)		20,185	10,185	2,632
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	7,893	23,647	26,599
Total Income Tax		28,078	33,832	29,231
Deferred State and Local Income Tax Expense (Benefit)		100	7,800	8,200
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		17,797	14,968	24,074
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		(7,739)	8,923	1,857
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		(974)	1,109	(655)
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense		(351)	(351)	(351)
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		(370)	2	97
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ (470)	$ (1,004)	$ 1,577

[1] (1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively.

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%
Reconciliation of Effective Income Tax Rates Continuing Operations
Federal income tax expense (1)	[1]	$ 24,214	$ 25,982	$ 23,666
State income taxes, net of federal benefit		4,377	7,714	6,371
ESOP dividend deduction		(184)	(177)	(180)
Other		(329)	313	293
Total Income Tax		$ 28,078	$ 33,832	$ 29,231
Effective Income Tax Rate		24.35%	27.34%	25.94%
Net Operating Losses and Tax Carryback		$ 0	$ 0	$ (919)

[1] Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021.

XML

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 100	$ 7,800	$ 8,200
Deferred income tax liabilities:
Property, plant and equipment	252,125	238,687
Acquisition adjustment	5,564	5,915
Deferred Tax Liabilities Loss On Reacquired Debt	145	164
Deferred Income Tax Liability - Deferred Gas Costs	3,550	11,288
Deferred Income Tax Liability, Natural Gas Conversion Costs	4,824	5,026
Deferred Income Tax Liability, Storm Reserve	5,797	5,791
Other	9,655	8,236
Total deferred income tax liabilities	281,660	275,107
Deferred income tax assets:
Pension and other employee benefits	4,993	3,985
Environmental costs	951	1,052
Net operating loss carryforwards	1,847	1,488
Storm reserve liability	213	453
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals	3,335	9,007
Other	11,239	2,955
Total deferred income tax assets	22,578	18,940
Deferred Income Tax Liabilities, Net	$ 259,082	$ 256,167

XML

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 0.1	$ 7.8	$ 8.2
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Maximum [Member]
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			35.00%
Minimum [Member]
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent			21.00%

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2023
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%

XML

Income Taxes Federal Tax Reform (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2021
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%
Maximum [Member]
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		35.00%
Minimum [Member]
Components Of Income Tax Expense Benefit [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent		21.00%

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.54%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 255,000
Long-term debt including current maturities	1,200,000	$ 600,800
Long-term Debt and Lease Obligation	1,205,580	599,871
Total long-term debt, net of current maturities	1,187,075	578,388
Unamortized Debt Issuance Expense	(3,753)	(946)
Long-term Debt and Lease Obligation, Current	(18,505)	(21,483)
MetLife [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	150,000
Long-term debt including current maturities	50,000
MetLife [Member] | Maximum [Member]
Debt Instrument [Line Items]
Face amount	200,000
Prudential [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	105,000
Long-term debt including current maturities	300,000
Prudential [Member] | Maximum [Member]
Debt Instrument [Line Items]
Face amount	$ 405,000
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Long-term debt including current maturities	$ 8,700	11,600
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.98%
Long-term debt including current maturities	$ 70,000
Uncollateralized Senior Note Due On May 2 Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Long-term debt including current maturities	$ 3,500	4,200
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Long-term debt including current maturities	$ 10,000	12,000
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Long-term debt including current maturities	$ 30,000	35,000
Uncollateralized Senior Note Due On Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Long-term debt including current maturities	$ 0	3,000
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Long-term debt including current maturities	$ 59,500	66,500
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.48%
Long-term debt including current maturities	$ 50,000	50,000
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.58%
Long-term debt including current maturities	$ 50,000	50,000
Uncollateralized Senior Note Due November Two Thousand Thirty Nine
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 100,000	100,000
Uncollateralized Senior Note Due November Two Thousand Thirty Four
Debt Instrument [Line Items]
Long-term debt including current maturities		70,000
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.00%
Long-term debt including current maturities	$ 50,000	50,000
Uncollateralized Senior Note Due August Two Thousand Thirty Five
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.96%
Long-term debt including current maturities	$ 40,000	40,000
Uncollateralized Senior Note Due January Two Thousand Thirty Seven
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.49%
Long-term debt including current maturities	$ 50,000	50,000
Equipment Security Note
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Long-term debt including current maturities	$ 7,633	8,517
Uncollateralized Senior Note Due March 15, 2042
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.95%
Long-term debt including current maturities	$ 50,000	$ 50,000
Uncollateralized Senior Note Due March 14, 2038
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.43%
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 80,000

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term Debt	$ 1,200,000	$ 600,800
Less: debt issuance costs	(3,753)	(946)
Long-term Debt and Lease Obligation	1,205,580	599,871
Less: current maturities	(18,505)	(21,483)
Total long-term debt, net of current maturities	$ 1,187,075	578,388
Debt Instrument, Interest Rate, Stated Percentage	6.54%
Proceeds from issuance of long-term debt	$ 627,011	49,859	$ 59,478
Proceeds from Issuance of Senior Long-Term Debt	550,000
Common Stock [Member]
Debt Instrument [Line Items]
Proceeds from Issuance of Senior Long-Term Debt	4,400
Prudential [Member]
Debt Instrument [Line Items]
Long-term Debt	300,000
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	$ 0	3,000
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 8,700	11,600
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 3,500	4,200
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 10,000	12,000
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	$ 30,000	35,000
Debt Instrument, Interest Rate, Stated Percentage	3.88%
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 59,500	66,500
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	50,000
Debt Instrument, Interest Rate, Stated Percentage	3.48%
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	50,000
Debt Instrument, Interest Rate, Stated Percentage	3.58%
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 70,000
Debt Instrument, Interest Rate, Stated Percentage	2.98%
Uncollateralized Senior Note Due March 15, 2042
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	50,000
Debt Instrument, Interest Rate, Stated Percentage	2.95%
Uncollateralized Senior Note Due March 14, 2038 [Abstract]
Debt Instrument [Line Items]
Long-term Debt	$ 80,000	0
Debt Instrument, Interest Rate, Stated Percentage	5.43%
Uncollateralized Senior Note Due December 2026
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Debt Instrument, Interest Rate, Stated Percentage	6.39%
Uncollateralized Senior Note Due December 2027
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Debt Instrument, Interest Rate, Stated Percentage	6.44%
Uncollateralized Senior Note Due December 2028
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Uncollateralized Senior Note Due December 2030
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Debt Instrument, Interest Rate, Stated Percentage	6.62%
Uncollateralized Senior Note Due December 2033
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	0
Debt Instrument, Interest Rate, Stated Percentage	6.71%
Uncollateralized Senior Note Due December 2038
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	$ 0
Debt Instrument, Interest Rate, Stated Percentage	6.73%
Uncollateralized Senior Note Due March 14, 2038
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.43%
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 80,000

XML

Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.54%
Proceeds from issuance of long-term debt	$ 627,011	$ 49,859	$ 59,478
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt Instrument, Maturity Date	Oct. 31, 2023
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Debt Instrument, Maturity Date	Jun. 30, 2026
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt Instrument, Maturity Date	May 02, 2028
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Debt Instrument, Maturity Date	Dec. 16, 2028
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt Instrument, Maturity Date	May 15, 2029
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date	Apr. 30, 2032
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.48%
Debt Instrument, Maturity Date	May 31, 2038
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.58%
Debt Instrument, Maturity Date	Nov. 30, 2038
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.98%
Debt Instrument, Maturity Date	Aug. 20, 2039
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.98%
Debt Instrument, Maturity Date	Dec. 20, 2034
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.00%
Debt Instrument, Maturity Date	Jul. 15, 2035
Uncollateralized Senior Note Due August Two Thousand Thirty Five
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.96%
Debt Instrument, Maturity Date	Aug. 15, 2035
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Equipment Security Note
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Debt Instrument, Maturity Date	Sep. 24, 2031
Uncollateralized Senior Note Due January Two Thousand Thirty Seven
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.49%
Debt Instrument, Maturity Date	Jan. 25, 2037
Uncollateralized Senior Note Due March 15, 2042
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.95%
Debt Instrument, Maturity Date	Mar. 15, 2042
Uncollateralized Senior Note Due March 14, 2038 [Abstract]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.43%
Debt Instrument, Maturity Date	Mar. 14, 2038
Uncollateralized Senior Note Due December 2026
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.39%
Debt Instrument, Maturity Date	Dec. 31, 2026
Uncollateralized Senior Note Due December 2027
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.44%
Debt Instrument, Maturity Date	Dec. 31, 2027
Uncollateralized Senior Note Due December 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.45%
Debt Instrument, Maturity Date	Dec. 31, 2028
Uncollateralized Senior Note Due December 2030
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.62%
Debt Instrument, Maturity Date	Dec. 31, 2030
Uncollateralized Senior Note Due December 2033
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.71%
Debt Instrument, Maturity Date	Dec. 31, 2033
Uncollateralized Senior Note Due December 2038
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.73%
Debt Instrument, Maturity Date	Dec. 31, 2038

XML

Long-Term Debt Annual Maturities (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months	$ 18,505
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two	25,528
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Three	134,551
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four	131,674
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Five	136,699
Long-term Debt, Maturities, Repayments of Principal in Rolling after Year Five	762,376
Total Future Repayments	$ 1,209,333

XML

Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Line of Credit Facility [Line Items]
Long-term Debt	$ (1,200,000)	$ (600,800)
Debt Instrument, Interest Rate, Stated Percentage	6.54%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 255,000
Prudential [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(300,000)
Debt Instrument, Unused Borrowing Capacity, Amount	105,000
MetLife [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(50,000)
Debt Instrument, Unused Borrowing Capacity, Amount	150,000
Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(350,000)
Aggregated Unfunded Commitments [Member]
Line of Credit Facility [Line Items]
Long-term Debt	0
Aggregated Unfunded Commitments [Member] | Prudential [Member]
Line of Credit Facility [Line Items]
Long-term Debt	0
Aggregated Unfunded Commitments [Member] | MetLife [Member]
Line of Credit Facility [Line Items]
Long-term Debt	0
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (59,500)	(66,500)
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Line of Credit Facility [Line Items]
Long-term Debt	$ (50,000)	(50,000)
Debt Instrument, Interest Rate, Stated Percentage	3.00%
Uncollateralized Senior Note Due August Two Thousand Thirty Five
Line of Credit Facility [Line Items]
Long-term Debt	$ (40,000)	$ (40,000)
Debt Instrument, Interest Rate, Stated Percentage	2.96%
Uncollateralized Senior Note Due March 14, 2038
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	5.43%
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (80,000)
Maximum [Member] | Prudential [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	405,000
Maximum [Member] | MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	200,000
Maximum [Member] | Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	$ 605,000

XML

Short-Term Borrowing - Additional Information (Detail)	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2023 USD ($)	Oct. 31, 2023	Sep. 30, 2023	Dec. 31, 2022 USD ($)
Short-term Debt [Line Items]
Short-term borrowings			$ 179,853,000			$ 202,157,000
Number Of Unsecured Bank Credit Facilities			3
Short-term Debt, Weighted Average Interest Rate, at Point in Time			5.83%			5.04%
Ratio of Indebtedness to Net Capital				0.70	0.65
Long-term debt including current maturities			$ 1,200,000,000			$ 600,800,000
Line of Credit Facility, Commitment Fee Percentage			9500.00%
Line of Credit Facility, Remaining Borrowing Capacity			$ 188,100,000
Notional Amount of Nonderivative Instruments	$ 40,000,000	$ 60,000,000	$ 50,000,000
Fixed Swap Rate	0.17%
Debt Instrument, Interest Rate, Stated Percentage			6.54%
Amount of letter of credit to our current primary insurance company			$ 7,000,000
Florida City Gas | Regulated Energy [Member]
Short-term Debt [Line Items]
Bridge Loan			965,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity			$ 375,000,000
Interest Rate Swap Rate, Low Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate		0.20%
Interest Rate Swap Rate, High Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate			3.98%
Revolving Line of Credit, Short-term
Short-term Debt [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			7500.00%
Debt Instrument, Fee			9
Aggregate Investment, Maximum			$ 175,000,000			$ 150,000,000
Ownership Interest			0.50
Interest Rate Credit Adjustment			10
Line Of Credit Facility Interest Rate Description 2			$ 0.0005
Line Of Credit Facility Interest Rate Description 1			$ 0.01
Line of Credit Facility, Interest Rate Description			1.05 percent
Revolving Line of Credit, Long-term
Short-term Debt [Line Items]
Debt Instrument, Fee			9
Interest Rate Credit Adjustment			10

XML

Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 188,100,000
Short-term borrowing	$ 179,853,000	$ 202,157,000
Number Of Unsecured Bank Credit Facilities	3
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 375,000,000

XML

Leases Schedule of Future Minimum Rental Payment for Operating Leases (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2,771	[1]
Lessee Future Operating Lease Option Payments	2,100
Lessee, Operating Lease, Liability, Payments, Due Year Two	2,288	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,774	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,583	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,205	[1]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	5,243	[1]
Lessee, Operating Lease, Liability, Payments, Due	14,864	[1]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(1,860)
Operating Lease, Liability	$ 13,004

[1] (1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised

XML

Leases Lease Cost Additional (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating Lease, Cost	$ 3,040	$ 2,883	[1]

[1] 1) Includes short-term leases and variable lease costs, which are immaterial

XML

Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List]	Other accrued liabilities	Other accrued liabilities
Operating Lease, Right-of-Use Asset	$ 12,426	$ 14,421
Operating Lease, Liability, Current	2,454	2,552
Operating Lease, Liability, Noncurrent	10,550	12,392
Total Operating and Finance Lease Liabilities	$ 13,004	$ 14,944

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Leases Weighted Average Remaining Lease Term Additional Information (Details)	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	8 years 1 month 6 days	8 years 6 months
Operating Lease, Weighted Average Discount Rate, Percent	3.50%	3.40%

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Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Leases Cash Flows [Abstract]
Operating Lease, Payments	$ 2,931	$ 2,906
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	$ (1,860)

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Stockholders' Equity Additional Details (Details) - USD ($)	6 Months Ended	12 Months Ended
	Jun. 30, 2023	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Nov. 30, 2023
Accumulated Other Comprehensive Income (Loss) [Line Items]
Preferred Stock, Shares Authorized		2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01	$ 0.01
Proceeds from issuance of common stock, net of expenses		$ 366,417,000	$ 0	$ 0
Stock Issued During Period, Shares, Dividend Reinvestment Plan			100,000
Stock Issued During Period, Value, Dividend Reinvestment Plan			$ 136.26
Issuance of stock for Dividend Reinvestment Plan			$ 4,500,000
Florida City Gas
Accumulated Other Comprehensive Income (Loss) [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		4,438,596
Common Stock [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Stock Issued During Period, Shares, Dividend Reinvestment Plan			39,418
Shares Issued, Price Per Share					$ 82.72
Common Stock [Member] | Florida City Gas
Accumulated Other Comprehensive Income (Loss) [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares		4,400,000
Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Proceeds from Stock Plans	$ 75,000,000

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Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (1,379)	$ 1,303
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(959)	(229)
Amounts reclassified from accumulated other comprehensive income/(loss)	(400)	(2,453)
Net current-period other comprehensive income/(loss)	(1,359)	(2,682)
Accumulated other comprehensive loss at end of period	(2,738)	(1,379)	$ 1,303
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(2,506)	(3,268)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(110)	705
Amounts reclassified from accumulated other comprehensive income/(loss)	32	57
Net current-period other comprehensive income/(loss)	(78)	762
Accumulated other comprehensive loss at end of period	(2,584)	(2,506)	(3,268)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	1,092	4,571
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(1,322)	(934)
Amounts reclassified from accumulated other comprehensive income/(loss)	(44)	(2,545)	(4,813)
Net current-period other comprehensive income/(loss)	(1,366)	(3,479)
Accumulated other comprehensive loss at end of period	(274)	1,092	4,571
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	35	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	473	0
Amounts reclassified from accumulated other comprehensive income/(loss)	(388)	35
Net current-period other comprehensive income/(loss)	85	35
Accumulated other comprehensive loss at end of period	$ 120	$ 35	$ 0

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Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes	$ 115,290	$ 123,628	$ 112,697
Income tax benefit	(28,078)	(33,832)	(29,231)
Accumulated other comprehensive loss	(2,738)	(1,379)	1,303
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(959)	(229)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(400)	(2,453)
Other Comprehensive Income (Loss), Net of Tax	(1,359)	(2,682)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	(274)	1,092	4,571
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(1,322)	(934)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(44)	(2,545)	(4,813)
Other Comprehensive Income (Loss), Net of Tax	(1,366)	(3,479)
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	120	35	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	473	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(388)	35
Other Comprehensive Income (Loss), Net of Tax	85	35
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	(2,584)	(2,506)	$ (3,268)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(110)	705
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	32	57
Other Comprehensive Income (Loss), Net of Tax	$ (78)	$ 762

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Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2023 USD ($) shares	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		$ 12,800
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 200
Required period of service for eligibility		3 months
Percentage of eligible participants contribution to the plan		100.00%
Employer matching contribution vested, percentage		100.00%
Deferred Compensation Arrangement with Individual, Requisite Service Period		2 years
Defined Benefit Plan, Benefit Obligation			2
Employee contribution age		55 years
Deferral rate		80.00%
Deferred Compensation Employer Matching Contribution Rate		6.00%
Number Of Years to Collect Benefits		20 years
Deferral rate increase, minimum		1.00%
Employer contributions to pension plan		$ 6,600	$ 6,200	$ 5,900
Shares reserved to fund future contributions | shares		798,586
Investments, Fair Value Disclosure		$ 12,282	10,576
Deferred compensation obligation		$ 9,050	7,060
Pension Settlement Expense				$ 2,000
Minimum
Defined Benefit Plan Disclosure [Line Items]
Maximum percentage of eligible compensation		3.00%
Maximum
Defined Benefit Plan Disclosure [Line Items]
Maximum percentage of eligible compensation		6.00%			10.00%
Number Of Years to Collect Benefits		15 years
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		$ 10,800
Expected contribution	[1]	3,528
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Expected contribution	[2]	$ 151
Medical
Defined Benefit Plan Disclosure [Line Items]
Health care inflation rate		5.00%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		$ 1,200
Unfunded accumulated benefit obligation		$ (1,100)	(600)
Health care inflation rate		6.00%
Expected contribution	[2]	$ 42
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Unfunded accumulated benefit obligation		$ (400)	(700)
Health care inflation rate		5.00%
Expected contribution	[2]	$ 35
FPU Medical Plan and Chesapeake OPRB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans		2
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Deferred compensation obligation		$ 12,300	10,600
Deferred Compensation Equity		$ 9,100	$ 7,100

[1] The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

[2] Benefit payments are expected to be paid out of our general funds.

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Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Change in benefit obligation:
Interest cost	$ 81	$ 50	$ 48
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	49,941	67,030
Interest cost	2,495	1,781	1,714
Actuarial loss	454	(15,713)
Benefits paid	(3,233)	(3,157)
Benefit obligation - end of year	49,657	49,941	67,030
Change in plan assets:
Balance, beginning of year	46,203	58,712
Actual return on plan assets	6,462	(9,552)
Employer contributions	0	200
Benefits paid	(3,233)	(3,157)
Balance, end of year	49,432	46,203	$ 58,712
Reconciliation:
Accrued pension cost	$ (225)	$ (3,738)
Assumptions:
Discount rate	5.00%	5.25%
Expected return on plan assets	6.00%	6.00%	6.00%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1,659	$ 2,096
Interest cost	81	50
Actuarial loss	48	(335)
Benefits paid	(152)	(152)
Benefit obligation - end of year	1,636	1,659	$ 2,096
Change in plan assets:
Employer contributions	152	152
Benefits paid	(152)	(152)
Reconciliation:
Accrued pension cost	$ (1,636)	$ (1,659)
Assumptions:
Discount rate	4.88%	5.00%
Chesapeake Postretirement Plan
Reconciliation:
Funded status	$ (1,100)	$ (600)
FPU Medical Plan
Reconciliation:
Funded status	$ (400)	$ (700)

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Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 81	$ 50	$ 48
Accumulated other comprehensive loss pre-tax	(3,200)
Total unrecognized cost	(12,800)
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost	2,495	1,781	1,714
Post-merger regulatory asset	(8,700)
Total unrecognized cost	(10,800)
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	2,670	3,430	3,306
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year	(407)	(466)	(612)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 232	$ (1,183)	$ (980)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.25%	2.75%	2.50%
Expected return on plan assets	6.00%	6.00%	6.00%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 81	$ 50
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year	(8)	(28)	$ (28)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 89	$ 78	$ 76
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5.00%	2.50%	2.25%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost	$ (1,200)

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Employee Benefit Plans - Schedule of Assets by Investment Type (Detail) - USD ($) $ in Thousands		Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Inputs, Level 1, 2 and 3
Asset Category
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments	[1]	$ 49,432	$ 41,257
FPU Pension Plan
Asset Category
Percentage of assets by investment type		100.00%	100.00%	100.00%
FPU Pension Plan | Investments in equity securities
Asset Category
Percentage of assets by investment type		50.00%	53.00%	52.00%
FPU Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type		49.00%	38.00%	38.00%
FPU Pension Plan | Other
Asset Category
Percentage of assets by investment type		1.00%	9.00%	10.00%

[1] (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

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Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2023
Minimum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	33.00%
Minimum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	3.00%
Minimum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	38.00%
Minimum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Maximum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	57.00%
Maximum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7.00%
Maximum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	58.00%
Maximum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	5.00%

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Employee Benefit Plans - Summary of Pension Plan Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2023	Dec. 31, 2022
Debt and Equity Securities, FV-NI [Line Items]
Investments measured at net asset value	[1]	$ 0	$ 4,946
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		24,648	19,706
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	15,360	3,413
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	4,271	1,425
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	2,518	692
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	2,499	9,352
Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	0	4,824
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		24,228	17,612
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	24,228	15,343
Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	0	2,269
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		556	3,939
Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	0	1,832
Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	0	1,709
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	556	398
Fair Value, Inputs, Level 1, 2 and 3
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets, excluding investments measured at net asset value	[9]	49,432	41,257
Fair Value Measured at Net Asset Value Per Share
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 49,432	$ 46,203

[1] Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

[2] Includes funds that invest primarily in United States common stocks.

[3] Includes funds that invest primarily in foreign equities and emerging markets equities.

[4] Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

[5] Includes funds that invest in investment grade and fixed income securities.

[6] Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

[7] Includes funds that invest primarily in real estate.

[8] 7) Includes investment in a group annuity product issued by an insurance company.

[9] (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

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Employee Benefit Plans - Summary of Changes in Fair Value of Level 3 Investments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Alternative Investments, Fair Value of Plan Assets	[1]	$ 0	$ 4,946
Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments	[2]	49,432	41,257
Fair Value Measured at Net Asset Value Per Share
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		46,203
Balance, end of year		49,432	46,203
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		19,706
Balance, end of year		24,648	19,706
Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		17,612
Balance, end of year		24,228	17,612
Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		3,939
Balance, end of year		556	3,939
Us Large Cap Equity Securities | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	3,413
Balance, end of year	[3]	15,360	3,413
Us Mid Cap Equity Securities | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	1,425
Balance, end of year	[3]	4,271	1,425
United States Equity Small Cap | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	692
Balance, end of year	[3]	2,518	692
International All Cap Equity | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	9,352
Balance, end of year	[4]	2,499	9,352
Alternative Strategies | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	4,824
Balance, end of year	[5]	0	4,824
Fixed Income Securities [Member] | Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	15,343
Balance, end of year	[6]	24,228	15,343
High Yield Asset Backed Securities | Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	2,269
Balance, end of year	[6]	0	2,269
Commodities | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[7]	1,832
Balance, end of year	[7]	0	1,832
Real Estate [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[8]	1,709
Balance, end of year	[8]	0	1,709
Guaranteed deposit | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[9]	398
Balance, end of year	[9]	$ 556	$ 398

[1] Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

[2] (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.

[3] Includes funds that invest primarily in United States common stocks.

[4] Includes funds that invest primarily in foreign equities and emerging markets equities.

[5] Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

[6] Includes funds that invest in investment grade and fixed income securities.

[7] Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

[8] Includes funds that invest primarily in real estate.

[9] 7) Includes investment in a group annuity product issued by an insurance company.

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Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Components of net periodic cost:
Interest cost	$ 81	$ 50	$ 48
Chesapeake Postretirement Plan
Assumptions
Funded status	(1,100)	(600)
FPU Medical Plan
Assumptions
Funded status	(400)	(700)
Chesapeake SERP
Components of net periodic cost:
Interest cost	81	50
Actuarial (gain) loss	8	28	28
Net periodic postretirement cost	$ 89	$ 78	$ 76
Assumptions
Discount rate	5.00%	2.50%	2.25%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 48	$ (335)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(152)	(152)
Defined Benefit Plan, Plan Assets, Contributions by Employer	152	152
Defined Benefit Plan, Plan Assets, Benefits Paid	(152)	(152)
Accrued pension cost	$ (1,636)	$ (1,659)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	4.88%	5.00%
FPU Pension Plan
Components of net periodic cost:
Interest cost	$ 2,495	$ 1,781	$ 1,714
Expected return on assets	(2,670)	(3,430)	(3,306)
Actuarial (gain) loss	407	466	612
Net periodic postretirement cost	$ 232	$ (1,183)	$ (980)
Assumptions
Discount rate	5.25%	2.75%	2.50%
Expected return on plan assets	6.00%	6.00%	6.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 454	$ (15,713)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(3,233)	(3,157)
Defined Benefit Plan, Plan Assets, Amount	49,432	46,203	$ 58,712
Defined Benefit Plan, Plan Assets, Contributions by Employer	0	200
Defined Benefit Plan, Plan Assets, Benefits Paid	(3,233)	(3,157)
Accrued pension cost	$ (225)	$ (3,738)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.00%	5.25%

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Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2023 USD ($)
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 200
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	3,528	[1]
2018	3,603	[1]
2019	3,617	[1]
2020	3,616	[1]
2021	3,651	[1]
Years 2022 through 2026	17,951	[1]
Chesapeake SERP
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	151	[2]
2018	164	[2]
2019	161	[2]
2020	158	[2]
2021	154	[2]
Years 2022 through 2026	689	[2]
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	42	[2]
2018	46	[2]
2019	45	[2]
2020	48	[2]
2021	49	[2]
Years 2022 through 2026	299	[2]
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	35	[2]
2018	35	[2]
2019	34	[2]
2020	33	[2]
2021	32	[2]
Years 2022 through 2026	$ 143	[2]

[1] The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

[2] Benefit payments are expected to be paid out of our general funds.

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Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	798,586
Number of Shares, Granted	765	652
Number of shares withheld	19,859	21,832	14,020
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 6.6
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to the awards to Non employee directors	$ 0.3
Weighted average grant-date fair value of awards granted	$ 124.12	$ 130.36
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 91.59	$ 90.60
Number of Shares, Granted	80,820	69,620
Weighted average grant-date fair value of awards granted	$ 126.06	$ 117.61
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 22.5	$ 24.1	$ 28.8
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	561,115

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Share-Based Compensation Plans - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 7,622	$ 6,438	$ 5,945
Less: tax benefit	(1,947)	(1,663)	(1,535)
Share-Based Compensation amounts included in net income	5,675	4,775	4,410
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	906	959	782
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	300
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	22,500	24,100	28,800
Total compensation expense	$ 6,716	$ 5,479	$ 5,163

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Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	765	652
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Granted	$ 124.12	$ 130.36
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 0.3

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Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	765	652
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	204,149	197,398
Number of Shares, Granted	80,820	69,620
Number of Shares, Vested	(68,302)	(60,191)
Number of Shares, Outstanding Ending Balance	213,124	204,149
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$ 103.17	$ 94.15
Weighted Average Grant Date Fair Value, Granted	126.06	117.61
Weighted Average Grant Date Fair Value, Vested	91.59	90.60
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$ 117.74	$ 103.17
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	1,490
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 113.44
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 22.5	$ 24.1	$ 28.8
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Vested	$ 94.64	$ 91.42
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	2,053	2,678

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Share-Based Compensation Plans Shares Withheld and Tax Benefits Associated With Share-Based Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation	19,859	21,832	14,020
Payment, Tax Withholding, Share-based Payment Arrangement	$ 2,455	$ 2,838	$ 1,478

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Rates and Other Regulatory Activities - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2023 USD ($) Dekatherm mi	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 115,902,000	$ 149,653,000
Revenues		670,604,000	680,704,000	$ 569,968,000
Interim Rates		7,700,000
Annual Rate Case Recovery		17,200,000
COVID-19 Regulatory Asset		200,000	1,200,000
RSAM		25,000,000
Regulatory Liabilities		208,998,000	148,020,000
Cost Recovery Storm Protection Plan		13,600,000
Gas Utility Access and Replacement Directive Related Capital Expenditures		205,000,000
Storm reserve
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	1,900,000	2,845,000
Underrecovered purchased fuel costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	13,696,000	$ 43,583,000
Maryland Natural Gas Distribution Businesses [Member]
Rates and Other Regulatory Activities [Line Items]
Permanent Rates		6,900,000
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
COVID-19 Settlement Amount		2,100,000
West Palm Beach Florida | Minimum [Member]
Rates and Other Regulatory Activities [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss		1,900,000
West Palm Beach Florida | Maximum [Member]
Rates and Other Regulatory Activities [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss		3,200,000
Florida Natural Gas Distribution [Member]
Rates and Other Regulatory Activities [Line Items]
Permanent Rates		24,100,000
Florida City Gas
Rates and Other Regulatory Activities [Line Items]
Total Base Revenue		23,300,000
Rate Increase		14,100,000
Base Rate Increase Base - SAFE investments transfer to base rates		5,300,000
Base Rate Increase - liquefied natural gas facility		3,800,000
Florida City Gas | Storm reserve
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		$ 800,000
Beachside Expansion | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		10,176
Number of Mainline Pipeline Miles | mi		11.3
Twin Lakes Expansion | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		2,400
Ocean City Maryland Reinforcement | Maryland Natural Gas [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Mainline Pipeline Miles | mi		5.4
Lake Wales Pipeline Acquisition | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		9,000
Newberry Expansion | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		8,000
East Coast Reinforcement Projects: Boynton Beach | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		15,000
East Coast Reinforcement Projects: New Smyrna Beach | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		3,400
Elkton Gas [Member] | Regulated Energy [Member]
Rates and Other Regulatory Activities [Line Items]
Number of customers acquired through acquisition		7,000

[1] We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

[2] We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

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Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2023		Dec. 31, 2022
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 115,902		$ 149,653
Regulatory Liabilities		208,998		148,020
Underrecovered Gas & Fuel Costs		21,200
Self Insured Liabilities [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	521		339
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	12,340		3,827
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	1,900		2,845
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	86,534		50,261
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[4]	105,055		87,690
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		1,611		1,851
Storm Cost Recovery, Interest
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[5]	536		1,207
Over-recovered GRIP revenue
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		501		0
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	13,696		43,583
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	10,802		13,927
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	21,466		23,653
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	31,857		25,609
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		15,573		12,256
COVID-19 Deferred Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		190	[8]	1,233
Deferred Storm Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[5]	19,370		27,687
Under-recovered GRIP Revenues
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	1,777		1,705
Deferred rate case expenses - current
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		1,171		$ 0
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34,200
Indiantown Gas Company
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		$ 700

[1] We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

[2] We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.

[3] See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

[4] ) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.

[5] The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets

[6] The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16, Employee Benefit Plans, for additional information.

[7] We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010.

[8] ) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs.

[9] The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

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Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 208,998	$ 148,020
Eastern Shore Gas Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	34,190	34,190
Delaware natural gas division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	12,038	12,230
Maryland Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,585	3,703
Sandpiper [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,487	3,597
Central Florida Gas Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	26,757	27,179
Elkton Gas [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	1,027	1,059
FPU electric division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 4,760	$ 4,993

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Environmental Commitments and Contingencies - Additional Information (Detail)

12 Months Ended

Dec. 31, 2023

USD ($)

site

Dec. 31, 2022

USD ($)

Environmental Commitments And Contingencies [Line Items]

Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site

7

Environmental liabilities

$ 2,607,000

$ 3,272,000

Environmental Commitments and Contingencies

ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

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

MGP Sites

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

As of December 31, 2023 and 2022, we had approximately $3.6 million and $4.3 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2023 and 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs from customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval for and has recovered, through a combination of insurance and customer rates, $14.0 million of its environmental costs related to its MGP sites as of December 31, 2023.

Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial.

The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million.

Manufactured Gas Plant

Environmental Commitments And Contingencies [Line Items]

Regulatory assets for future recovery of environmental costs

$ 500,000

800,000

West Palm Beach Florida | Maximum

Environmental Commitments And Contingencies [Line Items]

Environmental Exit Costs, Reasonably Possible Additional Loss

3,200,000

West Palm Beach Florida | Minimum

Environmental Commitments And Contingencies [Line Items]

Environmental Exit Costs, Reasonably Possible Additional Loss

1,900,000

Seaford | Maximum

Environmental Commitments And Contingencies [Line Items]

Environmental Exit Costs, Reasonably Possible Additional Loss

900,000

Seaford | Minimum

Environmental Commitments And Contingencies [Line Items]

Environmental Exit Costs, Reasonably Possible Additional Loss

300,000

Florida Natural Gas Distribution [Member]

Environmental Commitments And Contingencies [Line Items]

Permanent Rates

24,100,000

Maryland Natural Gas Distribution Businesses [Member]

Environmental Commitments And Contingencies [Line Items]

Permanent Rates

6,900,000

Florida City Gas

Environmental Commitments And Contingencies [Line Items]

Rate Increase

14,100,000

FPU

Environmental Commitments And Contingencies [Line Items]

Environmental liabilities

3,600,000

$ 4,300,000

Approval of recovery of environmental costs

$ 14,000,000

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Other Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Subsequent Event [Line Items]
Intercompany Agreements, Description	three years
Debt Service Coverage Ratio	1.25
Time to cure ratio	5 days
Ratio based on average number of prior quarters	6
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	65
Number Of Years to Collect Benefits	20 years
Total purchase obligations for 2018	$ 86,040,000
Total purchase obligations for 2019 - 2020	105,082,000
Total purchase obligations for 2021 - 2022	83,851,000
Total purchase obligations thereafter	141,287,000
Aggregate guaranteed amount	35,000,000
Guarantor Obligations, Current Carrying Value	24,300,000
Amount of letter of credit to our current primary insurance company	7,000,000
Loss Contingencies [Line Items]
Environmental liabilities	$ 2,607,000	$ 3,272,000
Maximum [Member]
Subsequent Event [Line Items]
Number Of Years to Collect Benefits	15 years
Maximum [Member] | Seaford
Loss Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	$ 900,000
Specific Purpose
Subsequent Event [Line Items]
Guarantor Obligations, Current Carrying Value	4,000,000
Florida Public Utilities Company [Member]
Loss Contingencies [Line Items]
Environmental liabilities	$ 3,600,000	$ 4,300,000

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Other Commitments and Contingencies Purchase Obligations (Details) $ in Thousands	Dec. 31, 2023 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 86,040
Purchase Obligation, Due in Second and Third Year	105,082
Purchase Obligation, Due in Fourth and Fifth Year	83,851
Purchase Obligation, Due after Fifth Year	141,287
Purchase Obligation	$ 416,260

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Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 3,141	$ 4,785
Additions, Charged to Income	1,550	134
Additions, Other Accounts	172	(125)
Deductions	(1,986)	(1,653)
Balance at End of Year	$ 2,877	$ 3,141