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, 2021

☐ 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.)

909 Silver Lake Boulevard, Dover, Delaware 19904

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

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. ☒

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2021, 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 18, 2022 was 17,657,537

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2022 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, 2021

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	3
Item 1A. Risk Factors	14
Item 1B. Unresolved Staff Comments	22
Item 2. Properties	22
Item 3. Legal Proceedings	23
Item 4. Mine Safety Disclosures	23
Part II	24
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	24
Item 6. Selected Financial Data	26
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	27
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	50
Item 8. Financial Statements and Supplementary Data	52
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
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	105
Item 15. Exhibits, Financial Statement Schedules	105
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

Boulden: Boulden, Inc., an entity from whom we acquired certain propane operating assets

CARES Act: Coronavirus Aid, Relief, and Economic Security Act

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

CDD: Cooling Degree-Day

CFG: Chesapeake Utilities' Central Florida Gas division

CGS: Community Gas Systems

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

Columbia Gas: Columbia Gas Transmission, LLC

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

COVID-19: An infectious disease caused by a discovered coronavirus

CNG: Compressed natural gas

Degree-day: A degree-day is the 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: Diversified Energy Company 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 subsidiary of Chesapeake OnSight Services, LLC

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

EDI: Equity Diversity and Inclusion

Escambia Meter Station: A natural gas metering station owned by Peninsula Pipeline Company located in Escambia County,

Florida

ESG: Environmental, Social and Governance

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission

FGT: Florida Gas Transmission Company

Flo-gas: Flo-gas Corporation, a wholly-owned subsidiary of FPU

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

Guernsey Power Station: Guernsey Power Station, LLC, a partner with Aspire Energy Express in the construction of a power generation facility in Ohio.

GRIP: Gas Reliability Infrastructure Program

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

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 losses

NYL: New York Life Investors LLC, an institutional debt investment management firm, with which Chesapeake Utilities entered into a Shelf Agreement and issued Shelf Notes

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

Peoples Gas: Peoples Gas System, an Emera Incorporated subsidiary

PESCO: Peninsula Energy Services Company, Inc., an inactive wholly-owned subsidiary of Chesapeake Utilities

Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which Chesapeake Utilities entered into a previous Shelf Agreement and issued Shelf Notes

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

Revolver: Our $400.0 million unsecured revolving credit facility with certain lenders

RNG: Renewable natural gas

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

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: 2013 Stock and Incentive Compensation Plan

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

Uncollateralized Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates

U.S.: The United States of America

Western Natural Gas: Western Natural Gas Company, an entity from whom we acquired certain propane operating assets in Jacksonville, Florida and the surrounding communities

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;

•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 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;

•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;

•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

Chesapeake Utilities Corporation 2021 Form 10-K Page 1

•the impacts associated with the outbreak of 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 2019 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 top tier returns on equity relative to our peer group. The Company’s growth strategy includes the continued investment and expansion of the Company’s regulated operations that provide a stable base of earnings, as well as investments in other related non-regulated businesses and services including sustainable energy initiatives. By investing in these related business 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, 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 opportunities.

Operating Segments

We operate 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. The following table presents net income for the year ended December 31, 2021 and total assets as of December 31, 2021, by operation and area served:

Chesapeake Utilities Corporation 2021 Form 10-K Page 3

Operations	Areas Served	Net Income		Total Assets
(in thousands)
Natural Gas Distribution
Delmarva Natural Gas (1)	Delaware/Maryland	$	12,283	$	350,196
Florida Natural Gas (2)	Florida	16,040		481,573
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	21,369		482,161
Peninsula Pipeline	Florida	10,898		140,494
Aspire Energy Express	Ohio	119		7,503
Electric Distribution
FPU	Florida	5,441		167,264
Total Regulated Energy		$	66,150	$	1,629,191

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

(2) Florida Natural Gas consists of Chesapeake Utilities CFG Division and FPU, and FPU's Ft. Meade and Indiantown divisions.

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. Our Regulated Energy operations in Florida 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 (which we define as operating revenues less purchased gas or electricity cost) 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.

Acquisition of Elkton Gas

In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions in the consolidated financial statements) for further information. The results of Elkton Gas are now included within our Delmarva Natural Gas distribution operations.

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, 2021:

Chesapeake Utilities Corporation 2021 Form 10-K     Page 4

	Delmarva Natural Gas Distribution				Florida Natural Gas Distribution (2)				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	73,539	61	%	$	41,460	31	%	$	37,594	48	%
Commercial	37,507		31	%	34,834		26	%	34,591		44	%
Industrial	9,160		8	%	47,418		35	%	2,105		3	%
Other (1)	1,289		<1%		10,897		8	%	4,010		5	%
Total Operating Revenues	$	121,495	100	%	$	134,609	100	%	$	78,300	100	%
Volumes (in Dts for natural gas/KW Hours for electric)
Residential	4,475,634		30	%	2,024,286		5	%	304,236		49	%
Commercial	4,209,015		28	%	6,270,574		14	%	305,121		49	%
Industrial	6,158,412		40	%	33,945,702		74	%	15,361		2	%
Other	313,791		2	%	3,418,989		7	%	—		—	%
Total Volumes	15,156,852		100	%	45,659,551		100	%	624,718		100	%
Average Number of Customers (3)
Residential	87,697		92	%	81,635		91	%	25,347		78	%
Commercial	7,808		8	%	5,684		6	%	7,328		22	%
Industrial	209		<1%		2,540		3	%	2		<1%
Other	5		<1%		6		<1%		—		—	%
Total Average Number of Customers	95,719		100	%	89,865		100	%	32,677		100	%

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

(2) Florida natural gas distribution includes Chesapeake Utilities' Central Florida Gas division, FPU and FPU's Indiantown and Fort Meade divisions.

(3) Average number of customers is based on the twelve-month average for the year ended December 31, 2021.

The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, 2021, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, 2021:

	Eastern Shore				Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated (1)	$	29,214	38	%	$	23,510	88	%
Local distribution companies - non-affiliated	24,685		32	%	840		3	%
Commercial and industrial - affiliated	—		—	%	1,120		4	%
Commercial and industrial - non-affiliated	22,993		30	%	264		1	%
Other (2)	19		<1%		896		4	%
Total Operating Revenues	$	76,911	100	%	$	26,630	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	153,295		50	%	306,400		36	%
Local distribution companies - non-affiliated	56,576		18	%	534,825		63	%
Commercial and industrial - affiliated	—		—	%	1,500		<1%
Commercial and industrial - non-affiliated	98,540		32	%	5,100		1	%
Total Contracted firm transportation capacity	308,411		100	%	847,825		100	%
Design day capacity (in Dts/d)	308,411		100	%	847,825		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 2021 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 FERC and is therefore excluded from the table. See Item 8, Financial Statements and Supplementary Data (Note 19, 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	Sandpiper	Elkton Gas (7)	Chesapeake's Florida natural gas division	FPU	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	01/14/2010	01/14/2010(1)	10/8/2020	08/01/2017
Rate Base (in Rates) (in Millions)	Not stated	Not stated	Not stated	Not stated	$46.7	$68.9	$24.9	Not stated
Annual Rate Increase Approved (in Millions)	$2.3	$0.6	N/A(2)	$0.1	$2.5	$8.0	$3.4 base rate and $7.7 from storm surcharge	$9.8
Capital Structure (in rates)(3)*	Not stated	LTD: 42% STD: 5% Equity: 53%	Not stated	LTD: 50% Equity: 50%	LTD: 31% STD: 6% Equity: 43% Other: 20%	LTD: 31% Equity: 47% Other: 22%	LTD: 22% STD: 23% Equity: 55%	Not stated
Allowed Return on Equity	9.75% (4)	10.75%(4)	Not stated (5)	9.80%	10.80%(4)	10.85%(4)	10.25%(4), (6)	Not stated
TJCA Refund Status associated with customer rates	Refunded	Refunded	Refunded	N/A	Retained	Retained	Refunded	Refunded

(1) The effective date of the order approving the settlement agreement, which adjusted the rates originally approved on June 4, 2009.

(2) The Maryland PSC approved a declining return on equity that will result in a decline in our rates.

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

(4) Allowed after-tax return on equity.

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

(6) 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.

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

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

In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida and caused widespread and severe damage to FPU's infrastructure resulting in the loss of electric service to 100 percent of its customers in the Northwest Florida service territory. FPU expended more than $65.0 million to restore service, which was recorded as new plant and equipment, charged against FPU’s accumulated depreciation or charged against FPU’s storm reserve.

In late 2019, the Florida PSC approved an interim rate increase, subject to refund, effective January 1, 2020, associated with the restoration effort following Hurricane Michael. We fully reserved these interim rates, pending a final resolution and settlement of the limited proceeding. In September 2020, the Florida PSC approved a settlement agreement between FPU and the Office of the Public Counsel regarding final cost recovery and rates associated with Hurricane Michael. The settlement agreement allowed us to: (a) refund the over-collection of interim rates through the fuel clause; (b) record regulatory assets for storm costs in the amount of $45.8 million including interest which will be amortized over six years; (c) recover these storm costs through a surcharge totaling $7.7 million annually; and (d) collect an annual increase in revenue of $3.3 million to recover capital costs associated with new plant investments and a regulatory asset for the cost of removal and unrecovered plant costs. The new base rates and storm surcharge were effective on November 1, 2020.

In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The petition was joined to the Hurricane Michael docket, and was approved at the Florida PSC Agenda in September 2020. The approved rates were retroactively applied effective January 1, 2020. See Item 8, Financial Statements and Supplementary Data (Note 19, Rates and Other Regulatory Activities, in the consolidated financial statements) for further information.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 6

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, 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 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
FPU and Central Florida Gas natural gas divisions	Florida	Yes	No
FPU electric division	Florida	Yes	No

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.

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 client, Guernsey Power Station, to which it is the sole supplier.

Electric Distribution

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 7

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. In March 2020, 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, 2020 and expire on March 31, 2023. 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 operation uses Peninsula Pipeline and Peoples Gas to transport natural gas where there is no direct connection with FGT. In November 2020, 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. An agreement with Florida Southeast Connection LLC commenced in June 2020 for additional service to Palm Beach County for an initial term through December 2044.

A summary of our pipeline capacity contracts follows:

		Maximum Daily Firm Transportation Capacity (Dts)	Contract Expiration Date
Division	Pipeline
Delmarva Natural Gas Distribution	Eastern Shore	151,026	2022-2035
	Columbia Gas(1)	5,246	2023-2024
	Transco(1)	30,419	2022-2028
	TETLP(1)	50,000	2027
Florida Natural Gas Distribution	Gulfstream(2)	10,000	2022
	FGT	45,909 - 77,317	2023-2041
	Peninsula Pipeline	306,400	2033-2048
	Peoples Gas	12,660	2022-2024
	Florida Southeast Connection LLC	5,000	2044
	Southern Natural Gas Company	1,750	2030

(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 2023. 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 for firm transportation capacity with Guernsey Power Station, who is currently constructing a power generation facility. Aspire Energy Express will provide 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 to the power generation facility in the fourth quarter of 2021 and expects to begin 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

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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.

Unregulated Energy

Overview

The following table presents net income for the year ended December 31, 2021 and total assets as of December 31, 2021, for our Unregulated Energy segment by operation and area served:

Operations	Area Served	Net Income		Total Assets
(in thousands)
Propane Operations (Sharp, Diversified Energy, FPU and Flo-gas) (1)	Delaware, Maryland, Virginia, Pennsylvania, North Carolina, South Carolina, Florida	$	11,651	$	197,340
Energy Transmission (Aspire Energy)	Ohio	3,060		141,473
Energy Generation (Eight Flags)	Florida	1,900		38,060
Marlin Gas Services	The Eastern U.S.	370		61,567
Total		$	16,981	$	438,440

(1) Includes results and total assets for Western Natural Gas, which we acquired in October 2020. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions in the consolidated financial statements) for further information.

Propane Operations

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 9

Propane Operations - Operational Highlights

For the year ended December 31, 2021, operating revenues, volumes sold and average number of customers by customer class for our propane operations were as follows:

	Operating Revenues (in thousands)(2)				Volumes (in thousands of gallons)(2)			Average Number of Customers (1)(2)
Residential bulk	$	40,002	28	%	14,326	21	%	44,866	65	%
Residential metered	17,095		12	%	5,894	9	%	17,486	25	%
Commercial bulk	31,695		22	%	17,124	25	%	6,327	10	%
Commercial metered	1,764		1	%	641	1	%	234	<1%
Wholesale	30,965		22	%	26,762	39	%	48	<1%
AutoGas	5,678		4	%	3,652	5	%	92	<1%
Other (3)	14,883		11	%	—	—	%	—	—	%
Total	$	142,082	100	%	68,399	100	%	69,053	100	%

(1) Average number of customers is based on a twelve-month average for the year ended December 31, 2021.

(2) Operating revenues, volumes and average customer includes those for Diversified Energy that was acquired in December 2021. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions in the consolidated financial statements) for further information.

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

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. The RNG volume is estimated to represent nearly 10 percent of Aspire Energy’s gas gathering volumes in the future. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

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For the twelve-month period ended December 31, 2021, 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	$	15,062	39	%	2,556	44	%
Supply to CGC	16,111		42	%	1,675	29	%
Supply to Marketers - unaffiliated	4,778		13	%	1,507	26	%
Other (including natural gas gathering and processing)	2,212		6	%	71	1	%
Total	$	38,163	100	%	5,809	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 operation 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 eastern United States. Marlin Gas Services maintains a fleet of CNG trailers, mobile compression equipment, LNG tankers and vaporizers, and an internally developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas. Marlin Gas Services continues to actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to serve liquefied natural gas and RNG market needs.

Environmental Matters

See Item 8, Financial Statements and Supplementary Data (see Note 20, 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 culture. Among the ongoing initiatives across our enterprise, we highlight below the importance of our team, as well as our response to the COVID-19 pandemic, our culture of safety, and our environmental, social and governance stewardship.

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. In 2021, the Company hired a new 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 as well as tuition reimbursement to promote continued professional growth.

As of December 31, 2021, we had a total of 1,007 employees, 110 of whom are union employees represented by two labor unions: the International Brotherhood of Electrical Workers and the United Food and Commercial Workers Union. The

Chesapeake Utilities Corporation 2021 Form 10-K Page 11

collective bargaining agreements with these labor unions expire in 2022. 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. In 2021, the Company was recognized as a Top Workplace for the tenth consecutive year. These honors were based entirely on feedback from employees who were surveyed by the research firm ‘Energage’. In early 2022, the Company was recognized nationally as a 2022 Top Workplace USA recipient among mid-sized companies for the second consecutive year. These recognitions are a testament to our employees’ commitment to excellence. Our employees are the backbone of our continued growth and success.

In 2020, we enhanced our diversity initiatives and established an Equity, Diversity and Inclusion (“EDI”) Council. The Council recommends and promotes our EDI strategy, advises 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 Chesapeake Utilities 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.

In 2021, there were six active ERGs meeting throughout the Company. Early in 2022, two new ERGs were added. 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 the 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.

COVID-19 Response

In March 2020, the United States declared a national emergency in response to the COVID-19 pandemic. 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 into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place.

Throughout 2021, restrictions continued to be lifted as vaccines have become widely available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. The expiration of the states of emergency in our service territories, along with the settlement of our limited proceeding in Florida, has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process.

We have been closely following the legal process related to the Occupational Safety and Health Administration (OSHA) Emergency Temporary Standard (ETS) mandating that all employers, with 100 or more employees, require COVID-19 vaccinations or weekly testing, which made its way to the United States Supreme Court. While OSHA has withdrawn the ETS as a temporary standard following the Supreme Court’s ruling, we will continue to monitor its status as a proposed rule. In light of the continued emergence and growing prevalence of the new variants of COVID-19, such as the Omicron variant, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, and stockholders and take all precautions warranted to operate safely and to comply with the CDC and OSHA standards, in order to protect our employees, customers and the communities we serve. We continue to hold regular companywide all employee calls and leadership meetings with our President and CEO to discuss, among other things, matters pertaining to COVID-19, in addition to distributing frequent, routine communications updates. The Company’s Board met regularly and virtually, throughout 2021, and received updates on the Company’s actions related to COVID-19, the Company’s safety

Chesapeake Utilities Corporation 2021 Form 10-K     Page 12

protocols, and ongoing monitoring, including updates on the Company’s COVID-19 Human Resources Taskforce’s priorities and current employee health statistics, and the Company’s risk posture.

Workplace 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 our Board and our President and CEO, and including required attendance at monthly safety meetings, routine safety training and the inclusion of safety moments at key team meetings.

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. In November 2020, we announced the completion of our state-of-the art training facility in Dover, Delaware. ‘Safety Town’ 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. We are excited to start construction of a second ‘Safety Town’ facility in Florida in 2022.

Environmental, Social and Governance Stewardship ("ESG")

Consistent with our culture of teamwork, the broad responsibility of ESG stewardship is supported 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 and its safety and operational compliance practices, and to promoting equity, diversity and inclusion that reflects the diverse communities we serve. The Corporate Governance Committee oversees our ESG activities and initiatives to continue enhancing our culture of sustainability and corporate governance practices. The Audit Committee oversees the integrity of our financial statements and financial reporting process, our risk exposure, and implementation and effectiveness of our risk management programs. The Compensation Committee promotes a culture of equity, diversity and inclusion and contributes to the ability to attract, retain, develop and motivate both at the executive level and throughout the organization. Finally, the Investment Committee assists the Board of Directors with evaluating investments pursuant to or in support of our growth strategy, both organically and through acquisitions, including renewable natural gas and other sustainable initiatives.

Information About Executive Officers

Chesapeake Utilities Corporation 2021 Form 10-K Page 13

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	64	2010	President (January 2019 - present) Chief Executive Officer (January 2019 - present) Director (January 2019 - present) President of FPU (June 2010 - February 2019)
Beth W. Cooper	55	2005	Executive Vice President (February 2019 - present) Chief Financial Officer (September 2008 - present) Senior Vice President (September 2008 - February 2019) Assistant Corporate Secretary (March 2015 - present)
James F. Moriarty	64	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	63	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	52	2019	Chief Operating Officer (January 2022 - present) Senior Vice President (December 2019 - present) Vice President Black Hills Energy (October 2012 - December 2019)

Available Information on Corporate Governance Documents

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

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

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

•Code of Ethics for Financial Officers;

•Corporate Governance Guidelines; and

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

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 19904.

ITEM 1A. RISK FACTORS.

The following is a discussion of the primary factors that may affect the operations and/or financial performance of our regulated and unregulated energy businesses. 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.

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FINANCIAL RISKS

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.

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 the 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 or the inability to borrow under certain credit agreements. Any such acceleration could cause a material adverse change in our financial condition. As of December 31, 2021, we were in compliance with all of our 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. Absent recovery of the higher debt cost in the rates we charge our utility customers, 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.

Current market conditions could adversely impact the return on plan assets for FPU's pension plan, which may require significant additional funding.

In 2021, the Company terminated the Chesapeake Utilities pension plan. The FPU pension plan is closed to new employees, and the future benefits are frozen. 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 obligations 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;

Chesapeake Utilities Corporation 2021 Form 10-K Page 15

(iv) lack of anticipated future growth in available natural gas and electricity supply; (v) insufficient customer throughput commitments; and (vi) lack of available and qualified third-party contractors which could impact the timely construction of new facilities.

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, cash flows and results of operations.

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, could adversely affect our results of operations, cash flows and financial condition.

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 results of operations, cash flows and financial condition.

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 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. Likewise, if the weather is colder than normal, we 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.

Natural disasters, severe weather (such as a major hurricane) and acts of terrorism could adversely impact earnings.

Inherent in energy transmission and distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, explosions, sabotage and mechanical problems. Natural disasters and severe weather 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 United States 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 results of operations, cash flows and financial condition. The insurance industry may also be affected by natural disasters, severe weather 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 results of operations, financial condition and cash flows.

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

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

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 by foreign sources.

The failure of, or security breaches related to, our information technology infrastructure, could lead to system disruptions or cause facility shutdowns. 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, subject to 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 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.

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, 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.

Mandatory COVID-19 vaccination of employees or testing of employees could impact our workforce and have a material adverse effect on our business and results of operations.

On September 9, 2021, President Biden issued an executive order (the “Executive Order”) requiring most employers with U.S. Government contracts to ensure that their U.S.-based employees, contractors, and subcontractors, that work on or in support of U.S. Government contracts, be fully vaccinated by December 8, 2021.This date was later postponed to January 4, 2022, to allow for the final dose of the vaccine to be administered. However, a number of federal district courts enjoined the enforcement of this federal contractor mandate. As such, the federal government cannot, at present, enforce the Executive

Chesapeake Utilities Corporation 2021 Form 10-K Page 17

Order and its vaccine mandate against federal contractors. The various district court orders enjoining enforcement are being appealed by the federal government.

At this time, it is not possible to predict with certainty the nature and extent to which we will be subject to the Executive Order, or impact the Executive Order will have on us or on our workforce. Additional vaccine mandates may be announced in other jurisdictions in which we operate, or by governmental agencies with which we provide services. Implementation of these requirements by us may result in employee attrition, including attrition of critically skilled labor, absenteeism within our skilled labor force, challenges securing future labor needs, inefficiencies connected to employee turnover, and costs associated with implementation and on-going compliance, which could have a material adverse effect on our business, financial condition and results of operations.

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. Our ability to complete our infrastructure projects on a timely basis and manage the overall cost of those projects may be affected by the availability of the necessary materials and qualified vendors. Our future earnings could be adversely affected if we are unable to manage such capital projects effectively, or if full recovery of such capital costs is not permitted in future regulatory proceedings.

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 results of operations, cash flows and financial condition.

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 energy consumption by our customers. In addition, higher costs of natural gas, propane and electricity may cause customers to conserve fuel. To the extent a PSC or the FERC does not allow the recovery through customer rates of higher costs or lower consumption from energy efficiency or conservation, and our propane retail prices cannot be increased due to market conditions, our results of operations, cash flows and financial condition may 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/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 operating cash flows, results of operations and financial condition, 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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 18

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.

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 and adversely affected if the future availability of these capacities were insufficient to meet future customer demands for natural gas and electricity. Currently, our Florida natural gas operation relies primarily on two pipeline systems, FGT and Peninsula Pipeline, our intrastate pipeline subsidiary for most of its 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 earnings, financial condition and results of operations.

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.

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. Acquisitions involve a number or risks including, but not limited to, the assumption of material liabilities, the diversion of management’s attention from the management of daily operations to the integration of operations, difficulties in the assimilation and retention of employees and difficulties in the assimilation of different cultures and internal controls. Future acquisitions could also result in, among other things, the failure to identify material issues during due diligence, the risk of overpaying for assets, unanticipated capital expenditures, the failure to maintain effective internal control over financial reporting, recording goodwill and other intangible assets at values that ultimately may be subject to impairment charges and fluctuations in quarterly results. There can also be no assurance that our past and future acquisitions will deliver the strategic, financial and operational benefits that we anticipate. The failure to successfully integrate acquisitions could have an adverse effect on our results of operations, cash flows and financial condition.

An impairment of goodwill could result in a significant charge to earnings.

In accordance with GAAP, goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. 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 goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. 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 business segments, which may result in an impairment charge.

REGULATORY, LEGAL AND ENVIRONMENTAL RISKS

Chesapeake Utilities Corporation 2021 Form 10-K Page 19

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

The Delaware, Maryland 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.

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 our authorized rate of return.

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 results of operations, cash flows and financial condition.

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 and results of operations. 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 civil or criminal penalties and fines, which could impact our financial condition and results of operations. See Item 8, Financial Statements and Supplementary Data (see Note 20, 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 or cash flows.

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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 20

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, such as carbon dioxide. 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 EPA 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 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 climatic 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.

We face risks related to widespread public concerns, including the COVID-19 outbreak.

The actual or perceived effects of a disease outbreak, epidemic, pandemic or similar widespread public health concern, such as COVID-19, could negatively affect our operations, liquidity, financial condition, cash flows and results of operations. The outbreak of COVID-19 has adversely impacted economic activity and conditions worldwide. In particular, efforts to control the spread of COVID-19 led to shutdowns of customer operations and disrupted financial markets and supply chains.

We continue to respond to COVID-19 by taking steps to mitigate the impact of its spread and the potential risks to us. We provide a critical service to our customers, which means that it is paramount that we keep our employees who operate our businesses safe and minimize unnecessary risk of the exposure to COVID-19. We continue to operate under our Pandemic Response Plan that dates back to 2007. This plan guides our emergency response, business continuity, and the precautionary measures we have been taking on behalf of our employees, our customers and the communities we serve. We continue to take extra precautions for our employees who work in the field and for employees who continue to work in our facilities, and we have maintained work from home policies where appropriate. We continue to operate under restricted travel plans, minimize movement between offices, utilize virtual, or on-line work, meetings and events, and employ “social distancing” as directed by the CDC and state and local governments in the areas we serve. We have suspended walk-in customer access to our natural gas, propane and electric offices, and reminded customers of our online and direct mail payment options. We continue to utilize multiple organizational teams and task forces to guide us through ever changing key aspects of this pandemic. We have instituted measures to ensure our supply chains remain open to us; however, there could be global shortages that will impact our maintenance and capital programs that we currently cannot anticipate. We will continue to monitor developments affecting our workforce, our customers and our suppliers, and we will take additional precautions that we determine are necessary in order to mitigate the impacts. We continue to implement measures to ensure that our systems remain functional in order to both serve our operational needs with a remote workforce and keep them running to ensure uninterrupted service to our customers. To date, the crisis has not had a material effect on the Company.

Chesapeake Utilities Corporation 2021 Form 10-K Page 21

The extent to which COVID-19 impacts our future results, financial position and liquidity will depend on many factors. At the present time, not all of these factors can be predicted, including new information, which may emerge concerning the severity and duration of the pandemic or any subsequent mutations, the actions mandated by governmental authorities to contain COVID-19 and the availability and timing to identified vaccines, among others.

Additional risks and uncertainties not known to us at present, or that we currently deem immaterial, also may affect Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition and results of operations.

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 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 22

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, 2021:

Operations	Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines)	1,934
Delmarva Natural Gas (Underground propane pipelines)	32
Central Florida Gas and FPU (Natural gas pipelines)	3,030
Natural Gas Transmission
Eastern Shore	516
Peninsula Pipeline	144
Aspire Energy Express (1)	—
Electric Distribution
FPU	906
Total	6,562

(1) Aspire Energy Express had less than 1 mile of natural gas pipeline at December 31, 2021.

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 will serve growing demand in both Nassau and Duval Counties.

Unregulated Energy Segment

As of December 31, 2021 the following table presents propane storage capacity, miles of underground distribution mains and transmission for our Unregulated Energy Segment operations:

Operations	Gallons or miles
Propane distribution
Propane storage capacity (gallons in millions)	8.9
Underground propane distribution mains (miles)	198
Unregulated Energy Transmission and gathering (Aspire Energy)
Natural gas pipelines (miles)	2,800

ITEM 3. Legal Proceedings.

See Note 21, Other Commitments and Contingencies in the Consolidated Financial Statements, which is incorporated into Item 3 by reference.

ITEM 4. Mine Safety Disclosures.

Not applicable.

Chesapeake Utilities Corporation 2019 Form 10-K Page 23

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 18, 2022, we had 2,075 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $1.880 per share in 2021 and $1.725 per share in 2020, and have paid a cash dividend to our common stock stockholders for 61 consecutive years. Future dividend payments and amounts are at the discretion of our 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 13, Long-Term Debt, in the consolidated financial statements) for additional information.

Purchases of Equity Securities by the Issuer

The following table sets forth information on purchases by us or on our behalf of shares of our common stock during the quarter ended December 31, 2021.

	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, 2021 through October 31, 2021 (1)	431	$	128.24	—	—
November 1, 2021 through November 30, 2021	—	—		—	—
December 1, 2021 through December 31, 2021	—	—		—	—
Total	431	$	128.24	—	—

(1) In October 2021, we purchased 431 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 17, 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.

Discussion of our 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 2021 Form 10-K Page 24

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, 2021, 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 Inc.; Northwest Natural Holding Company; NorthWestern Corporation; ONE Gas Inc.; RGC Resources, Inc.; South Jersey Industries, Inc.; Spire Inc. and Unitil Corporation.

The comparison assumes $100 was invested on December 31, 2016 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.

	2016		2017		2018		2019		2020		2021
Chesapeake Utilities	$	100	$	119	$	126	$	151	$	174	$	237
Industry Index	$	100	$	114	$	122	$	170	$	121	$	160
S&P 500 Index	$	100	$	122	$	116	$	153	$	181	$	233

Chesapeake Utilities Corporation 2021 Form 10-K Page 25

ITEM 6. [RESERVED]

Chesapeake Utilities Corporation 2021 Form 10-K     Page 26

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.

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 in some capacity throughout all of 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place.

Throughout 2021, restrictions continued to be lifted as vaccines have become widely available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. The expiration of the states of emergency in our service territories, along with the settlement of our limited proceeding in Florida, has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process.

We have been closely following the legal process related to the Occupational Safety and Health Administration (OSHA) Emergency Temporary Standard (ETS) mandating that all employers, with 100 or more employees, require COVID-19 vaccinations or weekly testing, which made its way to the United States Supreme Court. While OSHA has withdrawn the ETS as a temporary standard following the Supreme Court’s ruling, we will continue to monitor its status as a proposed rule. In light of the continued emergence and growing prevalence of the new variants of COVID-19, such as the Omicron variant, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, and stockholders and take all precautions warranted to operate safely and to comply with the CDC and OSHA standards, in order to protect our employees, customers and the communities we serve. Refer to Item 8, Financial Statements and Supplementary Data, Note 19, Rates and Other Regulatory Activities, for further information on the potential deferral of incremental expenses associated with COVID-19.

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

The following discussions and those later in the document on operating income and segment results include the use of the term Adjusted Gross Margin which is a non-GAAP measure throughout our discussion on operating results. Adjusted Gross Margin is 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. Adjusted Gross Margin should not be considered an alternative to Gross Margin under U.S. GAAP which is defined as the excess of sales over cost of goods sold. We believe that Adjusted Gross Margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structures for our unregulated energy operations. Our management uses Adjusted Gross Margin as one of the financial measures in assessing our business units’ performance. Other companies may calculate Adjusted Gross Margin in a different manner.

The below tables reconcile Gross Margin as defined under GAAP to our non-GAAP measure of Adjusted Gross Margin for the years ended December 31, 2021, 2020 and 2019:

Chesapeake Utilities Corporation 2021 Form 10-K Page 27

	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)		20,686		(186,951)
Depreciation & amortization	(48,748)		(13,869)		(44)		(62,661)
Operations & maintenance expense (1)	(32,890)		(24,168)		334		(56,724)
Gross Margin (GAAP)	201,545		61,932		155		263,632
Operations & maintenance expense (1)	32,890		24,168		(334)		56,724
Depreciation & amortization	48,748		13,869		44		62,661
Adjusted Gross Margin (Non-GAAP)	$	283,183	$	99,969	$	(135)	$	383,017

	For the Year Ended December 31, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	352,746	$	152,526	$	(17,074)	$	488,198
Cost of Sales:
Natural gas, propane and electric costs	(91,994)		(62,780)		16,836		(137,938)
Depreciation & amortization	(46,079)		(11,988)		(50)		(58,117)
Operations & maintenance expense (1)	(31,237)		(22,914)		298		(53,853)
Gross Margin (GAAP)	183,436		54,844		10		238,290
Operations & maintenance expense (1)	31,237		22,914		(298)		53,853
Depreciation & amortization	46,079		11,988		50		58,117
Adjusted Gross Margin (Non-GAAP)	$	260,752	$	89,746	$	(238)	$	350,260

	For the Year Ended December 31, 2019
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Operating Revenues	$	343,006	$	154,150	$	(17,551)	$	479,605
Cost of Sales:
Natural gas, propane and electric costs	(102,803)		(68,885)		17,187		(154,501)
Depreciation & amortization	(35,227)		(10,130)		(67)		(45,424)
Operations & maintenance expense (1)	(30,219)		(22,025)		334		(51,910)
Gross Margin (GAAP)	174,757		53,110		(97)		227,770
Operations & maintenance expense (1)	30,219		22,025		(334)		51,910
Depreciation & amortization	35,227		10,130		67		45,424
Adjusted Gross Margin (Non-GAAP)	$	240,203	$	85,265	$	(364)	$	325,104

(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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 28

2021 to 2020 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for 2021 was $201.5 million, an increase of $18.1 million, or 9.9 percent, compared to 2020. Higher operating gross margin reflects continued pipeline expansions by Eastern Shore and Peninsula Pipeline, organic growth in the natural gas distribution businesses, increased consumption from a return toward pre-pandemic consumption levels and operating results from 2020 and 2021 acquisitions. These increases were partially offset by higher depreciation, amortization related to recent capital investments and acquisitions, increased payroll and benefits costs as well as operating expenses associated with a return toward pre-pandemic conditions.

2020 to 2019 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for 2020 was $183.4 million, an increase of $8.7 million, or 5.0 percent, compared to 2019. In the fourth quarter of 2020, we established $1.9 million of regulatory assets based on the estimated net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric businesses as currently authorized by the Delaware, Maryland and Florida PSCs. Excluding the estimated unfavorable COVID-19 impacts of $4.2 million for the year, Gross Margin (GAAP) increased $12.9 million as a result of the Hurricane Michael regulatory proceeding settlement, operating results from expansion projects completed by Eastern Shore and Peninsula Pipeline, organic growth in our natural gas distribution businesses, contribution from the Elkton Gas acquisition and additional GRIP investments. These increases were offset by lower customer consumption driven primarily by milder weather; higher depreciation and amortization, including amortization of the regulatory asset associated with the Hurricane Michael regulatory proceeding settlement, new expenses associated with the acquisition of Elkton Gas, and higher other operating expenses.

2021 to 2020 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for 2021 was $61.9 million, an increase of $7.1 million compared to 2020. Higher gross margin is a result of weather that was colder than 2020, higher retail propane margins per gallon and service fees, contributions from the propane acquisitions completed in 2020 and 2021, increased demand for Marlin Gas Services' CNG transportation services and increased customer consumption along with higher rates for Aspire Energy. These increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments and acquisitions,a return toward pre-pandemic conditions and a general increase in operating expenses to support growth in the business.

2020 to 2019 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for 2020 was $54.8 million, an increase of $1.7 million compared to 2019. Excluding the estimated COVID-19 impacts of $1.7 million, Gross Margin (GAAP) increased $3.4 million due to the acquisitions of the Boulden and Western Natural Gas propane assets, higher retail propane volumes and fees, increased demand for Marlin Gas Services’ CNG transportation services and higher rates for Aspire Energy. These increases were partially offset by reduced volumes from overall warmer temperatures and higher depreciation and amortization expenses associated with recent acquisitions.

Chesapeake Utilities Corporation 2021 Form 10-K Page 29

OVERVIEW AND HIGHLIGHTS

(in thousands except per share data)					Increase						Increase
For the Year Ended December 31,	2021		2020		(decrease)		2020		2019		(decrease)
Business Segment:
Regulated Energy	$	106,064	$	92,124	$	13,940	$	92,124	$	86,584	$	5,540
Unregulated Energy	24,382		20,664		3,718		20,664		19,938		726
Other businesses and eliminations	666		(65)		731		(65)		(237)		172
Operating Income	131,112		112,723		18,389		112,723		106,285		6,438
Other income (expense), net	1,721		3,222		(1,501)		3,222		(1,847)		5,069
Interest charges	20,135		21,765		(1,630)		21,765		22,224		(459)
Income from Continuing Operations Before Income Taxes	112,698		94,180		18,518		94,180		82,214		11,966
Income Taxes on Continuing Operations	29,231		23,538		5,693		23,538		21,114		2,424
Income from Continuing Operations	83,467		70,642		12,825		70,642		61,100		9,542
Income (loss) from Discontinued Operations, Net of Tax	(1)		686		(687)		686		(1,349)		2,035
Gain on sale of Discontinued Operations, Net of tax	—		170		(170)		170		5,402		(5,232)
Net Income	$	83,466	$	71,498	$	11,968	$	71,498	$	65,153	$	6,345
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	4.75	$	4.23	$	0.52	$	4.23	$	3.73	$	0.50
Earnings/ Per Share from Discontinued Operations	—		0.05		(0.05)		0.05		0.24		(0.19)
Basic Earnings Per Share of Common Stock	$	4.75	$	4.28	$	0.47	$	4.28	$	3.97	$	0.31
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.73	$	4.21	$	0.52	$	4.21	$	3.72	$	0.49
Earnings Per Share from Discontinued Operations	—		0.05		(0.05)		0.05		0.24		(0.19)
Diluted Earnings Per Share of Common Stock	$	4.73	$	4.26	$	0.47	$	4.26	$	3.96	$	0.30

Chesapeake Utilities Corporation 2021 Form 10-K     Page 30

2021 compared to 2020

Key variances in continuing operations between 2021 and 2020 included:

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Year ended December 31, 2020 Reported Results from Continuing Operations	$	94,180	$	70,642	$	4.21
Adjusting for unusual items:
Gains from sales of assets	(989)		(724)		(0.04)
Net impact of NOL Carryback related to implementation of the CARES Act	—		(919)		(0.05)
Reduced interest expense related to early extinguishment of FPU mortgage bonds	961		704		0.04
Regulatory deferral of COVID-19 expenses per PSCs orders	2,377		1,741		0.10
	2,349		802		0.05
Increased (Decreased) Adjusted Gross Margins:
Eastern Shore and Peninsula Pipeline service expansions*	7,168		5,250		0.30
Increased customer consumption - primarily weather related	5,519		4,043		0.23
Contributions from 2020 and 2021 acquisitions*	4,773		3,496		0.20
Increased propane margins per gallon and fees	3,638		2,664		0.15
Increased customer consumption - primarily due to return to pre-pandemic consumption	3,418		2,504		0.14
Contributions from regulated infrastructure programs *	3,158		2,313		0.13
Natural gas growth (excluding service expansions)	3,084		2,259		0.13
Improved performance from electric operations	1,015		743		0.04
Higher results from Aspire Energy	325		238		0.01
	32,098		23,510		1.33
(Increased) Decreased Other Operating Expenses (Excluding Natural Gas, Electricity and Propane Costs):
Depreciation, amortization and property tax costs due to new capital investments	(5,995)		(4,391)		(0.25)
Outside services due to growth and a return toward pre-pandemic conditions	(3,403)		(2,493)		(0.14)
Operating expenses from recent acquisitions	(2,914)		(2,134)		(0.12)
Payroll, benefits and other employee-related expenses	(1,756)		(1,286)		(0.07)
Increased facilities and maintenance costs	(1,130)		(828)		(0.05)
	(15,198)		(11,132)		(0.63)
Change in shares outstanding due to 2020 and 2021 equity offerings	—		—		(0.21)
Net Other Changes	(731)		(355)		(0.02)
Year ended December 31, 2021 Reported Results from Continuing Operations	$	112,698	$	83,467	$	4.73

* See the Major Projects and Initiatives table.

Chesapeake Utilities Corporation 2021 Form 10-K Page 31

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, with the intention of increasing shareholder value. The following represent the major projects/initiatives recently completed and currently underway. In the future, we will add new projects and initiatives to this table once substantially finalized and the associated earnings can be estimated.

	Adjusted Gross Margin
	Year Ended December 31,						Estimate for Fiscal
(in thousands)	2019		2020		2021		2022		2023
Pipeline Expansions:
Western Palm Beach County, Florida Expansion (1)	$	2,139	$	4,167	$	4,729	$	5,227	$	5,227
Del-Mar Energy Pathway (1) (2)	731		2,462		4,584		6,867		6,890
Callahan Intrastate Pipeline (2) (3)	—		3,080		7,564		7,564		7,564
Guernsey Power Station	—		—		187		1,380		1,486
Southern Expansion	—		—		—		586		2,344
Winter Haven Expansion	—		—		—		759		976
Beachside Pipeline Expansions	—		—		—		—		2,451
Total Pipeline Expansions	2,870		9,709		17,064		22,383		26,938
CNG Transportation	5,410		7,231		7,566		8,500		9,500
RNG Transportation	—		—		—		1,000		1,000
Acquisitions:
Diversified Energy	—		—		603		11,300		12,000
Elkton Gas	—		1,344		3,548		3,720		3,743
Western Natural Gas	—		389		1,772		2,001		2,061
Escambia Meter Station	—		—		583		1,000		1,000
Total Acquisitions	—		1,733		6,506		18,021		18,804
Regulatory Initiatives:
Florida GRIP	13,939		15,178		16,995		18,797		19,475
Hurricane Michael Regulatory Proceeding	—		10,864		11,492		11,704		11,818
Capital Cost Surcharge Programs	—		523		1,199		2,002		1,961
Elkton STRIDE Plan	—		—		26		299		354
Total Regulatory Initiatives	13,939		26,565		29,712		32,802		33,608
Total	$	22,219	$	45,238	$	60,848	$	82,706	$	89,850

(1) Includes adjusted gross margin generated from interim services.

(2) Includes adjusted gross margin from natural gas distribution services.

(3) Prior year amounts have been revised to conform to the current period presentation.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 32

Detailed Discussion of Major Projects and Initiatives

Pipeline Expansions

Western Palm Beach County, Florida Expansion

Peninsula Pipeline is constructing four transmission lines to bring additional natural gas to our distribution system in West Palm Beach, Florida. The first phase of this project was placed into service in December 2018 and generated incremental adjusted gross margin of $0.6 million during 2021 compared to 2020. The remainder of the project was completed in the fourth quarter of 2021. We estimate that the project will generate annual adjusted gross margin of $5.2 million in 2022 and beyond.

Del-Mar Energy Pathway

In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The project was placed into service in the fourth quarter of 2021. The new facilities: (i) include an additional 14,300 Dts/d of firm service to four customers, (ii) provide additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (iii) represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Construction of the project began in January 2020; including interim services in advance of construction completion, the project generated additional adjusted gross margin of $2.1 million for the year ended December 31, 2021. The estimated annual adjusted gross margin from this project, including natural gas distribution service in Somerset County, Maryland, is approximately $6.9 million in 2022 and growing each year thereafter, as the distribution system serving Somerset County further expands to meet demand.

Callahan Intrastate Pipeline

In May 2018, Peninsula Pipeline announced a plan to construct a jointly owned 26-mile intrastate transmission pipeline with Seacoast Gas Transmission in Nassau County, Florida to serve the growing demand in both Nassau and Duval Counties. This project was placed in service in June 2020 and generated $4.5 million in additional adjusted gross margin for the year ended December 31, 2021 including margin from natural gas distribution service. The pipeline is expected to generate $7.6 million annually in adjusted gross margin in 2022 and beyond.

Guernsey Power Station

Guernsey Power Station and the Company's affiliate, Aspire Energy Express, entered into a precedent agreement for firm transportation capacity whereby Guernsey Power Station will construct a power generation facility and Aspire Energy Express will provide 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 to provide the firm transportation service to the power generation facility in the fourth quarter of 2021. This project is expected to produce adjusted gross margin of approximately $1.4 million in 2022 and $1.5 million in 2023 and beyond.

Southern Expansion

Pending FERC authorization, Eastern Shore plans to install a new natural gas driven compressor skid unit at its existing Bridgeville, Delaware compressor station that will provide 7,300 Dts of incremental firm transportation pipeline capacity. The project is currently estimated to go into service in the fourth quarter of 2022. Eastern Shore expects the Southern Expansion project to generate annual adjusted gross margin of $0.6 million in 2022 and $2.3 million in 2023 and thereafter.

Winter Haven Expansion

In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use 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 CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. We expect this expansion to generate additional adjusted gross margin of $0.8 million beginning in 2022 and $1.0 million in 2023 and beyond.

Beachside Pipeline Expansion

In June 2021, Peninsula Pipeline and Florida City Gas 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 will construct approximately 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida, area east under the ICW and southward on the barrier island. We expect this expansion to generate additional annual adjusted gross margin of $2.5 million in 2023 and beyond.

Chesapeake Utilities Corporation 2021 Form 10-K Page 33

CNG Transportation

Marlin Gas Services provides CNG temporary hold services, contracted pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. For the year ended December 31, 2021, Marlin Gas Services generated additional adjusted gross margin of $0.3 million compared to the year ended December 31, 2020. We estimate that Marlin Gas Services will generate annual adjusted gross margin of approximately $8.5 million in 2022, and $9.5 million in 2023, with potential for additional growth in future years. Marlin Gas Services continues to actively expand the territories it serves, as well as leverage its patented technology to serve other markets, including pursuing liquefied natural gas transportation opportunities and renewable natural gas transportation opportunities from diverse supply sources to various pipeline interconnection points, as further outlined below.

RNG Transportation

Noble Road Landfill RNG Project

In September 2020, Fortistar and Rumpke Waste & Recycling announced commencement of construction of the Noble Road Landfill RNG Project in Shiloh, Ohio. The project includes the construction of a new state-of-the-art facility that will utilize advanced, patented technology to treat landfill gas by removing carbon dioxide and other components to purify the gas and produce pipeline quality RNG. In October 2021, we announced that Aspire Energy had completed construction of its Noble Road Landfill RNG pipeline project, a 33.1-mile pipeline, which will transport RNG generated from the 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. Once flowing, the RNG volume will represent nearly 10 percent of Aspire Energy’s gas gathering volumes.

Bioenergy Devco

In June 2020, our Delmarva natural gas operations and Bioenergy DevCo (“BDC”), a developer of anaerobic digestion facilities that create renewable energy and healthy soil products from organic material, entered into an agreement related to a project to extract RNG from poultry production waste. BDC and our affiliates are collaborating on this project in addition to several other project sites where organic waste can be converted into a carbon-negative energy source.

Marlin Gas Services will transport the RNG created from the organic waste from the BDC facility to an Eastern Shore interconnection, where the sustainable fuel will be introduced into our transmission system and ultimately distributed to our natural gas customers.

CleanBay Project

In July 2020, our Delmarva natural gas operations and CleanBay Renewables Inc. ("CleanBay") announced a new partnership to bring RNG to our operations. As part of this partnership, we will transport the RNG produced at CleanBay's planned Westover, Maryland bio-refinery, to our natural gas infrastructure in the Delmarva Peninsula region. Eastern Shore and Marlin Gas Services, will transport the RNG from CleanBay to our Delmarva natural gas distribution system where it is ultimately delivered to the Delmarva natural gas distribution end use customers.

At the present time, we expect to generate adjusted gross margin of $1.0 million in 2022 and beyond from renewable natural gas transportation. As we continue to finalize contract terms associated with some of these projects, additional information will be provided regarding incremental margin at a future time.

Acquisitions

Diversified Energy

On December 15, 2021, Sharp Energy acquired the propane operating assets of Diversified Energy Company for approximately $37.5 million net of cash acquired. There are multiple strategic benefits to this acquisition including it: (i) expands the Company's propane territory into North Carolina and South Carolina while also expanding our existing footprint in Pennsylvania and Virginia, and (ii) includes an established customer base with opportunities for future growth. Through this acquisition, the Company adds approximately 19,000 residential, commercial and agricultural customers, along with distribution of approximately 10.0 million gallons of propane annually. For the year ended December 31, 2021, Diversified Energy contributed $0.6 million in adjusted gross margin and is expected to generate $11.3 million of additional adjusted gross margin in 2022 and $12.0 million in 2023.

Elkton Gas

Chesapeake Utilities Corporation 2021 Form 10-K     Page 34

In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. The purchase price was approximately $15.6 million, which included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland. We generated $2.2 million in additional adjusted gross margin from Elkton Gas for the year ended December 31, 2021 and estimates that this acquisition will generate adjusted gross margin of approximately $3.7 million in 2022 and growing each year thereafter, as the distribution system serving Cecil County further expands to meet demand.

Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired The Company generated $1.4 million in additional adjusted gross margin from Western Natural Gas in 2021 and estimates that this acquisition will generate adjusted gross margin of approximately $2.0 million in 2022 with additional margin growth expected in future years as we further expand our presence.

Escambia Meter Station

In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light’s Crist Lateral pipeline. The Florida Power & Light Crist Lateral provides gas supply to their natural gas fired power plant owned by Florida Power & Light in Pensacola, Florida. The Company generated $0.6 million in additional adjusted gross margin in 2021 and estimates that this acquisition will generate adjusted gross margin of approximately $1.0 million in 2022 and beyond.

Regulatory Initiatives

Florida GRIP

Florida GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic recovery, through rates, of costs associated with the replacement of mains and services. Since the program's inception in August 2012, the Company has invested $189.5 million of capital expenditures to replace 348 miles of qualifying distribution mains, including $23.6 million and $21.0 million of new pipes during 2021 and 2020, respectively. GRIP generated additional gross margin of $1.8 million for the year ended 2021 compared to 2020. We are currently projecting to complete this program in 2022 and expect to generate adjusted gross margin of $18.8 million and $19.5 million in 2022 and 2023, respectively. The adjusted gross margin on GRIP investments will continue until the Company requests the remaining net GRIP investment, and the associated expenses, be included in its next base rate proceeding.

Hurricane Michael

In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida and caused widespread and severe damage to FPU's infrastructure resulting in 100 percent of its customers in the Northwest Florida service territory losing electrical service.

In September 2020, the Florida PSC approved a settlement agreement between FPU and the Office of the Public Counsel regarding final cost recovery and rates associated with Hurricane Michael. Previously, in late 2019, the Florida PSC approved an interim rate increase, subject to refund, effective January 1, 2020, associated with the restoration effort following Hurricane Michael. The Company fully reserved these interim rates, pending a final resolution and settlement of the limited proceeding. The settlement agreement allowed us to: (a) refund the over-collection of interim rates through the fuel clause; (b) record regulatory assets for storm costs in the amount of $45.8 million including interest which will be amortized over six years; (c) recover these storm costs through a surcharge for a total of $7.7 million annually; and (d) collect an annual increase in revenue of $3.3 million to recover capital costs associated with new plant investments and a regulatory asset for the cost of removal and unrecovered plant costs. The new base rates and storm surcharge were effective on November 1, 2020. The following table summarizes the impact of Hurricane Michael regulatory proceeding for the years ended December 31, 2021 and 2020:

Chesapeake Utilities Corporation 2021 Form 10-K Page 35

	For the Year Ended December 31,		For the Year Ended December 31,
(in thousands)	2021		2020
Adjusted Gross Margin	$	11,492	$	10,864
Depreciation	1,218		1,184
Amortization of regulatory assets	(8,317)		(8,317)
Operating income	4,393		3,731
Amortization of liability associated with interest expense	1,207		1,475
Pre-tax income	5,600		5,206
Income tax expense	(1,484)		(1,403)
Net income	$	4,116	$	3,803

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 2021 there was $0.7 million of adjusted gross margin was added pursuant to the program. Eastern Shore expects to produce adjusted gross margin of approximately $2.0 million in 2022 and 2023 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

Elkton Gas STRIDE Plan

In March 2021, Elkton Gas filed a STRIDE plan with the Maryland PSC. The STRIDE plan proposes to increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of a fixed charge rider through a proposed 5-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. In June 2021, we reached a settlement with the Maryland PSC Staff and the Maryland Office of the Peoples Counsel. The STRIDE plan went into service in September 2021 and is expected to generate $0.3 million of additional adjusted gross margin in 2022 and $0.4 million annually thereafter.

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 will allow us to seek recovery of these costs in the next base rate proceedings. In November 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset treatment. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allowed 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 will amortize the amount over two years beginning January 1, 2022 and recover 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 division. This results in annual additional adjusted gross margin of $1.0 million that will be offset by a corresponding amortization of regulatory asset expense for both 2022 and 2023.

Other Major Factors Influencing Adjusted Gross Margin

Weather and Consumption

Weather conditions accounted for increased adjusted gross margin of $5.5 million in 2021 compared to 2020. Assuming normal temperatures, as detailed below, adjusted gross margin would have been higher by $2.2 million. 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 December 31, 2021 compared to 2020 and December 31, 2020 compared to 2019.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 36

HDD and CDD Information

	For the Years Ended December 31,
	2021	2020	Variance	2020	2019	Variance
Delmarva
Actual HDD	3,849	3,716	133	3,716	4,089	(373)
10-Year Average HDD ("Normal")	4,182	4,294	(112)	4,294	4,379	(85)
Variance from Normal	(333)	(578)		(578)	(290)
Florida (1)
Actual HDD	829	745	84	745	740	5
10-Year Average HDD ("Normal")	839	933	(94)	933	967	(34)
Variance from Normal	(10)	(188)		(188)	(227)
Ohio
Actual HDD	5,138	5,218	(80)	5,218	5,500	(282)
10-Year Average HDD ("Normal")	5,621	5,701	(80)	5,701	5,983	(282)
Variance from Normal	(483)	(483)		(483)	(483)
Florida (1)
Actual CDD	2,687	3,078	(391)	3,078	3,194	(116)
10-Year Average CDD ("Normal")	2,952	2,931	21	2,931	2,889	42
Variance from Normal	(265)	147		147	305

(1) Prior year amounts have been revised to conform to the current period presentation.

Natural Gas Distribution Growth

Customer growth for our natural gas distribution operations, as a result of the addition of new customers and the conversion of customers from alternative fuel sources to natural gas service, generated $3.1 million of additional adjusted gross margin in 2021. The average number of residential customers served on the Delmarva Peninsula and Florida increased by approximately 4.5 percent and 4.7 percent, respectively, during 2021. 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 infrastructure is added 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:

	Adjusted Gross Margin increase
	For the Year Ended December 31, 2021
(in thousands)	Delmarva Peninsula		Florida
Customer growth:
Residential	$	1,468	$	1,010
Commercial and industrial	278		328
Total customer growth	$	1,746	$	1,338

Chesapeake Utilities Corporation 2021 Form 10-K Page 37

REGULATED ENERGY

					Increase						Increase
For the Year Ended December	2021		2020		(decrease)		2020		2019		(decrease)
(in thousands)
Revenue	$	383,920	$	352,746	$	31,174	$	352,746	$	343,006	$	9,740
Natural gas and electric costs	100,737		91,994		8,743		91,994		102,803		(10,809)
Adjusted gross margin (1)	283,183		260,752		22,431		260,752		240,203		20,549
Operations & maintenance	108,300		104,379		3,921		104,379		102,099		2,280
Gain from a settlement	—		(130)		130		(130)		(130)		—
Depreciation & amortization	48,748		46,079		2,669		46,079		35,227		10,852
Other taxes	20,071		18,300		1,771		18,300		16,423		1,877
Other operating expenses	177,119		168,628		8,491		168,628		153,619		15,009
Operating Income	$	106,064	$	92,124	$	13,940	$	92,124	$	86,584	$	5,540

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.

2021 compared to 2020

Operating income for the Regulated Energy segment for 2021 was $106.1 million, an increase of $13.9 million, or 15.1 percent, compared to 2020. Higher operating income reflects continued pipeline expansions by Eastern Shore and Peninsula Pipeline, organic growth in the natural gas distribution businesses, increased consumption from a return toward pre-pandemic consumption levels and operating results from 2020 and 2021 acquisitions. We recorded higher depreciation, amortization and property taxes of $4.3 million related to recent capital investments and net operating expenses of $4.2 million. The increase was associated primarily with an increase in outside services, employee related costs and increased spending with the 2020 and 2021 acquisitions. In addition to these growth drivers, the increase in other operating expenses was also attributable to operations returning towards pre-pandemic conditions. Partially offsetting the increase was the establishment of regulatory assets for COVID-19 expenses approved by the various state PSCs of approximately $2.4 million.

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

(in thousands)
Eastern Shore and Peninsula Pipeline service expansions	$	7,168
Natural gas distribution customer growth (excluding service expansions)	3,084
Increased customer consumption - primarily due to return to pre-pandemic consumption	3,027
Contributions from 2020 and 2021 acquisitions	2,787
Florida GRIP	1,817
Increased customer consumption - primarily weather related	1,159
Improved results from electric operations	1,015
Eastern Shore capital relocation and non-service expansion projects	676
Sandpiper infrastructure rider associated with conversions	665
Other	1,033
Year-over-year increase in adjusted gross margin	$	22,431

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

Eastern Shore and Peninsula Pipeline Service Expansions

We generated increased earnings of $5.1 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $2.1 million from Eastern Shore's Del-Mar Energy Pathway project.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 38

Natural Gas Distribution Customer Growth

Organic growth within our natural gas distribution businesses improved operating results compared to the full year 2020. Residential customer growth was 4.5 percent on the Delmarva Peninsula and 4.7 percent in Florida compared to the prior year. On the Delmarva Peninsula, a larger percentage of our results was generated from residential growth given the expansion of gas into new communities and conversions, while in Florida, as gas heating is not a significant portion of residential use, a greater portion occurred in the commercial and industrial sectors.

Consumption Increase – Return Towards Pre-pandemic Conditions

Increased customer consumption, which reflects the ongoing return toward pre-pandemic conditions in our service territories as a result of the expiration of restrictions imposed to slow down the spread of COVID-19 increased adjusted gross margin by $3.0 million.

Contribution from Acquisitions

The acquisition of Elkton Gas in July 2020 and the Escambia meter station in June 2021 increased adjusted gross margin by $2.8 million.

Florida GRIP

Continued investment in the Florida GRIP generated additional adjusted gross margin of $1.8 million.

Increased Customer Consumption - Weather Related

Adjusted gross margin increased by $1.2 million due to colder weather and higher other consumption on the Delmarva Peninsula and in Florida in 2021 compared to 2020. The weather on the Delmarva Peninsula was 4 percent cooler in 2021 compared to 2020.

Improved Results from Electric Operations

Our electric operations generated additional adjusted gross margin of $1.0 million due to increased consumption and growth.

Eastern Shore Capital Relocation and Non-service Expansion Projects

We generated additional adjusted gross margin of $0.7 million from Eastern Shore's surcharge on capital spent on several governmental-mandated relocation and non-service expansion projects.

Sandpiper Energy Infrastructure Rider Associated with Conversions

Conversion of Sandpiper Energy's propane customers to natural gas customers generated additional adjusted gross margin of $0.7 million.

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

(in thousands)
Depreciation, amortization and property tax costs due to new capital investments	$	4,323
Outside services due to growth and a return toward pre-pandemic conditions	3,102
Payroll, benefits and other employee-related expenses	1,489
Operating expenses from the Elkton Gas acquisition	1,370
Regulatory deferral of COVID-19 expenses per PSCs orders	(2,377)
Other variances	584
Period-over-period increase in other operating expenses	$	8,491

2020 compared to 2019

The results for the Regulated Energy segment for the year ended December 31, 2020 compared to 2019 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated herein by reference.

Chesapeake Utilities Corporation 2021 Form 10-K Page 39

UNREGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2021		2020		(decrease)		2020		2019		(decrease)
(in thousands)
Revenue	$	206,869	$	152,526	$	54,343	$	152,526	$	154,150	$	(1,624)
Propane and natural gas costs	106,900		62,780		44,120		62,780		68,884		(6,104)
Adjusted gross margin (1)	99,969		89,746		10,223		89,746		85,266		4,480
Operations & maintenance	57,950		53,839		4,111		53,839		52,028		1,811
Depreciation & amortization	13,869		11,988		1,881		11,988		10,130		1,858
Other taxes	3,768		3,255		513		3,255		3,170		85
Other operating expenses	75,587		69,082		6,505		69,082		65,328		3,754
Operating Income	$	24,382	$	20,664	$	3,718	$	20,664	$	19,938	$	726

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.

2021 Compared to 2020

Operating income for the Unregulated Energy segment for 2021 was $24.4 million, an increase of $3.7 million compared to 2020. The higher operating income is a result of weather that was colder than 2020, higher retail propane margins per gallon and service fees, incremental adjusted gross margin from the propane acquisitions completed in 2020 and 2021, increased demand for Marlin Gas Services' CNG transportation services and increased customer consumption along with higher rates for Aspire Energy. These adjusted gross margin increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments and acquisitions,a return toward pre-pandemic conditions and a general increase in operating expenses to support growth in the business.

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 customer consumption - primarily weather related	$	3,603
Increased retail propane margins per gallon and service fees	3,250
Acquisitions of Western Natural Gas and Diversified Energy (completed October 2020 and December 2021)	1,986
Increased wholesale propane margins per gallon	388
Marlin Gas Services
Increased demand for CNG services	334
Aspire Energy
Increased customer consumption - primarily weather related	757
Higher overall rates inclusive of natural gas liquid processing	325
Other variances	(420)
Year-over-year increase in adjusted gross margin	$	10,223

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

Propane Operations

•Increased Customer Consumption Primarily Weather Related - Adjusted gross margin increased by $3.6 million for the Mid-Atlantic propane operations as weather on the Delmarva Peninsula was 4 percent colder in 2021 compared to 2020.

•Increased Retail Propane Margins Per Gallon and Service Fees - Adjusted gross margin increased by $3.2 million, due to lower propane inventory costs and favorable market conditions as well as resuming the assessment of our customary service fees. These market conditions, which include 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 40

•Acquisitions of Western Natural Gas and Diversified Energy - We generated adjusted gross margin of $1.4 million from Western Natural Gas which was acquired by Sharp in October 2020 and $0.6 million from Diversified Energy which was acquired by Sharp in December 2021.

•Increased Wholesale Propane Margins per Gallon - Adjusted gross margin increased by $0.4 million during 2021 over the same period in 2020, due to lower propane inventory costs and favorable market conditions. These conditions tend to fluctuate based on changes in demand, supply and other energy commodity prices.

Marlin Gas Services

•Increased demand for Marlin Gas Services’ CNG hold services improved operating results compared to 2020.

Aspire Energy

•Increased Customer Consumption Primarily Weather Related - Adjusted gross margin increased by $0.8 million due to higher consumption related to weather as compared to the prior year.

•Improved Performance From Natural Gas Liquid Processing - Adjusted gross margin increased by $0.3 million, from natural gas liquid processing activities compared to 2020.

Other Operating Expenses

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

(in thousands)
Depreciation, amortization and property tax costs due to new capital investments	$	1,985
Operating expenses from Western Natural Gas and Diversified Energy acquisitions	1,130
Increased facilities and maintenance costs	1,036
Increased vehicle expenses	417
Insurance related costs (non-health)	395
Outside services due to growth and a return toward pre-pandemic conditions	364
Payroll, benefits and other employee-related expenses due to growth	311
Other variances	867
Period-over-period increase in other operating expenses	$	6,505

2020 compared to 2019

The results for the Unregulated Energy segment for the year ended December 31, 2020 compared to 2019 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2020, which is incorporated by reference.

Divestiture of PESCO

During the fourth quarter of 2019, we sold PESCO's assets and contracts and accordingly have exited the natural gas marketing business. This was done in an effort to enable us to focus on the strategies that support our core energy delivery business. As a result, we began to report PESCO as discontinued operations during the third quarter of 2019 and excluded PESCO's performance from continuing operations for all periods presented and classified its assets and liabilities as held for sale, where applicable.

Chesapeake Utilities Corporation 2021 Form 10-K Page 41

OTHER INCOME (EXPENSE), NET

Other income (expense), net was $1.7 million and $3.2 million for 2021 and 2020, respectively. Other income (expense), 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 due to a higher level of asset sales in 2020 compared to 2021.

INTEREST CHARGES

2021 Compared to 2020

Interest charges for 2021 decreased by $1.6 million, compared to the same period in 2020. In the fourth quarter of 2020, the 9.08% FPU secured first mortgage bonds were terminated resulting in $1.0 million in interest and fees associated with the early payoff. Interest expense, which included the expense associated with the bonds decreased by $0.6 million due primarily to lower levels outstanding under our revolving credit facilities and lower interest rates on short-term borrowings. This decrease was offset by an increase of $0.5 million primarily due to lower capitalized interest associated with growth projects and $0.3 million of an amortization credit/reduction in interest expense associated with a regulatory liability that was established in connection with the Hurricane Michael regulatory proceeding settlement.

INCOME TAXES

2021 Compared to 2020

Income tax expense from continuing operations was $29.2 million for 2021 compared to $23.5 million for 2020. Our effective income tax rates were 25.9 percent and 25.0 percent for the year ended December 31, 2021 and 2020, respectively. During the years ended December 31, 2021 and 2020 we implemented certain provisions of the CARES Act that allowed us to carryback net operating losses into prior year periods where the federal income tax rate was higher. As a result, we recognized a $0.9 million reduction in tax expense for the twelve months ended December 31, 2021 and a $1.8 million reduction for the twelve months ended December 31, 2020. Excluding this impact of the CARES Act, our effective` tax rates for the years ended December 31, 2021 and 2020 were 26.8 percent and 26.9 percent, respectively.

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 an effective shelf registration statement with the SEC for the issuance of shares of common stock under various types of equity offerings, including shares of common stock under our ATM equity program, as well as an effective registration statement with respect to the DRIP. 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 the ATM equity program. Beginning in the third quarter of 2020, we issued shares of common stock under both the DRIP and the 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 $227.8 million in 2021.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 42

The following table shows total capital expenditures for the year ended December 31, 2021 by segment and by business line:

	For the Year Ended December 31, 2021
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	78,084
Natural gas transmission	55,149
Electric distribution	6,500
Total Regulated Energy	139,733
Unregulated Energy:
Propane distribution	46,023
Energy transmission	20,101
Other unregulated energy	15,527
Total Unregulated Energy	81,651
Other:
Corporate and other businesses	6,425
Total Other	6,425
Total 2021 Capital Expenditures	$	227,809

In the table below, we have provided a range of our forecasted capital expenditures for 2022:

	Estimate for Fiscal 2022
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	87,000	$	92,000
Natural gas transmission	60,000		67,000
Electric distribution	7,000		12,000
Total Regulated Energy	154,000		171,000
Unregulated Energy:
Propane distribution	10,000		14,000
Energy transmission	5,000		6,000
Other unregulated energy	4,000		5,000
Total Unregulated Energy	19,000		25,000
Other:
Corporate and other businesses	2,000		4,000
Total Other	2,000		4,000
Total 2022 Forecasted Capital Expenditures	$	175,000	$	200,000

The 2022 forecast, excluding acquisitions, includes capital expenditures for the following: Pipeline expansions related to the Eastern Shore Southern expansion and the Florida Beachside Pipeline as well as amounts for the expansion into Somerset County, Maryland. Furthermore, the 2022 forecast includes continued expenditures under the Florida GRIP, the capital cost surcharge program and the Elkton Gas STRIDE program as well as further expansion of our natural gas distribution and transmission systems, information technology systems and other strategic initiatives and investments.

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, capital delays because of COVID-19 that are greater than currently anticipated, customer growth in existing areas, regulation, new growth or acquisition opportunities, availability of capital and other factors discussed in Item 1A. Risk Factors. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.

Chesapeake Utilities Corporation 2021 Form 10-K Page 43

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, excluding and including short-term borrowings, as of December 31, 2021 and 2020 follows:

	December 31, 2021				December 31, 2020
(in thousands)
Long-term debt, net of current maturities	$	549,903	42	%	$	508,499	42	%
Stockholders’ equity	774,130		58	%	697,085		58	%
Total capitalization, excluding short-term borrowings	$	1,324,033	100	%	$	1,205,584	100	%

	December 31, 2021				December 31, 2020
(in thousands)
Short-term debt	$	221,634	14	%	$	175,644	13	%
Long-term debt, including current maturities	567,866		36	%	522,099		37	%
Stockholders’ equity	774,130		50	%	697,085		50	%
Total capitalization, including short-term borrowings	$	1,563,630	100	%	$	1,394,828	100	%

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was approximately 50 percent as of December 31, 2021. We seek to align permanent financing with the in-service dates of capital projects. We may utilize more temporary short-term debt when the financing cost is attractive as a bridge to the permanent long-term financing or if the equity markets are volatile.

In 2021, we issued just over 0.1 million shares at an average price per share of $125.71 and received net proceeds of $15.2 million under the DRIP. In the third and fourth quarters of 2020, we issued 1.0 million shares of common stock through our DRIP and the ATM programs and received net proceeds of approximately $83.0 million which were added to the general funds and then used to pay down short-term borrowing. See Note 16, Stockholders’ Equity, in the consolidated financial statements for additional information on commissions and fees paid in connection with these issuances.

Uncollateralized Senior Notes

All of our Senior Notes require periodic principal and interest payments as specified in each note. They also contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40 percent of total capitalization (including short-term borrowings), and the fixed charge coverage ratio must be at least 1.2 times. The most recent Senior Notes issued since September 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain Uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2021, the cumulative consolidated net income base was $664.5 million, offset by restricted payments of $289.4 million, leaving $375.1 million of cumulative net income free of restrictions.

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at December 31, 2021:

Chesapeake Utilities Corporation 2021 Form 10-K     Page 44

	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
(in thousands)
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	—		$	150,000
MetLife Shelf Agreement (2)	150,000		—		(50,000)		100,000
Total	$	520,000	$	(220,000)	$	(50,000)	$	250,000

(1) The Prudential and MetLife Shelf Agreements expire in April 2023 and May 2023, respectively.

(2) Unfunded commitments of $50 million reflects Senior Notes expected to be issued on or before March 15, 2022.

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

Short-Term Borrowings

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At December 31, 2021 and 2020, we had $221.6 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 0.83 percent and 1.28 percent, respectively.

In August 2021, we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the facility consist of a $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three one-year extension options, which can be authorized by our Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the facility and to the extent that an individual loan under the revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2021, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026. Both tranches are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon a total indebtedness to total capitalization ratio. As of December 31, 2021, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of December 31, 2021, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

Our total available credit under the Revolver at December 31, 2021 was $173.1 million. As of December 31, 2021, we had issued $5.3 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

In the fourth quarter of 2020, we entered into two $30.0 million interest rate swaps with a total notional amount of $60.0 million through December 2021 with pricing of 0.20 percent and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. As of December 31, 2021 all of our interests rate swaps had expired and we had not entered into any new swaps.

Chesapeake Utilities Corporation 2021 Form 10-K Page 45

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, 2021, 2020 and 2019 are as follows:

(in thousands)	2021			2020			2019
Average borrowings during the year	$	182,305		$	230,526		$	257,587
Weighted average interest rate for the year	1.03		%	1.50		%	3.11		%
Maximum month-end borrowings	$	226,097		$	284,914		$	302,379

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Net cash provided by (used in):
Operating activities	$	150,504	$	158,916	$	102,964
Investing activities	(223,023)		(181,631)		(186,587)
Financing activities	73,996		19,229		84,519
Net (decrease) increase in cash and cash equivalents	1,477		(3,486)		896
Cash and cash equivalents—beginning of period	3,499		6,985		6,089
Cash and cash equivalents—end of period	$	4,976	$	3,499	$	6,985

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 2021, net cash provided by operating activities was $150.5 million. Operating cash flows were primarily impacted by the following:

•Net income, adjusted for non-cash adjustments, provided a $162.3 million source of cash;

•An increased level of deferred taxes associated with incremental tax depreciation from growth investments resulted in a source of cash of $26.7 million;

•Changes in net regulatory assets and liabilities due primarily to the change in fuel costs collected through the various cost recovery mechanisms generated an $18.5 million use of cash;

•Working capital changes, impacted primarily by propane inventory purchases and hedging activities, resulted in a $15.4 million use of cash; and

•An increase in income tax receivables reduced cash inflows by $4.6 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $223.0 million during the year ended December 31, 2021. Key investing activities contributing to the cash flow change included:

•Cash used to pay for capital expenditures was $186.9 million for 2021; and

•Net cash of $36.4 million was used to acquire certain propane operating assets of Diversified Energy in 2021.

Cash Flows Provided by Financing Activities

Chesapeake Utilities Corporation 2021 Form 10-K     Page 46

Net cash provided by financing activities totaled $74.0 million for the year ended December 31, 2021. Net cash provided by financing activities:

•Net increase in borrowings under lines of credit of $46.6 million to support working capital needs and short-term capital spending;

•Net increase in long-term debt borrowings resulted in a source of cash of $45.7 million to permanently finance investment in growth initiatives;

•Source of cash of $15.9 million from issuance of stock under the DRIP; and

•A use of cash of $31.5 million for dividend payments in 2021.

CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2021:

	Payments Due by Period
Contractual Obligations	2022		2023-2024		2025-2026		After 2026		Total
(in thousands)
Long-term debt (1)	$	17,962	$	39,988	$	60,078	$	450,750	$	568,778
Operating leases (2)	2,019		3,574		2,226		3,668		11,487
Purchase obligations (3)
Transmission capacity	35,368		68,183		56,566		147,899		308,016
Storage capacity	2,741		1,391		612		383		5,127
Commodities	45,066		—		—		—		45,066
Electric supply	6,382		12,838		12,936		25,921		58,077
Unfunded benefits (4)	315		611		583		1,265		2,774
Funded benefits (5)	2,104		3,607		3,607		3,052		12,370
Total Contractual Obligations	$	111,957	$	130,192	$	136,608	$	632,938	$	1,011,695

(1) This represents principal payments on long-term debt. See Item 8, Financial Statements and Supplementary Data, Note 13, Long-Term Debt, for additional information. The expected interest payments on long-term debt are $18.8 million, $36.0 million, $32.8 million and $90.2 million, respectively, for the periods indicated above. Expected interest payments for all periods total $177.8 million.

(2) See Item 8, Financial Statements and Supplementary Data, Note 15, Leases, for additional information.

(3) See Item 8, Financial Statements and Supplementary Data, Note 21, 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 17, Employee Benefit Plans, for additional information on the plans.

(5) We have recorded long-term liabilities of $8.3 million at December 31, 2021 for the FPU qualified, defined benefit pension plan. The assets funding this plan is in a separate trust and is not considered assets of ours or included in our balance sheets. The Contractual Obligations table above includes $0.3 million, reflecting the payments we expect to make to the trust funds in 2022. 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 17, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $12.1 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, 2021 was $20.0 million. The aggregate amount guaranteed at December 31, 2021 was $13.1 million, with the guarantees expiring on various dates through December 1, 2022.

As of December 31, 2021, we have issued letters of credit totaling approximately $5.3 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 25, 2022. There have been no draws on these letters of credit as of December 31, 2021. 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 21, Other Commitments and Contingencies in the consolidated financial statements.

Chesapeake Utilities Corporation 2021 Form 10-K Page 47

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.

Valuation of Environmental Liabilities and Related Regulatory Assets

As more fully described in Item 8, Financial Statements and Supplementary Data, Note 20, Environmental Commitments and Contingencies, in the consolidated financial statements, we are currently participating in the investigation, assessment or remediation of former MGP sites for which we have sought or will seek regulatory approval to recover through rates the estimated costs of remediation and related activities. Amounts have been recorded as environmental liabilities based on estimates of future costs to remediate these sites, which are provided by independent consultants.

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.

Operating Revenues

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC of each state in which we operate. Customers’ base rates may not be changed without formal approval by these PSCs. However, the PSCs 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 negotiated rates.

Peninsula Pipeline, our Florida intrastate pipeline subsidiary that is subject to regulation by the Florida PSC, has negotiated firm transportation service contracts with third-party customers and with certain affiliates.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 48

For regulated deliveries of natural gas, electricity and propane, 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 that have been 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. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers, whose billing cycles do not coincide with the accounting periods.

Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped, using contractual rates, which are 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.

Each of our natural gas distribution operations in Delaware and Maryland, our bundled natural gas distribution service in Florida and our electric distribution operation in Florida has a fuel cost recovery mechanism. This mechanism provides a method of adjusting billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is 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 industrial interruptible customers on our natural gas distribution systems to compete with the price of alternative fuel that they can use. Neither we, nor any of our interruptible customers, are contractually obligated to deliver or receive natural gas on a firm service basis.

Allowance for Credit Losses

An allowance for expected credit losses is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experience, the condition of the overall economy and our assessment of our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices, impacts from pandemics and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Goodwill and Other Intangible Assets

We test goodwill for impairment at least annually in December. The annual impairment testing for 2021 indicated no impairment of goodwill. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 11, Goodwill and Other Intangible Assets, in the consolidated financial statements.

Other Assets Impairment Evaluations

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

Pension and Other Postretirement Benefits

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 17, 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.

During the fourth quarter of 2021, we formally terminated the Chesapeake Utilities Pension Plan. For 2021, 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 2.75 percent. The discount rate was determined by management considering high-quality corporate bond rates, such as the

Chesapeake Utilities Corporation 2021 Form 10-K Page 49

Prudential 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 decrease in the discount rate could decrease our annual pension and postretirement costs by an immaterial amount, and a 0.25 percent increase could increase our annual pension and postretirement costs by an immaterial amount.

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. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $0.1 million and would not have an impact on the postretirement and Chesapeake Utilities supplemental executive retirement pension plan ("Chesapeake SERP") because these plans are not funded.

Tax-Related Contingency

We account for uncertainty in income taxes in the consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on its 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 quantifiable. 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.

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

INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. 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 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 13, Long-Term Debt, and Note 14, 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 2021 Form 10-K     Page 50

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2020 to December 31, 2021:

(in thousands)	Balance at December 31, 2020		Increase (Decrease) in Fair Market Value		Less Amounts Settled		Balance at December 31, 2021
Sharp	$	3,182	$	9,802	$	(6,651)	$	6,333

There were no changes in the methods of valuations during the year ended December 31, 2021.

The following is a summary of fair market value of financial derivatives as of December 31, 2021, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2022		2023		2024		Total Fair Value
Price based on Mont Belvieu - Sharp	$	3,574	$	1,983	$	776	$	6,333

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 2021 Form 10-K Page 51

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, 2021 and 2020, 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, 2021, 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, 2021, 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, 2021 and 2020, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2021, 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, 2021, 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 its 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 consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

Definition and Limitations of Internal Control Over Financial Reporting

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

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 2021 Form 10-K     Page 52

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) relate 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 separate opinions on the critical audit matter or on the accounts or disclosures to which they relate.

Goodwill Impairment Assessment - Energy Transmission and Supply Services (Aspire Energy), Mid-Atlantic Propane Operations, Florida Propane Operations and Marlin Gas Services - Unregulated Energy Segment - Refer to Notes 1 and 11 to the consolidated financial statements

Critical Audit Matter Description

As described in Notes 1 and 11 to the consolidated financial statements, the Company has recorded approximately $37.0 million of goodwill within the Unregulated Energy reportable segment as of December 31, 2021, all of which relates to the four reporting units listed above. 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 for December 31, 2021 indicated no impairment.

We determined the goodwill impairment assessment for the four reporting units listed above was a critical audit matter because the fair value estimates require significant estimates and assumptions by management, including those relating to future revenue and operating margin forecasts and discount rates. Testing these estimates involved increased auditor judgment 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 reporting units within the Unregulated Energy reportable segment.

•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 each 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, inclusive of the Regulated and Unregulated Energy reporting units, 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.

Philadelphia, Pennsylvania

February 23, 2022

Chesapeake Utilities Corporation 2021 Form 10-K Page 53

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Income

	For the Year Ended December 31,
	2021		2020		2019
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	383,920	$	352,746	$	343,006
Unregulated Energy	206,869		152,526		154,151
Other businesses and eliminations	(20,821)		(17,074)		(17,552)
Total operating revenues	569,968		488,198		479,605
Operating Expenses
Natural gas and electricity costs	100,737		91,994		102,803
Propane and natural gas costs	86,213		45,944		51,698
Operations	148,294		142,055		137,845
Maintenance	16,793		15,587		15,679
Gain from a settlement	—		(130)		(130)
Depreciation and amortization	62,661		58,117		45,424
Other taxes	24,158		21,908		20,001
Total operating expenses	438,856		375,475		373,320
Operating Income	131,112		112,723		106,285
Other income (expense), net	1,721		3,222		(1,847)
Interest charges	20,135		21,765		22,224
Income from Continuing Operations Before Income Taxes	112,698		94,180		82,214
Income Taxes on Continuing Operations	29,231		23,538		21,114
Income from Continuing Operations	83,467		70,642		61,100
Income (loss) from Discontinued Operations, Net of Tax	(1)		686		(1,349)
Gain on sale of Discontinued Operations, Net of tax	—		170		5,402
Net Income	$	83,466	$	71,498	$	65,153
Weighted Average Common Shares Outstanding:
Basic	17,558,078		16,711,579		16,398,443
Diluted	17,633,029		16,770,735		16,448,486
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.75	$	4.23	$	3.73
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Basic Earnings Per Share of Common Stock	$	4.75	$	4.28	$	3.97
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.73	$	4.21	$	3.72
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Diluted Earnings Per Share of Common Stock	$	4.73	$	4.26	$	3.96

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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 54

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Comprehensive Income

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Net Income	$	83,466	$	71,498	$	65,153
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(20), $(18) and $(20), respectively	(57)		(59)		(57)
Net gain (loss), net of tax of $662, $(41), and $368, respectively	1,935		(154)		1,052
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $864, $1,392 and $(176), respectively	2,262		3,643		(434)
Unrealized gain (loss) on interest rate swap cash flow hedges, net of tax of $12, $(12), and $0, respectively	28		(28)		—
Total Other Comprehensive Income	4,168		3,402		561
Comprehensive Income	$	87,634	$	74,900	$	65,714

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 55

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Assets	2021		2020
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,720,287	1,577,576
Unregulated Energy	357,259		300,647
Other businesses and eliminations	35,418		30,769
Total property, plant and equipment	2,112,964		1,908,992
Less: Accumulated depreciation and amortization	(417,479)		(368,743)
Plus: Construction work in progress	49,393		60,929
Net property, plant and equipment	1,744,878		1,601,178
Current Assets
Cash and cash equivalents	4,976		3,499
Trade and other receivables	61,623		61,675
Less: Allowance for credit losses	(3,141)		(4,785)
Trade receivables, net	58,482		56,890
Accrued revenue	22,513		21,527
Propane inventory, at average cost	11,644		5,906
Other inventory, at average cost	9,345		5,539
Regulatory assets	19,794		10,786
Storage gas prepayments	3,691		2,455
Income taxes receivable	17,460		12,885
Prepaid expenses	17,121		13,239
Derivative assets, at fair value	7,076		3,269
Other current assets	1,033		436
Total current assets	173,135		136,431
Deferred Charges and Other Assets
Goodwill	44,708		38,731
Other intangible assets, net	13,192		8,292
Investments, at fair value	12,095		10,776
Operating lease right-of-use assets	10,139		11,194
Regulatory assets	104,173		113,806
Receivables and other deferred charges	12,549		12,079
Total deferred charges and other assets	196,856		194,878
Total Assets	$	2,114,869	$	1,932,487

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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 56

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Capitalization and Liabilities	2021		2020
(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)	8,593		8,499
Additional paid-in capital	371,162		348,482
Retained earnings	393,072		342,969
Accumulated other comprehensive income (loss)	1,303		(2,865)
Deferred compensation obligation	7,240		5,679
Treasury stock	(7,240)		(5,679)
Total stockholders’ equity	774,130		697,085
Long-term debt, net of current maturities	549,903		508,499
Total capitalization	1,324,033		1,205,584
Current Liabilities
Current portion of long-term debt	17,962		13,600
Short-term borrowing	221,634		175,644
Accounts payable	52,628		60,253
Customer deposits and refunds	36,488		33,302
Accrued interest	2,775		2,905
Dividends payable	8,466		7,683
Accrued compensation	15,505		13,994
Regulatory liabilities	2,312		6,284
Derivative liabilities, at fair value	743		127
Other accrued liabilities	17,920		15,240
Total current liabilities	376,433		329,032
Deferred Credits and Other Liabilities
Deferred income taxes	233,550		205,388
Regulatory liabilities	142,488		142,736
Environmental liabilities	3,538		4,299
Other pension and benefit costs	24,120		30,673
Operating lease - liabilities	8,571		9,872
Deferred investment tax credits and other liabilities	2,136		4,903
Total deferred credits and other liabilities	414,403		397,871
Environmental and other commitments and contingencies (Note 20 and 21)
Total Capitalization and Liabilities	$	2,114,869	$	1,932,487

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 57

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Operating Activities
Net Income	$	83,466	$	71,498	$	65,153
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	62,661		58,117		45,900
Depreciation and accretion included in operations expenses	10,228		9,599		8,752
Deferred income taxes, net	26,658		24,709		24,476
Gain on sale of discontinued operations	—		(200)		(7,344)
Realized (loss) on sale of assets/commodity contracts	(9,026)		(6,243)		(4,135)
Unrealized (gain) on investments/commodity contracts	(1,464)		(1,482)		(1,595)
Employee benefits and compensation	(53)		207		1,985
Share-based compensation	5,945		4,829		4,279
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(1,634)		(7,426)		36,489
Propane inventory, storage gas and other inventory	(9,517)		1,709		8,227
Regulatory assets/liabilities, net	(18,464)		(4,973)		(7,812)
Prepaid expenses and other current assets	(1,520)		2,424		11,115
Accounts payable and other accrued liabilities	8,285		4,941		(62,021)
Income taxes receivable	(4,575)		7,165		(4,750)
Customer deposits and refunds	3,176		2,238		(1,811)
Accrued compensation	1,198		(2,473)		2,120
Other assets and liabilities, net	(4,860)		(5,723)		(16,064)
Net cash provided by operating activities	150,504		158,916		102,964
Investing Activities
Property, plant and equipment expenditures	(186,924)		(165,511)		(184,727)
Proceeds from sale of assets	1,033		8,080		427
Acquisitions, net of cash acquired	(36,371)		(22,231)		(23,988)
Proceeds from the sale of discontinued operations	—		200		22,871
Environmental expenditures	(761)		(2,169)		(1,170)
Net cash used in investing activities	(223,023)		(181,631)		(186,587)
Financing Activities
Common stock dividends	(31,537)		(27,161)		(24,693)
Issuance of stock for Dividend Reinvestment Plan	15,851		22,627		(721)
Proceeds from issuance of common stock, net of expenses	—		60,980		—
Tax withholding payments related to net settled stock compensation	(1,478)		(977)		(692)
Change in cash overdrafts due to outstanding checks	(1,154)		(825)		(1,174)
Net borrowings (repayments) under line of credit agreements	46,647		(71,637)		(45,913)
Proceeds from issuance of long-term debt	59,478		89,822		199,648
Repayment of long-term debt and finance lease obligation	(13,811)		(53,600)		(41,936)
Net cash provided by financing activities	73,996		19,229		84,519
Net (Decrease) Increase in Cash and Cash Equivalents	1,477		(3,486)		896
Cash and Cash Equivalents — Beginning of Period	3,499		6,985		6,089
Cash and Cash Equivalents — End of Period	$	4,976	$	3,499	$	6,985

Supplemental Cash Flow Disclosures (see Note 7)

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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 58

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 Loss		Deferred Compensation		Treasury Stock		Total
Balance at December 31, 2018	16,378,545	$	7,971	$	255,651	$	261,530	$	(6,713)	$	3,854	$	(3,854)	$	518,439
Net Income	—	—		—		65,153		—		—		—		65,153
Prior period reclassification	—	—		—		115		(115)		—		—		—
Other comprehensive loss	—	—		—		—		561		—		—		561
Dividends declared ($1.585 per share)	—	—		—		(26,191)		—		—		—		(26,191)
Dividend reinvestment plan	—	—		(3)		—		—		—		—		(3)
Share-based compensation and tax benefit (3) (4)	25,231	13		3,605		—		—		—		—		3,618
Treasury stock activities(2)	—	—		—		—		—		689		(689)		—
Balance at December 31, 2019	16,403,776	7,984		259,253		300,607		(6,267)		4,543		(4,543)		561,577
Net Income	—	—		—		71,498		—		—		—		71,498
Other comprehensive income	—	—		—		—		3,402		—		—		3,402
Dividends declared ($1.725 per share)	—	—		—		(29,106)		—		—		—		(29,106)
Equity issuances under various plans (5)	1,023,609	498		85,353		—		—		—		—		85,851
Share-based compensation and tax benefit (3) (4)	34,456	17		3,876		—		—		—		—		3,893
Treasury stock activities (2)	—	—		—		—		—		1,136		(1,136)		—
Cumulative effect of the adoption of ASU 2016-13	—	—		—		(30)		—		—		—		(30)
Balances 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	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)		—
Balances at December 31, 2021	17,655,410	$	8,593	$	371,162	$	393,072	$	1,303	$	7,240	$	(7,240)	$	774,130

(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 116,238, 105,087 and 95,329 shares at December 31, 2021, 2020 and 2019, 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 2021, 2020 and 2019, we withheld 14,020, 10,319 and 7,635 shares, respectively, for taxes.

(5) Includes the Retirement Savings Plan, DRIP and ATM equity issuances.

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 59

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 and in Florida; 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; and (d) our subsidiary, based in Florida, that provides CNG, LNG and RNG transportation and pipeline solutions, primarily to utilities and pipelines throughout the eastern United States.

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 changed to conform to current period presentation.

Beginning in the third quarter of 2019, our management began executing a strategy to sell the operating assets of PESCO. In the fourth quarter of 2019, we closed on four separate transactions to sell PESCO's assets and contracts. As a result of these sales, we have fully exited the natural gas marketing business. Accordingly, PESCO’s historical financial results are reflected in our consolidated financial statements as discontinued operations, which required retrospective application to financial information for all periods presented. Refer to Note 4, Acquisitions for further information.

Effects of COVID-19

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 into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place.

Throughout 2021, restrictions continued to be lifted as vaccines have become widely available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. The expiration of the states of emergency in our service territories, along with the settlement of our limited proceeding in Florida, has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process.

We have been closely following the legal process related to the Occupational Safety and Health Administration (OSHA) Emergency Temporary Standard (ETS) mandating that all employers, with 100 or more employees, require COVID-19 vaccinations or weekly testing, which made its way to the United States Supreme Court. While OSHA has withdrawn the ETS as a temporary standard following the Supreme Court’s ruling, we will continue to monitor its status as a proposed rule, and any developments in the various appeals of the various district court orders enjoining the enforcement of the Executive Order regarding the federal contractor vaccine mandate. In light of the continued emergence and growing prevalence of the new variants of COVID-19, such as the Omicron variant, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, and stockholders and take all precautions warranted to operate safely and to comply with the CDC and OSHA standards, in order to protect our employees, customers and the communities we serve. Refer to Note 19, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses associated with COVID-19.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 60

Notes to the Consolidated Financial Statements

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the consolidated financial statements in conformity 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 betterments 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 for continuing operations by classification as of December 31, 2021 and 2020 is provided in the following table:

	As of December 31,
(in thousands)	2021		2020
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	859,627	$	782,329
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	727,277		667,538
Electric distribution	133,383		127,710
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	176,095		151,258
Natural gas transmission and supply – Ohio	112,050		87,962
Electricity and steam generation	36,740		36,521
Mobile CNG and pipeline solutions	32,374		24,905
Other	35,418		30,769
Total property, plant and equipment	2,112,964		1,908,992
Less: Accumulated depreciation and amortization	(417,479)		(368,743)
Plus: Construction work in progress	49,393		60,929
Net property, plant and equipment	$	1,744,878	$	1,601,178

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, 2021 and 2020, the non-refundable contributions totaled $6.3 million and $3.7 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 ratemaking purposes when the completed projects are placed in service. During the years ended December 31, 2021, 2020 and 2019 AFUDC totaled $0.4 million, $0.7 million and $0.7 million, respectively, which was reflected as a reduction of interest charges.

Leases

Chesapeake Utilities Corporation 2021 Form 10-K Page 61

Notes to the Consolidated Financial Statements

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 15, Leases, for additional information.

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $27.6 million of assets at December 31, 2021, which consist 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. The pipeline was placed in-service during the second quarter of 2020. Peninsula Pipeline's share of direct expenses for the jointly-owned pipeline are included in operating expenses of our consolidated statements of income. Accumulated depreciation for this pipeline totaled $0.9 million at December 31, 2021.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2021 and 2020, which consisted of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, previously jointly owned with Peoples Gas. Effective October 2020, the parties agreed to terminate the pre-existing ownership and capacity agreement and rescind their ownership interests in exchange for defined sections of the pipeline. This resulted in Peninsula Pipeline taking a 100% ownership in the northern end of the pipeline. Accumulated depreciation for this pipeline totaled $1.8 million and $1.7 million at December 31, 2021 and 2020, respectively.

Impairment of Long-lived Assets

We periodically evaluate whether events or circumstances have occurred, which indicate that other 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. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2021, 2020 and 2019:

	2021	2020	2019
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.5%	2.6%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.6%
Natural gas transmission – Florida	2.3%	2.3%	2.4%
Electric distribution	2.8%	2.9%	3.4%

Chesapeake Utilities Corporation 2021 Form 10-K     Page 62

Notes to the Consolidated Financial Statements

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

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

We report certain depreciation and accretion in operations expense, rather than as a 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 expense 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, 2021, 2020 and 2019, we reported $10.2 million, $9.6 million and $8.8 million, respectively, of depreciation and accretion in operations expenses.

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 the 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, Regulated Operations, 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, except for two utilities that provide only unbundled delivery service (Chesapeake Utilities' Central Florida Gas division and FPU's Indiantown division). These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost

Chesapeake Utilities Corporation 2021 Form 10-K Page 63

Notes to the Consolidated Financial Statements

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 delivery 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.

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 pandemics and 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 resulted in 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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 64

Notes to the Consolidated Financial Statements

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. 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.

During the first quarter of 2020, COVID-19 began to rapidly spread within the United States. Federal, state and local governments throughout the country imposed restrictions to promote social distancing to slow the spread of the virus, which has also had the effect of limiting commercial activity. These measures resulted in significant job losses and a slowing of economic activity across the United States and in the areas that we serve. We have considered the impact of COVID-19 on our receivables for the twelve months ended December 31, 2021, monitored developments that impact our customers’ ability to pay and have revised our estimates of expected credit losses to reflect these impacts.

(in thousands)
Balance at December 31, 2020	$	4,785
Additions:
Provision for credit losses	134
Recoveries	(125)
Deductions:
Write offs	(1,653)
Balance at December 31, 2021	$	3,141

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 was no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2021, 2020 or 2019.

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 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 implied fair value. The testing of goodwill for the years ended December 31, 2021, 2020 and 2019 indicated no goodwill impairment. 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.

Chesapeake Utilities Corporation 2021 Form 10-K Page 65

Notes to the Consolidated Financial Statements

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 Prudential 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 assets.

We estimate the health care cost trend rates used in determining our postretirement net 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 recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 66

Notes to the Consolidated Financial Statements

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 sales” treatment under ASC Topic 815 Derivatives and Hedging, 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

There are no new accounting pronouncements issued that are applicable to us.

Chesapeake Utilities Corporation 2021 Form 10-K Page 67

Notes to the Consolidated Financial Statements

3. EARNINGS PER SHARE

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

	For the Year Ended December 31,
	2021		2020		2019
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	83,467	$	70,642	$	61,100
Income/(Loss) from Discontinued Operations	(1)		856		4,053
Net Income	$	83,466	$	71,498	$	65,153
Weighted average shares outstanding	17,558,078		16,711,579		16,398,443
Earnings Per Share from Continuing Operations	$	4.75	$	4.23	$	3.73
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Basic Earnings Per Share	$	4.75	$	4.28	$	3.97
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	17,558,078		16,711,579		16,398,443
Effect of dilutive securities — Share-based compensation	74,951		59,156		50,043
Adjusted denominator — Diluted	17,633,029		16,770,735		16,448,486
Earnings Per Share from Continuing Operations	$	4.73	$	4.21	$	3.72
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Diluted Earnings Per Share	$	4.73	$	4.26	$	3.96

4. ACQUISITIONS

Acquisition of Diversified Energy

On December 15, 2021, Sharp acquired the propane operating assets of Diversified Energy for approximately $37.5 million, net of cash acquired. In connection with this acquisition, we recorded a $2.1 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. Included with the acquisition, was approximately $1.7 million of working capital from the Seller consisting predominantly of accounts receivable and propane inventory. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2021. There are multiple strategic benefits to this acquisition including it: (i) expands our propane service territory into North Carolina, South Carolina, Pennsylvania, and Virginia and (ii) includes an established customer base with opportunities for future growth. Through this acquisition, the Company expands its operating footprint into North Carolina and South Carolina and our propane business will add approximately 19,000 residential, commercial and agricultural customers, along with distribution of approximately 10.0 million gallons of propane annually. In connection with this acquisition, we recorded $23.1 million in property plant and equipment, $6.2 million in intangible assets associated with customer relationships and non-compete agreements and $5.9 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. In January 2022, we received a $0.8 million customary post-closing working capital true-up provision related to the working capital valuation at the time of closing.

Acquisition of Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired. Additionally, the purchase price included $0.3 million of working capital. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2020. There are multiple strategic

Chesapeake Utilities Corporation 2021 Form 10-K     Page 68

Notes to the Consolidated Financial Statements

benefits to this acquisition including: (i) expansion of our propane service territory in Florida and (ii) establishment of a customer base with additional opportunities for future growth.

In connection with this acquisition, we recorded $3.5 million in property plant and equipment, $1.4 million in intangible assets associated with customer relationships and non-compete agreements and $1.8 million in goodwill, all of which is deductible for income tax purposes.

Acquisition of Elkton Gas

In July 2020, we closed on the acquisition on of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland for approximately $15.6 million, net of cash acquired. Additionally, the purchase price included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland.

In connection with this acquisition, we recorded $15.9 million in property, plant and equipment, $0.6 million in accounts receivable, $2.6 million in other liabilities, $2.6 million in regulatory liabilities and $4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. Upon reaching the end of the acquisition measurement period, we recognized offsetting adjustments to the acquisition date fair values of several of the assets acquired and liabilities assumed. These adjustments did not materially impact our previously recognized amount of goodwill.

These acquisitions generated the following operating revenues and income:

	For the Year Ended				For the Year Ended
	December 31, 2021				December 31, 2020
	Operating Revenues		Operating Income		Operating Revenues		Operating Income
(in thousands)
Diversified Energy	$	1,423	$	300	$	—	$	—
Western Natural Gas	$	2,594	$	550	$	555	$	120
Elkton Gas	$	7,105	$	1,000	$	2,399	$	418

5. REVENUE RECOGNITION

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays revenue from continuing operations by major source based on product and service type for the years ended December 31, 2021, 2020 and 2019:

Chesapeake Utilities Corporation 2021 Form 10-K Page 69

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 division	34,074		—		—		34,074
FPU electric distribution	78,300		—		—		78,300
FPU natural gas distribution	100,535		—		—		100,535
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 delivery operations	—		142,082		—		142,082
Energy delivery 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 (1)	$	383,920	$	206,869	$	(20,821)	$	569,968

    

(1) 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 70

Notes to the Consolidated Financial Statements

	For the year ended December 31, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	63,389	$	—	$	—	$	63,389
Florida natural gas division	30,850		—		—		30,850
FPU electric distribution	76,863		—		—		76,863
FPU natural gas distribution	90,150		—		—		90,150
Maryland natural gas division	21,853		—		—		21,853
Sandpiper natural gas/propane operations	17,214		—		—		17,214
Elkton Gas	2,399		—		—		2,399
Total energy distribution	302,718		—		—		302,718
Energy transmission
Aspire Energy	—		27,951		—		27,951
Aspire Energy Express	16		—		—		16
Eastern Shore	75,117		—		—		75,117
Peninsula Pipeline	23,080		—		—		23,080
Total energy transmission	98,213		27,951		—		126,164
Energy generation
Eight Flags	—		16,147		—		16,147
Propane operations
Propane delivery operations	—		100,744		—		100,744
Energy delivery services
Marlin Gas Services	—		7,818		—		7,818
Other and eliminations
Eliminations	(48,185)		(134)		(17,602)		(65,921)
Other	—		—		528		528
Total other and eliminations	(48,185)		(134)		(17,074)		(65,393)
Total operating revenues (1)	$	352,746	$	152,526	$	(17,074)	$	488,198

(1) Total operating revenues for the year ended December 31, 2020, include other revenue (revenues from sources other than contracts with customers of $1.4 million and $0.2 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 2021 Form 10-K Page 71

Notes to the Consolidated Financial Statements

	For the years ended December 31, 2019
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	62,659	$	—	$	—	$	62,659
Florida natural gas division	28,485		—		—		28,485
FPU electric distribution	77,416		—		—		77,416
FPU natural gas distribution	82,418		—		—		82,418
Maryland natural gas division	22,517		—		—		22,517
Sandpiper natural gas/propane operations	19,068		—		—		19,068
Total energy distribution	292,563		—		—		292,563
Energy transmission
Aspire Energy	—		32,493		—		32,493
Aspire Energy Express	—		—		—		—
Eastern Shore	72,924		—		—		72,924
Peninsula Pipeline	16,453		—		—		16,453
Total energy transmission	89,377		32,493		—		121,870
Energy generation
Eight Flags	—		16,749		—		16,749
Propane operations
Propane delivery operations	—		109,614		—		109,614
Energy delivery services
Marlin Gas Services	—		5,702		—		5,702
Other and eliminations
Eliminations	(38,934)		(10,407)		(18,081)		(67,422)
Other	—		—		529		529
Total other and eliminations	(38,934)		(10,407)		(17,552)		(66,893)
Total operating revenues (1)	$	343,006	$	154,151	$	(17,552)	$	479,605

(1) Total operating revenues for the year ended December 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 72

Notes to the Consolidated Financial Statements

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 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 delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane 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.

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 2021 Form 10-K Page 73

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, 2021 and 2020 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	4,816	$	644
Balance at 12/31/2021	56,277		4,806		747
Increase (decrease)	$	677	$	(10)	$	103

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 Mid-Atlantic propane delivery 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, 2021 and 2020, we recognized revenue of $1.1 million and $1.3 million, respectively.

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, 2021 are expected to be recognized as follows:

(in thousands)	2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	33,925	$	26,334	$	24,103	$	23,231	$	21,964	$	179,866
Natural gas distribution operations	6,747		6,174		5,946		5,410		5,179		33,543
FPU electric distribution	652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	41,324	$	33,160	$	30,701	$	28,916	$	27,418	$	213,959

Practical expedients

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.

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) 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 74

Notes to the Consolidated Financial Statements

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions operations. 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 table presents information about our reportable segments.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	381,879	$	350,853	$	340,857
Unregulated Energy	188,089		137,345		138,748
Total operating revenues, unaffiliated customers	$	569,968	$	488,198	$	479,605
Intersegment Revenues (1)
Regulated Energy	$	2,041	$	1,893	$	2,149
Unregulated Energy	18,780		15,181		15,403
Other businesses	527		528		529
Total intersegment revenues	$	21,348	$	17,602	$	18,081
Operating Income (Loss)
Regulated Energy	$	106,064	$	92,124	$	86,584
Unregulated Energy	24,382		20,664		19,938
Other businesses and eliminations	666		(65)		(237)
Operating Income	131,112		112,723		106,285
Other income (expense), net	1,721		3,222		(1,847)
Interest charges	20,135		21,765		22,224
Income from Continuing Operations before Income Taxes	112,698		94,180		82,214
Income Taxes on Continuing Operations	29,231		23,538		21,114
Income from Continuing Operations	83,467		70,642		61,100
Income (loss) from Discontinued Operations, Net of Tax	(1)		686		(1,349)
Gain on sale of Discontinued Operations, Net of tax	—		170		5,402
Net Income	$	83,466	$	71,498	$	65,153
Depreciation and Amortization
Regulated Energy	$	48,748	$	46,079	$	35,227
Unregulated Energy	13,869		11,988		10,130
Other businesses and eliminations	44		50		67
Total depreciation and amortization	$	62,661	$	58,117	$	45,424
Capital Expenditures
Regulated Energy	$	139,733	147,100		$	130,604
Unregulated Energy	81,651		46,295		60,034
Other businesses	6,425		2,480		8,348
Total capital expenditures	$	227,809	$	195,875	$	198,986

     

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

Chesapeake Utilities Corporation 2021 Form 10-K Page 75

Notes to the Consolidated Financial Statements

	As of December 31,
	2021		2020
Identifiable Assets
Regulated Energy segment	$	1,629,191	$	1,547,619
Unregulated Energy segment	439,114		347,665
Other businesses and eliminations	46,564		37,203
Total identifiable assets	$	2,114,869	$	1,932,487

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2021, 2020 and 2019 were as follows:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Cash paid for interest	$	20,809	$	22,884	$	23,856
Cash (received) paid for income taxes, net of refunds	$	8,395	$	(8,135)	$	3,221

Non-cash investing and financing activities during the years ended December 31, 2021, 2020, and 2019 were as follows: 

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	16,164	$	23,625	$	13,470
Common stock issued for the Retirement Savings Plan	$	1,712	$	1,605	$	—
Common stock issued under the SICP	$	2,834	$	1,971	$	1,691

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, 2021 and 2020, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of December 31, 2021, 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	21.2	Cash flow hedges	June, 2024
Sharp	Propane (gallons)	Sales	4.4	Cash flow hedges	December, 2022
Sharp	Propane (gallons)	Purchases	0.3	N/A	March 2022

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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 76

Notes to the Consolidated Financial Statements

agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2021 through June 2024) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. If the index prices are lower than the contract prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $3.6 million of unrealized gain from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2022.

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 the second quarter of 2020, we entered into interest rate swaps with notional amounts totaling $100.0 million associated with three of our short-term lines of credit which expired in October 2020. The interest rate swaps were entered to hedge the variability in cash flows attributable to changes in the short-term borrowing rates during this period. Pricing on the interest rate swaps ranged between 0.2615 and 0.3875 percent for the period. In the fourth quarter of 2020, we entered into additional interest rate swaps with notional amount of $60.0 million through December 2021 with pricing of 0.20 percent and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest swap was cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate. At December 31, 2021 all of our interest rate swaps had expired and we have not entered into any new derivative contracts associated with our outstanding short-term borrowings.

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, the balance related to the account is as follows:

(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,081	$	1,505

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, 2021 and 2020 are as follows:

Chesapeake Utilities Corporation 2021 Form 10-K Page 77

Notes to the Consolidated Financial Statements

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	16	$	—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	—		14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	7,060		3,255
Total Derivative Assets		$	7,076	$	3,269

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	743		64
Interest rate swap agreements	Derivative liabilities, at fair value	—		40
Total Derivative Liabilities		$	743	$	127

 The effects of gains and losses from derivative instruments are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2021		2020		2019
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	(1)	$	—	$	—
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	(24)		(12)		—
Put/Call option	Propane inventory	—		34		—
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	(536)		—		—
Propane swap agreements	Propane and natural gas costs	7,187		2,428		1,520
Propane swap agreements	Other comprehensive income (loss)	3,126		5,035		(253)
Interest rate swap agreements	Interest expense	(28)		60		—
Interest rate swap agreements	Other comprehensive income (loss)	—		(40)		—
Natural gas swap contracts	Other comprehensive income (loss)	—		—		(63)
Natural gas futures contracts	Other comprehensive income (loss)	—		—		(294)
Total		$	9,724	$	7,505	$	910

Chesapeake Utilities Corporation 2021 Form 10-K     Page 78

Notes to the Consolidated Financial Statements

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 the following:

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

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2021 and 2020, respectively:

			Fair Value Measurements Using:
As of December 31, 2021	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	$	26	$	26	$	—	$	—
Investments—guaranteed income fund	2,036		—		—		2,036
Investments—mutual funds and other	10,033		10,033		—		—
Total investments	12,095		10,059		—		2,036
Derivative assets	7,076		—		7,076		—
Total assets	$	19,171	$	10,059	$	7,076	$	2,036
Liabilities:
Derivative liabilities	$	743	$	—	$	743	$	—

Chesapeake Utilities Corporation 2021 Form 10-K Page 79

Notes to the Consolidated Financial Statements

			Fair Value Measurements Using:
As of December 31, 2020	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	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

	For the Year Ended December 31,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	88		261
Transfers/disbursements	(241)		1,065
Investment income	33		27
Ending Balance	$	2,036	$	2,156

Investment income from the Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

At December 31, 2021 and 2020, 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 and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its near-term maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2021, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $568.8 million, compared to the estimated fair value of $597.2 million. At December 31, 2020, long-term debt, which includes the current maturities and debt issuance costs, had a carrying value of $523.0 million, compared to a fair value of $548.5 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 3 measurement.

See Note 17, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 80

Notes to the Consolidated Financial Statements

10. INVESTMENTS

 The investment balances at December 31, 2021 and 2020, consisted of the following:

	As of December 31,
(in thousands)	2021		2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	12,069	$	10,755
Investments in equity securities	26		21
Total	$	12,095	$	10,776

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2021, 2020 and 2019, we recorded net unrealized gains of $1.5 million, $1.5 million, and $1.6 million, respectively in other income (expense), net in the consolidated statements of income related to these investments. For the investments in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

11. GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill from continuing operations as of December 31, 2021 and 2020 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731
Additions (1)	72		5,905		5,977
Balance at December 31, 2021	$	7,689	$	37,019	$	44,708

(1)Includes goodwill from the purchase of operating assets of Diversified Energy in December 2021 and Elkton Gas in the third quarter of 2020.

The annual impairment testing for the years 2021 and 2020 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2021 and 2020 are as follows:

	As of December 31,
	2021				2020
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	16,814	$	5,125	$	10,680	$	4,269
Non-Compete agreements (1)	2,431		1,078		2,375		768
Patents	452		354		452		236
Other	270		218		270		212
Total	$	19,967	$	6,775	$	13,777	$	5,485

(1) The customer relationship and non-compete agreements amounts include $6.1 million and less than $0.1 million, respectively, as a result of the purchase of the operating assets of Diversified Energy in December 2021 and $1.3 million and $0.1 million, respectively, recorded as a result of the purchase of the operating assets of Western Natural Gas in October 2020.

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 12 years. Amortization expense of intangible assets for the year ended December 31, 2021, 2020 and 2019 was $1.3 million, $1.2 million and $0.8 million, respectively. Amortization expense of intangible assets is expected to be $1.4 million for the year 2022, $1.3 million for the years 2023 through 2025, and $1.1 million for 2026.

12. 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

Chesapeake Utilities Corporation 2021 Form 10-K Page 81

Notes to the Consolidated Financial Statements

operations and/or are required to file. Our state returns for tax years after 2015 are subject to examination. At December 31, 2021, the 2015 through 2019 federal income tax returns are under examination, and no report has been issued at this time.

We expect to have federal NOLs totaling $6.3 million and $12.2 million in 2019 and 2018 respectively upon the settlement of the Internal Revenue Service examination described above. Under the CARES Act, discussed below, we elected to carry the losses back to 2015 and 2013. For state income tax purposes, we had NOLs in various states of $14.6 million and $40.0 million as of December 31, 2021 and 2020, respectively, almost all of which will expire in 2039. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.5 million and $1.6 million related to state NOL carry-forwards at December 31, 2021 and 2020, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOLs 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. Our income tax expense for the years ended December 31, 2021 and 2020 included a tax benefit of $0.9 million and $1.8 million, respectively, 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.

On December 22, 2017, President Trump signed into law the TCJA. 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 and thereafter 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 19, 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 2021, 2020, and 2019; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2021, 2020, and 2019 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2021 and 2020.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Current Income Tax Expense
Federal	$	2,775	$	(2,777)	$	(2,252)
State	(96)		2,162		(491)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	2,632		(662)		(2,790)
Deferred Income Tax Expense (1)
Property, plant and equipment	24,074		23,224		25,907
Deferred gas costs	1,857		(714)		79
Pensions and other employee benefits	(655)		(75)		(454)
FPU merger-related premium cost and deferred gain	(351)		156		(278)
Net operating loss carryforwards	97		5,107		(3,772)
Other	1,577		(3,498)		2,422
Total deferred income tax expense	26,599		24,200		23,904
Income Tax Expense from Continuing Operations	29,231		23,538		21,114
Income Tax Expense from Discontinued Operations	—		153		1,416
Total Income Tax	$	29,231	$	23,691	$	22,530

Chesapeake Utilities Corporation 2021 Form 10-K     Page 82

Notes to the Consolidated Financial Statements

(1) Includes $8.2 million, $4.9 million, and $4.7 million of deferred state income taxes for the years 2021, 2020 and 2019, respectively.

	For the Year Ended December 31,
	2021			2020			2019
(in thousands)
Reconciliation of Effective Income Tax Rates from Continuing Operations
Federal income tax expense (1)	$	23,666		$	19,778		$	17,264
State income taxes, net of federal benefit	6,371			5,051			5,093
ESOP dividend deduction	(180)			(218)			(173)
CARES Act Tax Benefit	(919)			(1,841)			—
Depreciation	(15)			—			—
Other	308			768			(1,070)
Total Income Tax Expense from Continuing Operations	$	29,231		$	23,538		$	21,114
Effective Income Tax Rate from Continuing Operations	25.94		%	24.99		%	25.65		%

(1) Federal income taxes were calculated at 21 percent for 2021, 2020, and 2019.

	As of December 31,
	2021		2020
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	224,034	$	199,287
Acquisition adjustment	6,266		6,618
Loss on reacquired debt	183		201
Deferred gas costs	2,366		509
Natural gas conversion costs	5,529		5,379
Storm reserve liability	5,783		7,073
Other	6,301		5,587
Total deferred income tax liabilities	250,462		224,654
Deferred income tax assets:
Pension and other employee benefits	5,354		4,636
Environmental costs	996		1,064
Net operating loss carryforwards	1,490		1,587
Storm reserve liability	448		409
Accrued expenses	4,843		6,153
Other	3,781		5,417
Total deferred income tax assets	16,912		19,266
Deferred Income Taxes Per Consolidated Balance Sheets	$	233,550	$	205,388

Chesapeake Utilities Corporation 2021 Form 10-K Page 83

Notes to the Consolidated Financial Statements

13. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2021		2020
Uncollateralized Senior Notes:
5.93% note, due October 31, 2023	$	6,000	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	14,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
2.49% notes Due January 25, 2037	50,000		—
Equipment security note
2.46% note, due September 24, 2031	9,378		—
Less: debt issuance costs	(913)		(901)
Total long-term debt	567,865		522,099
Less: current maturities	(17,962)		(13,600)
Total long-term debt, net of current maturities	$	549,903	$	508,499

Notes Purchase Agreement

On December 16, 2021, we agreed to issue and MetLife agreed to purchase 2.95 percent Senior Notes due March 15, 2042 in the aggregate principal amount of $50 million. We expect to issue the Notes on or before March 15, 2022. The Company anticipates using the proceeds received from the issuances of the Notes to reduce short-term borrowings under the Company’s revolving credit facility and/or to fund capital expenditures. These Senior Notes, when issued, will have similar covenants and default provisions as the existing senior notes, and will have an annual principal payment beginning in the eleventh year after the issuance.

Equipment Security Note

On September 24, 2021, we entered into an Equipment Financing Agreement with Banc of America Leasing & Capital, LLC to issue $9.6 million in sustainable financing associated with the purchase of qualifying equipment by our subsidiary, Marlin Gas Services. The equipment security note bears a 2.46 percent interest rate and has a term of 10 years. Under the terms of the agreement, we granted a security interest in the equipment to the lender, to serve as collateral.

Annual maturities

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

Year	2022		2023		2024		2025		2026		Thereafter		Total
(in thousands)
Payments	$	17,962	$	21,483	$	18,505	$	25,528	$	34,551	$	450,749	$	568,778

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. The following table summarizes our shelf agreements at December 31, 2021:

Chesapeake Utilities Corporation 2021 Form 10-K     Page 84

Notes to the Consolidated Financial Statements

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		(50,000)		100,000
Total	$	520,000	$	(220,000)	$	(50,000)	$	250,000

(1) The Prudential and MetLife Shelf Agreements expire in April 2023 and May 2023, respectively.

(2) Unfunded commitments of $50 million reflects Senior Notes expected to be issued on or before March 15, 2022..

The Senior Notes, Shelf Agreements or Shelf 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.

Uncollateralized Senior Notes

All of our Uncollateralized Senior Notes require periodic principal and interest payments as specified in each note. They also contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40.0 percent of total capitalization (including short-term borrowings), and the fixed charge coverage ratio must be at least 1.2 times. The most recent Senior Notes issued since September 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50.0 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain Uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2021, the cumulative consolidated net income base was $664.5 million, offset by restricted payments of $289.4 million, leaving $375.1 million of cumulative net income free of restrictions. As of December 31, 2021, we were in compliance with all of our debt covenants.

14. SHORT-TERM BORROWINGS

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At December 31, 2021 and 2020, we had $221.6 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 0.83 percent and 1.28 percent, respectively.

In August 2021, we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the facility consist of a $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three one-year extension options, which can be authorized by our Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the facility and to the extent that an individual loan under the Revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2021, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026. Both tranches are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon a total indebtedness to total capitalization ratio. As of December 31, 2021, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of December 31, 2021, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

Chesapeake Utilities Corporation 2021 Form 10-K Page 85

Notes to the Consolidated Financial Statements

Our total available credit under the Revolver at December 31, 2021 was $173.1 million. As of December 31, 2021, we had issued $5.3 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

In the fourth quarter of 2020, we entered into two $30.0 million interest rate swaps with a total notional amount of $60.0 million through December 2021 with pricing of 0.20 percent and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. At December 31, 2021, all of our interest rate swaps had expired and we have not entered into any new derivative contracts associated with our outstanding short-term borrowings.

15. 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 all 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. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. 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, 2021, 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 which preclude our ability to pay dividends, obtain financing or enter into additional leases. As of December 31, 2021, 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	2021		2020
Operating lease cost (1)	Operations expense	$	2,064	$	2,029

(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 sheet at December 31, 2021 and 2020:

(in thousands)	Balance sheet classification	December 31, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,139	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,996	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,571		9,872
Total lease liabilities		$	10,567	$	11,619

Chesapeake Utilities Corporation 2021 Form 10-K     Page 86

Notes to the Consolidated Financial Statements

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2021 and 2020:

	December 31, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.10		8.70
Weighted-average discount rate
Operating leases	3.6	%	3.8	%

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, 2021 and 2020:

	Year Ended December 31,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	1,996	$	1,956

The following table presents the future undiscounted maturities of our operating leases at December 31, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2022	$	2,019
2023	1,902
2024	1,672
2025	1,341
2026	885
Thereafter	3,668
Total lease payments	11,487
Less: Interest	(920)
Present value of lease liabilities	$	10,567

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

16. STOCKHOLDERS' EQUITY

Common Stock Issuances

In June 2020, we filed a shelf registration statement with the SEC to facilitate the issuance of our common stock. In August 2020, we filed a prospectus supplement under the shelf registration statement for an ATM equity program under which we may issue and sell shares of our common stock up to an aggregate offering price of $75.0 million. In the third and fourth quarters of 2020, we issued 0.7 million shares of common stock at an average price per share of $82.93 and received net proceeds of approximately $61.0 million, after deducting commissions and other fees of $1.5 million.

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. 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. In 2021, we issued just over 0.1 million shares at an average price per share of $125.71 and received net proceeds of $15.2 million under the DRIP. In the third and fourth quarters of 2020, we issued 0.3 million shares at an average price per share of $86.12 and received net proceeds of $22.0 million under the DRIP.

We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, 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)

Chesapeake Utilities Corporation 2021 Form 10-K Page 87

Notes to the Consolidated Financial Statements

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements and natural gas swaps and futures contracts, designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements, designated as cash flow hedges, are the components of our accumulated other comprehensive loss. The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the years ended December 31, 2021 and 2020. 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, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income (loss) before reclassifications	(578)		5,400		16		4,838
Amounts reclassified from accumulated other comprehensive income (loss)	365		(1,757)		(44)		(1,436)
Net current-period other comprehensive income (loss)	(213)		3,643		(28)		3,402
As of December 31, 2020	(5,146)		2,309		(28)		(2,865)
Other comprehensive income before reclassifications	262		7,075		—		7,337
Amounts reclassified from accumulated other comprehensive income (loss)	1,616		(4,813)		28		(3,169)
Net current-period other comprehensive income	1,878		2,262		28		4,168
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2021, 2020 and 2019. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	For the Year Ended December 31,
(in thousands)	2021		2020		2019
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(2,243)		(592)		(2,600)
Total before income taxes	(2,166)		(515)		(2,523)
Income tax benefit (4)	550		150		656
Net of tax	$	(1,616)	$	(365)	$	(1,867)
Gains on commodity contracts cash flow hedges
Propane swap agreements (2)	$	6,651	$	2,428	$	1,520
Natural gas swaps (2)(3)	—		—		7
Natural gas futures (2)(3)	—		—		2,096
Total before income taxes	6,651		2,428		3,623
Income tax expense (4)	(1,838)		(671)		(1,028)
Net of tax	$	4,813	$	1,757	$	2,595
Gains and (losses) on interest rate swap cash flow hedges:
Interest rate swap agreements	$	(28)	$	60	$	—
Total before income taxes	(28)		60		—
Income tax expense (4)	—		(16)		—
Net of tax	$	(28)	$	44	$	—
Total reclassifications for the period	$	3,169	$	1,436	$	728

Chesapeake Utilities Corporation 2021 Form 10-K     Page 88

Notes to the Consolidated Financial Statements

(1) These amounts are included in the computation of net periodic benefits. See Note 17, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details.

(3) PESCO's results are reflected as discontinued operations in our consolidated statements of income.

(4) The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

17. 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. We record as a component of other comprehensive income/loss or a regulatory asset the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs.

Defined Benefit Pension Plans

At December 31, 2021 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake SERP.

During the fourth quarter of 2021, we formally terminated the Chesapeake Pension Plan. Accordingly, a portion of the pension settlement expense associated with the termination was allocated to our Regulated Energy operations and was recorded as regulatory assets, previously approved in all of the impacted jurisdictions. The remaining portion of the pension settlement expense totaling $0.6 million was recorded in other expense in our consolidated statement of income which reflected the amount allocated to our Unregulated Energy operations or was deemed not recoverable through the regulatory process.

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 additional 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. Benefits under the Chesapeake SERP for the first sub-plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake SERP was frozen were credited with two additional years of service. 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 three plans at both December 31, 2021 and 2020, is included in the other pension and benefit costs liability in our consolidated balance sheets.

Chesapeake Utilities Corporation 2021 Form 10-K Page 89

Notes to the Consolidated Financial Statements

The following schedules set forth the funded status at December 31, 2021 and 2020 and the net periodic cost for the years ended December 31, 2021, 2020 and 2019 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2021			2020			2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,146		$	6,214		$	70,366		$	65,304		$	2,212		$	2,157
Interest cost	141			176			1,714			2,085			48			63
Actuarial (gain) loss	(371)			450			(1,953)			6,069			(12)			144
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Benefit obligation — end of year	—			6,146			67,030			70,366			2,096			2,212
Change in plan assets:
Fair value of plan assets — beginning of year	4,609			4,630			55,966			49,703			—			—
Actual return on plan assets	(237)			369			4,246			6,581			—			—
Employer contributions	1,544			304			1,597			2,774			152			152
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Fair value of plan assets — end of year	—			4,609			58,712			55,966			—			—
Reconciliation:
Funded status	—			(1,537)			(8,318)			(14,400)			(2,096)			(2,212)
Accrued pension cost	$	—		$	(1,537)		$	(8,318)		$	(14,400)		$	(2,096)		$	(2,212)
Assumptions:
Discount rate	2.50		%	2.25		%	2.75		%	2.50		%	2.50		%	2.25		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	—		%	—		%

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2021(2)			2020			2019(1)			2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic pension cost:
Interest cost	$	141		$	176		$	375		$	1,714		$	2,085		$	2,452		$	48		$	63		$	74
Expected return on assets	(166)			(157)			(487)			(3,306)			(2,967)			(2,770)			—			—			—
Amortization of actuarial loss	257			243			391			612			552			505			28			20			85
Settlement expense	1,810			203			1,982			—			—			—			—			—			58
Net periodic pension cost	2,042			465			2,261			(980)			(330)			187			76			83			217
Amortization of pre-merger regulatory asset	—			—			—			—			—			543			—			—			—
Total periodic cost	$	2,042		$	465		$	2,261		$	(980)		$	(330)		$	730		$	76		$	83		$	217
Assumptions:
Discount rate	2.25		%	3.00		%	3.00		%	2.50		%	3.25		%	4.25		%	2.25		%	3.00		%	4.00		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	—		%	—		%	—		%

(1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

(2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 90

Notes to the Consolidated Financial Statements

Included in the net periodic costs for the FPU Pension Plan for the year ended December 31, 2019 is amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU's regulated operations for the changes in funded status that occurred, but were not recognized as part of net periodic cost, prior to the merger with Chesapeake Utilities in October 2009. This was previously deferred as a regulatory asset to be recovered through rates pursuant to an order by the Florida PSC. As of December 31, 2019, this regulatory asset was fully amortized. Excluding the service cost component, the other components of the net periodic costs have been recorded or reclassified to other expense, net of tax, in the consolidated statements of income.

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. At December 31, 2021, there are no remaining assets in the Chesapeake Pension Plan. The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2021, 2020 and 2019:

	FPU Pension Plan
At December 31,	2021		2020		2019
Asset Category
Equity securities	52	%	54	%	53	%
Debt securities	38	%	37	%	37	%
Other	10	%	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 plans. 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 (this allocation range applied to the Chesapeake Pension Plan prior to the de-risking strategy executed during the fourth quarter of 2019):

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	4	%	10	%
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, 2021 and 2020, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:

Chesapeake Utilities Corporation 2021 Form 10-K Page 91

Notes to the Consolidated Financial Statements

	Fair Value Measurement Hierarchy
	At December 31, 2021								At December 31, 2020
Asset Category	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	4,302	$	—	$	—	$	4,302	$	3,615	$	—	$	—	$	3,615
U.S. Mid Cap (1)	1,835		—		—		1,835		1,672		—		—		1,672
U.S. Small Cap (1)	954		—		—		954		891		—		—		891
International (2)	10,863		—		—		10,863		11,307		—		—		11,307
Alternative Strategies (3)	5,888		—		—		5,888		5,586		—		—		5,586
	23,842		—		—		23,842		23,071		—		—		23,071
Mutual Funds - Debt securities
Fixed income (4)	19,551		—		—		19,551		21,563		—		—		21,563
High Yield (4)	3,014		—		—		3,014		2,606		—		—		2,606
	22,565		—		—		22,565		24,169		—		—		24,169
Mutual Funds - Other
Commodities (5)	2,297		—		—		2,297		2,246		—		—		2,246
Real Estate (6)	2,729		—		—		2,729		1,954		—		—		1,954
Guaranteed deposit (7)	—		—		497		497		—		—		1,019		1,019
	5,026		—		497		5,523		4,200		—		1,019		5,219
Total Pension Plan Assets in fair value hierarchy	$	51,433	$	—	$	497	51,930		$	51,440	$	—	$	1,019	52,459
Investments measured at net asset value (8)							6,782								8,116
Total Pension Plan Assets							$	58,712							$	60,575

(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) 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, 2021 and 2020, our pension plans 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 following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

Chesapeake Utilities Corporation 2021 Form 10-K     Page 92

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
	2021		2020
(in thousands)
Balance, beginning of year	$	1,019	$	1,147
Purchases	3,160		3,190
Transfers in	5,914		921
Disbursements	(9,587)		(4,290)
Investment income	(9)		51
Balance, end of year	$	497	$	1,019

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. The following table sets forth the funded status at December 31, 2021 and 2020:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,033		$	1,100		$	1,009		$	1,224
Interest cost	22			26			24			30
Plan participants contributions	190			166			29			37
Actuarial loss (gain)	159			(34)			71			(181)
Benefits paid	(470)			(225)			(129)			(101)
Benefit obligation — end of year	934			1,033			1,004			1,009
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	280			59			100			64
Plan participants contributions	190			166			29			37
Benefits paid	(470)			(225)			(129)			(101)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(934)			(1,033)			(1,004)			(1,009)
Accrued postretirement cost	$	(934)		$	(1,033)		$	(1,004)		$	(1,009)
Assumptions:
Discount rate	2.83		%	2.25		%	2.51		%	2.50		%

Chesapeake Utilities Corporation 2021 Form 10-K Page 93

Notes to the Consolidated Financial Statements

Net periodic postretirement benefit costs for 2021, 2020, and 2019 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	22		$	26		$	39		$	24		$	30		$	48
Amortization of actuarial loss (gain)	34			24			46			(9)			(19)			—
Amortization of prior service cost	(77)			(77)			(77)			—			—			—
Net periodic cost	(21)			(27)			8			15			11			48
Amortization of pre-merger regulatory asset	—			—			—			—			6			8
Total periodic cost	$	(21)		$	(27)		$	8		$	15		$	17		$	56
Assumptions
Discount rate	2.25		%	3.00		%	4.00		%	2.50		%	3.25		%	4.25		%

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive loss or as a regulatory asset as of December 31, 2021:

(in thousands)	FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service (credit)	$	—	$	—	$	(293)	$	—	$	(293)
Net loss (gain)	17,737		659		671		(114)		18,953
Total	$	17,737	$	659	$	378	$	(114)	$	18,660
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,370	$	659	$	378	$	(22)	$	4,385
Post-merger regulatory asset	14,367		—		—		(92)		14,275
Total unrecognized cost	$	17,737	$	659	$	378	$	(114)	$	18,660

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2021 is net of income tax benefits of $1.1 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations, which is included in the above table as a post-merger regulatory asset. As of December 31, 2021, the pre-merger regulatory asset related to the FPU Pension and FPU Medical Plan was fully amortized.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2021, considering the expected lives of each of the plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Due to the termination of the Chesapeake Pension Plan during the fourth quarter of 2021, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake Utilities' and FPU’s plans. 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 2021 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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 94

Notes to the Consolidated Financial Statements

Estimated Future Benefit Payments

In 2022, we expect to contribute $0.3 million to the FPU Pension Plan and $0.2 million to the Chesapeake SERP. We also expect to contribute less than $0.1 million to both the Chesapeake Postretirement Plan and FPU Medical Plan, in 2022.

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)
2022	$	3,451	$	151	$	73	$	71
2023	$	3,537	$	149	$	68	$	70
2024	$	3,592	$	147	$	63	$	71
2025	$	3,690	$	160	$	59	$	70
2026	$	3,720	$	157	$	54	$	69
Years 2027 through 2031	$	18,588	$	723	$	218	$	324

(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

For the years ended December 31, 2021, 2020 and 2019, we sponsored a 401(k) Retirement Savings Plan. This plan 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 $5.9 million, $5.9 million, and $5.7 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021, 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 our common stock in the same amount that is received by all other stockholders. Such dividends are reinvested into our common stock. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheet, had a fair value of $12.1 million and $10.8 million at December 31, 2021 and 2020, respectively. (See Note 10, Investments, for further details). The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.

Chesapeake Utilities Corporation 2021 Form 10-K Page 95

Notes to the Consolidated Financial Statements

Deferrals of officer base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares, which represent deferred stock units, and directors’ stock retainers are paid in shares of our common stock, 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 $7.2 million and $5.7 million at December 31, 2021 and 2020, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheet.

18. SHARE-BASED COMPENSATION PLANS

Our non-employee directors and key employees 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 369,099 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, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Awards to non-employee directors	$	782	$	733	$	620
Awards to key employees	5,163		4,096		3,659
Total compensation expense	5,945		4,829		4,279
Less: tax benefit	(1,535)		(1,254)		(1,117)
Share-based compensation amounts included in net income	$	4,410	$	3,575	$	3,162

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. In May 2021, after the most recent election of directors, each of our non-employee directors received an annual retainer of 683 shares of common stock under the SICP for service as a director through the 2022 Annual Meeting of Stockholders; accordingly, 6,830 shares, with a weighted average fair value of $117.11 per share, were issued and vested in 2021. At December 31, 2021, 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 2022.

In October 2021, a newly appointed member of the Board of Directors received a pro-rated retainer of 342 shares of common stock under the SICP to serve as a non-employee director through the 2022 Annual Meeting of Stockholders. The shares awarded to the non-employee director immediately vested upon issuance in October 2021, had a weighted average fair value of $129.09 per share, and will be expensed over the remaining service period ending on the date of the 2022 Annual Meeting of Stockholders.

In May 2020, after the most recent election of directors, each of our non-employee directors received an annual retainer of 887 shares of common stock under the SICP for board service through the 2021 Annual Meeting of Stockholders; accordingly, 8,870 shares, with a weighted average fair value of $84.47 per share, were issued and vested in 2020.

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 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 the Monte Carlo valuation to estimate the fair value of each share granted.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 96

Notes to the Consolidated Financial Statements

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, 2019	157,817	$	80.28
Granted	70,014	91.89
Vested	(35,651)	66.48
Expired	(5,302)	65.32
Outstanding — December 31, 2020	186,878	87.06
Granted	69,903	100.76
Vested	(53,147)	76.31
Expired	(852)	74.85
Forfeited (1)	(5,384)	$	93.39
Outstanding — December 31, 2021	197,398	$	94.15

(1) In conjunction with the retirement of one key employee during 2020, these shares were forfeited for the remainder of the service periods associated with awards granted during their employment with the Company.

For the year ended December 31, 2021, we granted awards of 69,903 shares of common stock to officers under the SICP, including awards granted in February 2021 and to key employees appointed in officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which are comprised of market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted.

The intrinsic value of these awards was $28.8 million, $20.2 million and $15.1 million in 2021, 2020 and 2019, respectively. At December 31, 2021, there was $4.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2023.

In 2021, 2020 and 2019, we withheld shares with a value at least equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives electing to receive the net shares. The below table presents the number of shares withheld /and amounts remitted to taxing authorities:

	For the Year Ended December 31,
	2021		2020		2019
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	14,020		10,319		7,635
Amounts remitted to tax authorities to satisfy obligations	$	1,478	$	977	$	692

Chesapeake Utilities Corporation 2021 Form 10-K Page 97

Notes to the Consolidated Financial Statements

19. RATES AND OTHER REGULATORY ACTIVITIES

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

Delaware

See the discussion below under COVID-19 impact.

Maryland

Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement plan with the Maryland PSC. The STRIDE plan accelerates Elkton Gas' Aldyl-A pipeline replacement program as costs of the plan are recovered through a fixed charge rider which is effective for five years. Under Elkton Gas’ STRIDE plan, the Aldyl-A pipelines will be fully replaced by 2023. In July 2021, Elkton Gas reached a settlement with the Maryland PSC Staff and the Maryland Office of Public Counsel that approved Elkton Gas’ STRIDE plan. The STRIDE plan allows for recovery of the associated revenue requirement through a monthly surcharge, which was implemented effective September 2021.

Florida

West Palm Beach Expansion Project: In August 2019, the Florida PSC approved Peninsula Pipeline’s Transportation Service Agreement with FPU. Peninsula Pipeline constructed several new interconnection points and pipeline expansions in Palm Beach County, Florida, which will enable FPU to serve an industrial research park and several new residential developments. Peninsula Pipeline is now providing transportation service to FPU, increasing reliability and system pressure as well as introducing diversity in the fuel source for natural gas to serve the increased demand in these areas. Interim services began in the fourth quarter of 2019, and we completed the remainder of the project in phases through the fourth quarter of 2021.

Winter Haven Expansion Project: In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use the additional firm service to support new incremental load due to growth, including providing service to a new can manufacturing facility, as well as provide reliability and operational benefits to CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. The Transportation Service Agreement was approved by the Florida PSC in September 2021. Construction commenced in February 2021 and the expected in-service date is March 2022.

Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas 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 will construct 11 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021. Construction also commenced in June 2021 and the expected in-service date is December 2022.

Eastern Shore

Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that provides an additional 14,300 Dts/d of firm service to four customers. This includes six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. The project is now fully in service as the construction of the Somerset County, Maryland expansion was completed in the third quarter of 2021.

Capital Cost Surcharge: In June 2021, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge is an approved item in the settlement of Eastern Shore’s last rate case. In conjunction

Chesapeake Utilities Corporation 2021 Form 10-K     Page 98

Notes to the Consolidated Financial Statements

with the filing of this surcharge, pursuant to the settlement agreement, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge became effective July 15, 2021.

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 to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued through the fourth quarter of 2021. Chesapeake Utilities is considered an “essential business,” which has 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 these unprecedented times.

In 2021, restrictions were gradually lifted as vaccines became widely available in the United States. The state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021. However, in light of the winter surge of COVID-19 cases, in January 2022, another state of emergency was declared in Delaware and Maryland. Considering the prevalence of new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC and the Occupational Safety and Health Administration, with a goal of minimizing further exposure for our employees, customers and the communities.

In April 2020, the Maryland PSC issued an order that authorized utilities to establish a regulatory asset to record prudently incurred incremental costs related to COVID-19, beginning on March 16, 2020. The Maryland PSC found that the creation of a regulatory asset for COVID-19 related expenses will facilitate the recovery of those costs prudently incurred to serve customers during the COVID-19 pandemic, and that the deferral of such costs is appropriate because the current catastrophic health emergency is outside the control of the utility and is a non-recurring event. The Maryland PSC reviewed and issued guidance regarding the distribution of funds and the manner in which the utilities will allocate the funds to customers with eligible arrearages. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas received $0.3 million in the third quarter of 2021 to credit the accounts of those customers experiencing financial hardship in becoming current on their past due balances.

In May 2020, the Delaware PSC issued an order that authorized Delaware utilities to establish a regulatory asset to record COVID-19 related incremental costs incurred to ensure customers have essential utility services, for the period beginning on March 24, 2020 and ending 30 days after the state of emergency ends. The state of emergency was lifted July 12, 2021. However, in light of the winter surge of COVID-19 cases, a new state of emergency was declared in January 2022. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs. Funds to assist with individual customer arrearages have become available through the Delaware State Housing Authority. We are working to ensure that customers know how to seek this support and then apply it to their overdue utility bills.

The Company’s Florida regulated business units reached a settlement with the Florida OPC in June 2021 related to incremental expenses incurred due to COVID-19. The settlement allows the units to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021. 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 will amortize the regulatory asset over two years and recover it 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 division. This settlement agreement was approved by the Florida PSC on July 8, 2021 and the final order was issued on July 22, 2021.

In the fourth quarter of 2020, we began recording regulatory assets based on the net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric business units as authorized by the Delaware, Maryland and Florida PSCs. As of December 31, 2021 and 2020, our total COVID-19 regulatory asset balance was $2.3 million and $1.9 million, respectively.

Chesapeake Utilities Corporation 2021 Form 10-K Page 99

Notes to the Consolidated Financial Statements

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, 2021 and 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	December 31, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,591	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,840	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,656	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,032	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,189	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$271	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,237	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,091	$1,124	PSC approved amortization of ADIT in March 2018.

Regulatory Assets and Liabilities

At December 31, 2021 and 2020, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 100

Notes to the Consolidated Financial Statements

	As of December 31,
	2021		2020
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	9,199	$	2,078
Under-recovered GRIP revenue (2)	2,101		278
Deferred postretirement benefits (3)	16,749		17,716
Deferred conversion and development costs (1)	23,383		23,054
Environmental regulatory assets and expenditures (4)	1,258		1,743
Acquisition adjustment (5)	27,182		28,756
Loss on reacquired debt (6)	721		795
Deferred costs associated with COVID-19 (7)	2,289		1,925
Deferred storm costs (8)	36,004		44,320
Other	5,081		3,927
Total Regulatory Assets	$	123,967	$	124,592
Regulatory Liabilities
Self-insurance (9)	$	563	$	533
Over-recovered purchased fuel and conservation cost recovery (1)	1,073		4,422
Over-recovered GRIP revenue (2)	11		338
Storm reserve (9)	2,829		2,673
Accrued asset removal cost (10)	47,887		45,315
Deferred income taxes due to rate change (11)	88,804		90,845
Interest related to storm recovery (8)	2,146		3,353
Other	1,487		1,541
Total Regulatory Liabilities	$	144,800	$	149,020

(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) 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’ Central Florida Gas division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(3) 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 17, Employee Benefit Plans, for additional information.

(4) All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 20, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

(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.

(6) Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

(7) 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.

(8) 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.

(9) 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.

(10) See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(11) 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 12, Income Taxes, for additional information.

Chesapeake Utilities Corporation 2021 Form 10-K Page 101

Notes to the Consolidated Financial Statements

20. 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, 2021 and 2020, we had approximately $5.2 million and $5.9 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2021 and 2020, we have cumulative regulatory assets of $1.3 million and $1.7 million, respectively, in regulatory assets for future recovery of environmental costs for customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. As of December 31, 2021 and 2020, we have recovered approximately $12.9 million and $12.4 million, respectively, leaving approximately $1.1 million and $1.6 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

Remediation is ongoing for the 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 following is a summary of our remediation status and estimated costs to implement clean-up of our West Palm Beach Florida site:

Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected be completed in 2022.	Between $3.3 million to $14.2 million, including costs associated with the relocation of FPU’s operations at this site, and any potential costs associated with future redevelopment of the properties.

21. OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

In March 2020, 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, 2020 and expire in March 2023.

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 are for a 10-year term that commenced in November 2020 and expire in October 2030.

Chesapeake Utilities' Florida Division 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

Chesapeake Utilities Corporation 2021 Form 10-K     Page 102

Notes to the Consolidated Financial Statements

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, 2021, FPU was in compliance with all of the requirements of its fuel 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	2022		2023-2024		2025-2026		Beyond 2026		Total
(in thousands)
Purchase Obligations	$	89,557	$	82,412	$	70,114	$	174,203	$	416,286

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, 2021 was $20.0 million. The aggregate amount guaranteed at December 31, 2021 was approximately $13.1 million with the guarantees expiring on various dates through December 1, 2022.

As of December 31, 2021, we have issued letters of credit totaling approximately $5.3 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 25, 2022. There have been no draws on these letters of credit as of December 31, 2021. 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 2021 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, 2021. 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, 2021.

CHANGE IN INTERNAL CONTROLS

In response to the COVID-19 pandemic and social distancing restrictions that have been established in our service territories, our current pandemic response plan includes having office staff work remotely to promote social distancing in efforts to reduce the ongoing spread of COVID-19. During the quarter ended December 31, 2021, our pandemic response plan did not result in a change in the design or operations of our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting. There has been no change in internal control over financial reporting (as such term is defined in Exchange Act Rule 13a-15(f)) that occurred during the quarter ended December 31, 2021, that materially affected, or is reasonably likely to materially affect, internal control over financial reporting.

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, 2021. In addition, in May 28, 2021, 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. 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.

Our management has evaluated and concluded that our internal control over financial reporting was effective as of December 31, 2021.

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, 2021, as stated in its report which appears under Part II, Item 8. Financial Statements and Supplementary Data. 

Chesapeake Utilities Corporation 2021 Form 10-K     Page 104

ITEM 9B. OTHER INFORMATION.

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, Chief Accounting Officer, Corporate Controller, Assistant Treasurer, 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://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 our Principal Executive Officer, President, Principal Financial Officer, Chief Accounting Officer or Corporate Controller, 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 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 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 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 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 captioned “Fees and Services of Independent Registered Public Accounting Firm." The Company's independent registered public accounting firm is Baker Tilly, LLP, PCAOB ID: (23)

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.

Chesapeake Utilities Corporation 2021 Form 10-K Page 105

(a)(3) The Exhibits below.

• Exhibit 1.1	Equity Distribution Agreement, dated August 17, 2020, by and between Chesapeake Utilities Corporation and each of RBC Capital Markets, LLC, BofA Securities, Inc., Wells Fargo Securities, LLC, Janney Montgomery Scott LLC, Guggenheim Securities, LLC, Maxim Group LLC, Sidoti & Company, LLC, and Siebert Williams Shank & Co., LLC is incorporated herein by reference to Exhibit 1.1 of our Current Report on Form 8-K, filed August 17, 2020, File No. 001-11590.
•     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 December 4, 2012, are incorporated herein by reference to Exhibit 3 of our Current Report on Form 8-K, filed December 7, 2012, File No. 001-11590.
•     Exhibit 3.3	First Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 3, 2014, is incorporated herein by reference to Exhibit 3.3 of our Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-11590.
•     Exhibit 3.4	Second Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective November 2, 2016, is incorporated herein by reference to Exhibit 3.3 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, File No. 001-11590.
•     Exhibit 3.5	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 3.6	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 3.7	Third Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective May 8, 2019, is incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 14, 2019, File No. 001-11590.
•     Exhibit 4.1	Note Agreement dated October 31, 2008, among Chesapeake Utilities Corporation, as issuer, General American Life Insurance Company and New England Life Insurance Company, relating to the private placement of Chesapeake Utilities Corporation's 5.93% Senior Notes due 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. †

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•       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. †
•       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 Corporations'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	Description of Securities Registered Under Section 12 of the Securities Exchange Act of 1934, as amended, is filed herewith.
•        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*	Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan, effective May 2, 2013 is incorporated herein by reference to our Proxy Statement dated March 29, 2013 in connection with our Annual Meeting held on May 2, 2013, File No. 001-11590.
•        Exhibit 10.3*	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 10.4*	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 10.5*	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 10.6	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 10.7	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 10.8	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 10.9*	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 2021 Form 10-K Page 107

•      Exhibit 10.10*	Executive Employment Agreement dated February 25, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.25 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.
•      Exhibit 10.11	Term Note dated January 31, 2019 issued by Chesapeake Utilities Corporation in favor of Branch Banking & Trust Company is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended March 30, 2019, File No. 001-11590.
•      Exhibit 10.12	Term Loan Credit Agreement, dated January 31, 2019, by and between Chesapeake Utilities Corporation and Branch Banking and Trust Company is incorporated herein by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q for the quarter ended March 30, 2019, File No. 001-11590.
•      Exhibit 10.13*	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 10.14	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 10.15*	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 10.16*	Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Kevin Webber, is filed incorporated herein by reference to Exhibit 10.27 to our Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-11590.
•      Exhibit 10.17*	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 10.18*	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 filed herewith.
• Exhibit 10.19	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 10.20	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 10.21	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.

Chesapeake Utilities Corporation 2021 Form 10-K     Page 108

• Exhibit 10.22	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 10.23	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.
• Exhibit 10.24	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 10.25	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 10.26	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 10.27	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 10.28	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 10.29*	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 10.30*	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 10.31*	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 10.32*	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 10.33*	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 10.34*	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 filed herewith.
•       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.

Chesapeake Utilities Corporation 2021 Form 10-K Page 109

•       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 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 2021 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 23, 2022

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,
February 23, 2022	and Assistant Corporate Secretary
	(Principal Financial and Accounting Officer)
	February 23, 2022
/S/ JOHN R. SCHIMKAITIS	/S/ DENNIS S. HUDSON, III
John R. Schimkaitis	Dennis S. Hudson, III, Director
Chair of the Board and Director	February 23, 2022
February 23, 2022
/S/ LISA G. BISACCIA	/S/ LILA A. JABER
Lisa G. Bisaccia, Director	Lila A. Jaber, Director
February 23, 2022	February 23, 2022
/S/ THOMAS J. BRESNAN	/S/ PAUL L. MADDOCK, JR.
Thomas J. Bresnan, Director	Paul L. Maddock, Jr., Director
February 23, 2022	February 23, 2022
/S/ RONALD G. FORSYTHE, JR.	/S/ CALVERT A. MORGAN, JR.
Dr. Ronald G. Forsythe, Jr., Director	Calvert A. Morgan, Jr., Director
February 23, 2022	February 23, 2022
/S/ THOMAS P. HILL, JR.	/S/ DIANNA F. MORGAN
Thomas P. Hill, Jr., Director	Dianna F. Morgan, Director
February 23, 2022	February 23, 2022

Chesapeake Utilities Corporation 2021 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
2021	$	4,785	$	134	$	(125)	$	(1,653)	$	3,141
2020	$	1,337	$	3,827	$	613	$	(992)	$	4,785
2019	$	1,058	$	1,392	$	278	$	(1,391)	$	1,337

(1) Recoveries and other allowance adjustments

(2) Uncollectible accounts charged off.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 112

EX-4.10

Exhibit 4.10

DESCRIPTION OF THE REGISTRANT’S SECURITIES REGISTERED PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934, AS AMENDED

The following is a description of the common stock, par value $0.4867 per share (our “Common Stock”), of Chesapeake Utilities Corporation (“Chesapeake Utilities,” the “Company,” “we,” “us,” or “our”) registered under Section 12 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). This description is a summary and is qualified in its entirety by reference to our Amended and Restated Certificate of Incorporation, as amended (the “Certificate of Incorporation”) and our Amended and Restated Bylaws, as amended (the “Bylaws”), each of which are incorporated by reference as exhibits to the Annual Report on Form 10-K of which this Exhibit 4.7 is a part. We encourage you to read our Certificate of Incorporation, our Bylaws, and the applicable provisions of the Delaware General Corporation Law for additional information.

Authorized and Outstanding Capital Stock

Our authorized capital stock consists of 50,000,000 shares of our Common Stock and 2,000,000 shares of preferred stock, par value $0.01 per share (our “Preferred Stock”). As of February 18, 2022, 17,657,537shares of our Common Stock were outstanding and no shares of our Preferred Stock were outstanding.

Common Stock

Our stockholders are entitled to one vote for each share held of record on all matters submitted to a vote of stockholders and are entitled to receive dividends when and as declared by the board of directors (the “Board of Directors”) out of funds legally available therefore for distribution to stockholders and to share ratably in the assets legally available for distribution to stockholders in the event of the liquidation or dissolution, whether voluntary or involuntary, of Chesapeake Utilities. Our stockholders do not have cumulative voting rights in the election of directors and have no preemptive, subscription, or conversion rights. Our Common Stock is not subject to redemption by us.

The transfer agent and registrar for our Common Stock is Computershare Trust Company, N.A.

Preferred Stock

Shares of our Preferred Stock may be issued by us from time to time, by authorization of the Board of Directors and without the necessity of further action or authorization by our stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional, or other special rights and qualifications as the Board of Directors may, in its discretion, determine, including, but not limited to: (i) the distinctive designation of such series and the number of shares to constitute such series; (ii) the dividend rights, if any, for such series; (iii) the voting power, if any, of shares of such series; (iv) the terms and conditions (including price), if any, upon which shares of such stock may be converted into or exchanged for shares of stock of any other class or any other series of the same class or any other securities or assets; (v) our right, if any, to redeem shares of such series and the terms and conditions of such redemption; (vi) the retirement or sinking fund provisions, if any, of shares of such series and the terms and provisions relative to the operation thereof; (vii) the amount, if any, that the stockholders of such series shall be entitled to receive in case of a liquidation, dissolution, or winding up of Chesapeake Utilities; (viii) the limitations and restrictions, if any, upon the payment of dividends or the making of other distributions on, and upon the purchase, redemption, or other acquisition by us of, our Common Stock; and (ix) the conditions or restrictions, if any, upon the creation of indebtedness or upon the issuance of any additional stock of Chesapeake Utilities.

Certain Provisions of our Certificate of Incorporation and our Bylaws

Certain provisions in our Certificate of Incorporation and Bylaws, as well as certain provisions of Delaware Law, may be deemed to have an anti-takeover effect and may delay, deter, or prevent a tender offer or takeover attempt that a stockholder might consider to be in its best interests, including attempts that might result in a premium being paid over the market price of the shares held by stockholders. These provisions contained in our Certificate of Incorporation and Bylaws include the items described below.

Exhibit 4.10

Change of Control Approvals. Pursuant to our Certificate of Incorporation, the affirmative vote of not less than 75% of the total voting power of all outstanding shares of our capital stock is required to approve a merger or consolidation of Chesapeake Utilities with, or the sale of substantially all of our assets or business to, any other corporation (other than a corporation 50% or more of the common stock of which is owned by us), if such corporation or its affiliates singly or in the aggregate own or control directly or indirectly 5% or more of the outstanding shares of our Common Stock, unless the transaction is approved by our Board of Directors prior to the acquisition by such corporation or its affiliates of ownership or control of 5% or more of the outstanding shares of common stock.

Classified Board of Directors. Our Certificate of Incorporation provides for a classified Board of Directors under which approximately one-third of the members are elected annually for three-year terms.

Special Stockholder Meetings. Our Bylaws provide that a special meeting of stockholders, unless otherwise provided by law or by the Certificate of Incorporation, may be called only by (i) the Chief Executive Officer and (ii) the Chief Executive Officer or the Secretary at the request in writing of a majority of the Board of Directors, and not at the request of any other person or person.

Stockholder Advance Notice Procedure. Our Bylaws establish an advance notice procedure for stockholders to make nominations of candidates for election as directors or to bring other business before an annual meeting of our stockholders.

Undesignated Preferred Stock. Because our Board of Directors has the power to establish the preferences and rights of the shares of any additional series of Preferred Stock, it may afford holders of any Preferred Stock preferences, powers, and rights, including voting and dividend rights, senior to the rights of holders of our Common Stock, which could adversely affect the holders of our Common Stock and could discourage a takeover of us even if a change of control of Chesapeake Utilities would be beneficial to the interests of our stockholders.

EX-10.18

Exhibit 10.18

PERFORMANCE STOCK AWARD AGREEMENT

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

2013 STOCK AND INCENTIVE COMPENSATION PLAN

On _______________, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to _______________ (the “Grantee”), who resides at ___________________________________, a Performance Stock Award on the terms and subject to the conditions of this Performance Stock Award Agreement.

Recitals

WHEREAS, the Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan (the “Plan”) has been duly adopted by action of the Company's Board of Directors (the “Board”) on March 6, 2013 and approved by the Shareholders of the Company at a meeting held on May 2, 2013; and

WHEREAS, the Committee of the Board of Directors of the Company referred to in the Plan (the “Committee”) has determined that it is in the best interests of the Company to grant the Performance Stock Award described herein pursuant to the Plan; and

WHEREAS, the shares of the Common Stock of the Company (“Shares”) that are subject to this Agreement, when added to the other shares of Common Stock that are subject to awards granted under the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are authorized to be granted under the Plan or the total number of shares of Common Stock that may be granted to an individual in a single calendar year.

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1.Performance Stock Award and Performance Period

The Company hereby grants to the Grantee a Performance Stock Award as of the Grant Date.As more fully described herein, the Grantee may earn up to _________ Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2021 to December 31, 2023 (the “Performance Period”).This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2.Performance Criteria and Terms of Stock Award

Exhibit 10.18

a.The Committee selected and established in writing performance criteria for the Performance Period, which, if met, may entitle the Grantee to some or all of the Performance Shares under this Award.As soon as practicable after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period, the Committee shall determine for purposes of this Agreement the Company’s (1) total shareholder return, defined as the cumulative total return to shareholders (“Shareholder Value”), (2) growth in long-term earnings, defined as the growth in total capital expenditures as a percentage of total capitalization (“Growth”), and (3) earnings performance, defined as average return on equity (“ROE”), in accordance with procedures established by the Committee.The Shareholder Value, Growth and ROE (each a “Performance Metric” and collectively, the “Performance Metrics”) shall be determined by the Committee in accordance with the terms of the Plan and this Agreement based on financial results reported to shareholders in the Company’s annual reports and may be subject to adjustment by the Committee for extraordinary events during the Performance Period, as applicable.Both the Shareholder Value and the Growth Performance Metrics will be compared to the performance of the 2021-2023 Performance Peer Group, Attachment A hereto and to the 2021-2023 Long-Term Award Resolution (collectively referred to as the “Peer Group”), for the Performance Period and Awards will be determined according to the schedule in subsection (b) below.For Shareholder Value, the calculation of total shareholder return will utilize the average closing stock price from November 1 through December 31 immediately preceding the beginning and at the end of the performance period.For the average ROE Performance Metric, the Company’s performance will be compared to pre-determined ROE thresholds established by the Committee.At the end of the Performance Period, the Committee shall certify the extent to which the Performance Goals were met during the Performance Period.If the Performance Goals for the Performance Period are met, the Grantee shall be entitled to the Award, subject, however, to the Committee’s exercise of discretion to adjust any Award to a grantee (either up or down) based on business objectives established for that grantee or any other factors, all as determined by the Committee in its sole discretion.The Committee shall promptly notify the Grantee of its determination.

a.The Grantee may earn 50% percent or more of the target award of _____ Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period .The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(c)Once established, the performance criteria identified above normally shall not be changed during the Performance Period.However, if any of the companies in the Peer Group cease to be publically traded, they will automatically be deleted from the Peer Group.In addition, if the Committee determines that external changes or other unanticipated business conditions have materially affected the fairness of the goals, or that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it

Exhibit 10.18

conducts its business, or acquisitions or divestitures of subsidiaries or business units, or other events or circumstances materially affect the performance criteria or render the performance criteria unsuitable, then the Committee may approve appropriate adjustments to the performance criteria (either up or down) during the Performance Period, in its discretion.

(d)Performance Shares that are awarded to the Grantee pursuant to this Section 2 shall be issued promptly, without payment of consideration by the Grantee, within 2 ½ months of the end of the Performance Period.The Grantee shall have the right to vote the Performance Shares and to receive the dividends distributable with respect to such Shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Performance Shares (the “Issue Date”).If, however, the Grantee receives Shares as part of any dividend or other distribution with respect to the Performance Shares, such Shares shall be treated as if they are Performance Shares, and such Shares shall be subject to all of the terms and conditions imposed by this Section 2.Notwithstanding the foregoing, the Grantee shall be entitled to receive an amount in cash, equivalent to the dividends that would have been paid on the awarded Performance Shares from the Grant Date to the Issue Date for those Performance Shares actually earned by the Grantee during the applicable Performance Period.Such dividend equivalents shall be payable at the time such Performance Shares are issued.

(e)The Performance Shares will not be registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution.Until a registration statement is filed and becomes effective, however, transfer of the Performance Shares shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Performance Shares are not transferred in the absence of such exemption.

(f)In the event of a Change in Control, as defined in the Plan, during the Performance Period, the Grantee shall earn the Target Award of Performance Shares set forth in this Section 2, as if all performance criteria were satisfied, without any pro ration based on the portion of the Performance Period that has expired as of the date of such Change in Control.

(g)If, during the Performance Period, the Grantee has a Termination of Employment, Performance Shares shall be deemed earned or forfeited as follows:

(1)Except as provided in Section (2), below, upon voluntary Termination of Employment by the Grantee or termination by the Company for any reason, all unearned Performance Shares shall be forfeited immediately; and

(2)If the Grantee has a Termination of Employment by reason of death or Disability or Retirement (as such terms are defined in the Plan), the number of Performance Shares that would otherwise have been earned at the end of the Performance Period shall be reduced by pro rating such Performance Shares based on the proportion of the Performance Period during which the Grantee was employed by the Company (based upon the full months of the Performance Period elapsed as of the end of the month in which the Termination of Employment occurred over the total number of months in the Performance Period), unless the Committee determines that the Performance Shares shall not be so reduced.

Exhibit 10.18

a.The Grantee shall be solely responsible for any federal, state and local taxes of any kind imposed in connection with the vesting or delivery of the Performance Shares.Prior to the transfer of any Performance Shares to the Grantee, the Grantee shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements.The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold Shares otherwise deliverable to the Grantee as Performance Shares, unless the Committee determines otherwise by resolution.If the Grantee fails to make such payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Performance Shares.In the case of any amounts withheld for taxes pursuant to this provision in the form of Shares, the amount withheld shall not exceed the maximum required by applicable law and regulations.

(i)Notwithstanding any other provision of this Agreement, if any payment or distribution (a "Payment") by the Company or any other person or entity to or for the benefit of the Grantee is determined to be an"excess parachute payment" (within the meaning of Code Section 280G(b)(1) or any successor provision of similar effect), whether paid or payable or distributed or distributable pursuant to this Agreement or otherwise, then the Grantee’s benefits under this Agreement may, unless the Grantee elects otherwise pursuant to his employment agreement, be reduced by the amount necessary so that the Grantee’s total "parachute payment" as defined in Code Section 280G(b)(2)(A) under this and all other agreements will be $1.00 less than the amount that would be a "parachute payment".The payment of any “excess parachute payment” pursuant to this paragraph shall also comply with the terms of the Grantee’s employment agreement, if any.

Section 3.Additional Conditions to Issuance of Shares

Each transfer of Performance Shares shall be subject to the condition that if at any time the Committee shall determine, in its sole discretion, that it is necessary or desirable as a condition of, or in connection with, the transfer of Performance Shares (i) to satisfy withholding tax or other withholding liabilities, (ii) to effect the listing, registration or qualification on any securities exchange or under any state or federal law of any Shares deliverable in connection with such exercise, or (iii) to obtain the consent or approval of any regulatory body, then in any such event such transfer shall not be effective unless such withholding, listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Company.

Section 4.Adjustment of Shares

(a)If the Company shall become involved in a merger, consolidation or other reorganization, whether or not the Company is the surviving corporation, any right to earn Performance Shares shall be deemed a right to earn or to elect to receive the consideration into which the Shares represented by the Performance Shares would have been converted under the terms of the merger, consolidation or other reorganization.If the Company is not the surviving corporation, the surviving corporation (the “Successor”) shall succeed to the rights and obligations of the Company under this Agreement.

Exhibit 10.18

(b)If any subdivision or combination of Shares or any stock dividend, capital reorganization or recapitalization occurs after the adoption of the Plan, the Committee shall make such proportionate adjustments as are appropriate to the number of Performance Shares to be earned in order to prevent the dilution or enlargement of the rights of the Grantee.

Section 5.No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company or to limit the right of the Company to terminate the Grantee’s employment for any reason or for no reason.

Section 6.Notice

Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, Delaware 19904, for the attention of the Committee, c/o the Corporate Secretary, and any notice by the Company to the Grantee shall be sent by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof.Either party may, by notice given to the other in accordance with the provisions of this Section, change the address to which subsequent notices shall be sent.

Section 7.Beneficiary Designation

Grantee may designate a beneficiary to receive any Performance Shares to which Grantee is entitled which vest as a result of Grantee’s death.Grantee acknowledges that the Company may exercise all rights under this Agreement and the Plan against Grantee and Grantee’s estate, heirs, lineal descendants and personal representatives and shall not be limited to exercising its rights against Grantee’s beneficiary.

Section 8.Assumption of Risk

It is expressly understood and agreed that the Grantee assumes all risks incident to any change hereafter in the applicable laws or regulations or incident to any change in the market value of the Performance Shares.

Section 9.Terms of Plan and Employment Agreement

This Agreement is entered into pursuant to the Plan (a summary of which has been delivered to the Grantee).This Agreement is subject to all of the terms and provisions of the Plan, which are incorporated into this Agreement by reference, and the actions taken by the Committee pursuant to the Plan.In the event of a conflict between this Agreement and the Plan, the provisions of the Plan shall govern.In addition, this Award is subject to applicable provisions of the Grantee’s employment agreement, including provisions requiring the Company to recover some or all of the Performance Shares awarded hereunder in the circumstances described in such agreement or as otherwise required by applicable law. All determinations by the Committee shall be in its sole discretion and shall be binding on the Company and the Grantee.

Section 10.Governing Law; Amendment

Exhibit 10.18

This Agreement shall be governed by, and shall be construed and administered in accordance with, the laws of the State of Delaware (without regard to its choice of law rules) and the requirements of any applicable federal law.This Agreement may be modified or amended only by a writing signed by the parties hereto.

Section 11.Action by the Committee

The parties agree that the interpretation of this Agreement shall rest exclusively and completely within the sole discretion of the Committee.The parties agree to be bound by the decisions of the Committee with regard to the interpretation of this Agreement and with regard to any and all matters set forth in this Agreement.The Committee may delegate its functions under this Agreement to an officer of the Company designated by the Committee (hereinafter the “Designee”).In fulfilling its responsibilities hereunder, the Committee or its Designee may rely upon documents, written statements of the parties or such other material as the Committee or its Designee deems appropriate.The parties agree that there is no right to be heard or to appear before the Committee or its Designee and that any decision of the Committee or its Designee relating to this Agreement shall be final and binding unless such decision is arbitrary and capricious.

Section 12.Terms of Agreement

This Agreement shall remain in full force and effect and shall be binding on the parties hereto for so long as any Performance Shares issued to the Grantee under this Agreement continue to be held by the Grantee.

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and the Grantee has executed the same in evidence of the Grantee'sacceptance hereof, upon the terms and conditions herein set forth, as of the day and year first above written.

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

Printed Name:

Exhibit 10.18

Attachment A

2021-2023 Performance Peer Group

The 2021-2023 Performance Peer Group consists of the following gas utility companies:

1.Atmos Energy Corporation

2.Black Hills Corporation

3.New Jersey Resources Corporation

4.NiSource, Inc.

5.NW Natural

6.Northwestern Corporation

7.OneGas, Inc.

8.RGC Resources, Inc.

9.South Jersey Industries, Inc.

10.Spire, Inc.

11.Unitil Corporation

EX-10.34

Exhibit 10.34

PERFORMANCE STOCK AWARD AGREEMENT

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

2013 STOCK AND INCENTIVE COMPENSATION PLAN

On February 23, 2022 (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to __________ (the “Grantee”), who resides at ______________, a Performance Stock Award on the terms and subject to the conditions of this Performance Stock Award Agreement.

Recitals

WHEREAS, the Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan (the “Plan”) has been duly adopted by action of the Company's Board of Directors (the “Board”) on March 6, 2013, approved by the Shareholders of the Company at a meeting held on May 2, 2013, and amended by the Compensation Committee of the Board, as administrator of the Plan, in January 2017 to align the Plan with a change in accounting standards; and

WHEREAS, the President of the Company after consultation with the Compensation Committee of the Board of Directors of the Company referred to in the Plan (the “Committee”) has determined that it is in the best interests of the Company to grant the Performance Stock Award described herein pursuant to the Plan; and

WHEREAS, the shares of the Common Stock of the Company (“Shares”) that are subject to this Agreement, when added to the other shares of Common Stock that are subject to awards granted under the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are authorized to be granted under the Plan or the total number of shares of Common Stock that may be granted to an individual in a single calendar year.

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1.Performance Stock Award and Performance Period

The Company hereby grants to the Grantee a Performance Stock Award as of the Grant Date.As more fully described herein, the Grantee may earn up to ______ Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2022 to December 31, 2024 (the “Performance Period”).This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2.Performance Criteria and Terms of Stock Award

Exhibit 10.34

a.The President selected and established in writing performance criteria for the Performance Period, which, if met, may entitle the Grantee to some or all of the Performance Shares under this Award.As soon as practicable after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period, the President in consultation with the Chief Financial Officer shall determine for purposes of this Agreement the Company’s (1) total shareholder return, defined as the cumulative total return to shareholders (“Shareholder Value”), (2) growth in long-term earnings, defined as the growth in total capital expenditures as a percentage of total capitalization (“Growth”), and (3) earnings performance, defined as average return on equity (“RoE”), in accordance with procedures established by the President.The Shareholder Value, Growth and RoE (each a “Performance Metric” and collectively, the “Performance Metrics”) shall be determined by the President and Chief Financial Officer in accordance with the terms of the Plan and this Agreement based on financial results reported to shareholders in the Company’s annual reports and may be subject to adjustment by the President for extraordinary events during the Performance Period, as applicable.Both the Shareholder Value and the Growth Performance Metrics will be compared to the performance of the 2022-2024 Performance Peer Group, Attachment A hereto and to the 2022-2024 Long-Term Award Resolution (collectively referred to as the “Peer Group”), for the Performance Period and Awards will be determined according to the schedule in subsection (b) below.For Shareholder Value, the calculation of total shareholder return will utilize the average closing stock price from November 1 through December 31 immediately preceding the beginning and at the end of the performance period. For the average RoE Performance Metric, the Company’s performance will be compared to pre-determined RoE thresholds established by the President. At the end of the Performance Period, the President shall certify the extent to which the Performance Goals were met during the Performance Period.If the Performance Goals for the Performance Period are met, the Grantee shall be entitled to the Award, subject, however, to the President’s exercise of discretion to adjust any Award to a grantee (either up or down) based on business objectives established for that grantee or any other factors, all as determined by the President in his sole discretion. The President shall promptly notify the Grantee of his determination.

a.The Grantee may earn 50% percent or more of the target award of _________ Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period. The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(c)Once established, the performance criteria identified above normally shall not be changed during the Performance Period.However, if any of the companies in the Peer Group cease to be publically traded, they will automatically be deleted from the Peer Group.In addition, if the President determines that external changes or other unanticipated business conditions have materially affected the fairness of the goals, or that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it

Exhibit 10.34

conducts its business, or acquisitions or divestitures of subsidiaries or business units, or other events or circumstances materially affect the performance criteria or render the performance criteria unsuitable, then the President may approve appropriate adjustments to the performance criteria (either up or down) during the Performance Period, in his discretion.

(d)Performance Shares that are awarded to the Grantee pursuant to this Section 2 shall be issued promptly, without payment of consideration by the Grantee, within 2½ months of the end of the Performance Period.The Grantee shall have the right to vote the Performance Shares and to receive the dividends distributable with respect to such Shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Performance Shares (the “Issue Date”).If, however, the Grantee receives Shares as part of any dividend or other distribution with respect to the Performance Shares, such Shares shall be treated as if they are Performance Shares, and such Shares shall be subject to all of the terms and conditions imposed by this Section 2.Notwithstanding the foregoing, the Grantee shall be entitled to receive an amount in cash, equivalent to the dividends that would have been paid on the awarded Performance Shares from the Grant Date to the Issue Date for those Performance Shares actually earned by the Grantee during the applicable Performance Period.Such dividend equivalents shall be payable at the time such Performance Shares are issued.

(e)The Performance Shares will not be registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution. Until a registration statement is filed and becomes effective, however, transfer of the Performance Shares shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Performance Shares are not transferred in the absence of such exemption.

(f)In the event of a Change in Control, as defined in the Plan, during the Performance Period, the Grantee shall earn the Target Award of Performance Shares set forth in this Section 2, as if all performance criteria were satisfied, without any pro ration based on the portion of the Performance Period that has expired as of the date of such Change in Control.

(g)If, during the Performance Period, the Grantee has a Termination of Employment, Performance Shares shall be deemed earned or forfeited as follows:

(1)Except as provided in Section (2), below, upon voluntary Termination of Employment by the Grantee or termination by the Company for any reason, all unearned Performance Shares shall be forfeited immediately; and

(2)If the Grantee has a Termination of Employment by reason of death or Disability or Retirement (as such terms are defined in the Plan), the number of Performance Shares that would otherwise have been earned at the end of the Performance Period shall be reduced by pro rating such Performance Shares based on the proportion of the Performance Period during which the Grantee was employed by the Company (based upon the full months of the Performance Period elapsed as of the end of the month in which the Termination of Employment occurred over the total number of months in the Performance Period), unless the President determines that the Performance Shares shall not be so reduced.

Exhibit 10.34

a.The Grantee shall be solely responsible for any federal, state and local taxes of any kind imposed in connection with the vesting or delivery of the Performance Shares.Prior to the transfer of any Performance Shares to the Grantee, the Grantee shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements. The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold Shares otherwise deliverable to the Grantee as Performance Shares, unless the President determines otherwise by resolution.If the Grantee fails to make such payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Performance Shares.In the case of any amounts withheld for taxes pursuant to this provision in the form of Shares, the amount withheld shall not exceed the maximum required by applicable law and regulations.

(i)Notwithstanding any other provision of this Agreement, if any payment or distribution (a "Payment") by the Company or any other person or entity to or for the benefit of the Grantee is determined to be an"excess parachute payment" (within the meaning of Code Section 280G(b)(1) or any successor provision of similar effect), whether paid or payable or distributed or distributable pursuant to this Agreement or otherwise, then the Grantee’s benefits under this Agreement may be reduced by the amount necessary so that the Grantee’s total "parachute payment" as defined in Code Section 280G(b)(2)(A) under this and all other agreements will be $1.00 less than the amount that would be a "parachute payment".

Section 3.Additional Conditions to Issuance of Shares

Each transfer of Performance Shares shall be subject to the condition that if at any time the President shall determine, in his sole discretion, that it is necessary or desirable as a condition of, or in connection with, the transfer of Performance Shares (i) to satisfy withholding tax or other withholding liabilities, (ii) to effect the listing, registration or qualification on any securities exchange or under any state or federal law of any Shares deliverable in connection with such exercise, or (iii) to obtain the consent or approval of any regulatory body, then in any such event such transfer shall not be effective unless such withholding, listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Company.

Section 4.Adjustment of Shares

(a)If the Company shall become involved in a merger, consolidation or other reorganization, whether or not the Company is the surviving corporation, any right to earn Performance Shares shall be deemed a right to earn or to elect to receive the consideration into which the Shares represented by the Performance Shares would have been converted under the terms of the merger, consolidation or other reorganization.If the Company is not the surviving corporation, the surviving corporation (the “Successor”) shall succeed to the rights and obligations of the Company under this Agreement.

(b)If any subdivision or combination of Shares or any stock dividend, capital reorganization or recapitalization occurs after the adoption of the Plan, the President shall make such proportionate adjustments as are appropriate to the number of Performance Shares to be earned in order to prevent the dilution or enlargement of the rights of the Grantee.

Exhibit 10.34

Section 5.No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company or to limit the right of the Company to terminate the Grantee’s employment for any reason or for no reason.

Section 6.Notice

Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake Utilities Corporation, 500 Energy Lane, Dover, Delaware 19901, for the attention of the President, c/o the Corporate Secretary, and any notice by the Company to the Grantee shall be sent by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof.Either party may, by notice given to the other in accordance with the provisions of this Section, change the address to which subsequent notices shall be sent.

Section 7.Beneficiary Designation

Grantee may designate a beneficiary to receive any Performance Shares to which Grantee is entitled which vest as a result of Grantee’s death.Grantee acknowledges that the Company may exercise all rights under this Agreement and the Plan against Grantee and Grantee’s estate, heirs, lineal descendants and personal representatives and shall not be limited to exercising its rights against Grantee’s beneficiary.

Section 8.Assumption of Risk

It is expressly understood and agreed that the Grantee assumes all risks incident to any change hereafter in the applicable laws or regulations or incident to any change in the market value of the Performance Shares.

Section 9.Terms of Plan

This Agreement is entered into pursuant to the Plan (a summary of which has been delivered to the Grantee).This Agreement is subject to all of the terms and provisions of the Plan, which are incorporated into this Agreement by reference, and the actions taken by the President pursuant to the Plan.In the event of a conflict between this Agreement and the Plan, the provisions of the Plan shall govern.All determinations by the President shall be in his sole discretion and shall be binding on the Company and the Grantee.

Section 10.Governing Law; Amendment

This Agreement shall be governed by, and shall be construed and administered in accordance with, the laws of the State of Delaware (without regard to its choice of law rules) and the requirements of any applicable federal law.This Agreement may be modified or amended only by a writing signed by the parties hereto.

Section 11.Action by the President

Exhibit 10.34

The parties agree that the interpretation of this Agreement shall rest exclusively and completely within the sole discretion of the President.The parties agree to be bound by the decisions of the President with regard to the interpretation of this Agreement and with regard to any and all matters set forth in this Agreement.The President may delegate his functions under this Agreement to an officer of the Company designated by the President (hereinafter the “Designee”).In fulfilling his responsibilities hereunder, the President or his Designee may rely upon documents, written statements of the parties or such other material as the President or his Designee deems appropriate.The parties agree that there is no right to be heard or to appear before the President or his Designee and that any decision of the President or his Designee relating to this Agreement shall be final and binding unless such decision is arbitrary and capricious.

Section 12.Terms of Agreement

This Agreement shall remain in full force and effect and shall be binding on the parties hereto for so long as any Performance Shares issued to the Grantee under this Agreement continue to be held by the Grantee.

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and the Grantee has executed the same in evidence of the Grantee'sacceptance hereof, upon the terms and conditions herein set forth, as of the day and year first above written.

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

Printed Name: ___________________

Exhibit 10.34

Attachment A

2022-2024 Performance Peer Group

The 2022-2024 Performance Peer Group consists of the following gas utility companies:

1.Atmos Energy Corporation

2.Black Hills Corporation

3.New Jersey Resources Corporation

4.NiSource Inc.

5.NW Natural (a subsidiary of Northwest Natural Holding Co.)

6.Northwestern Corporation

7.ONE Gas, Inc.

8.RGC Resources, Inc.

9.South Jersey Industries, Inc.

10.Spire Inc.

11.Unitil Corporation

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
Subsidiary of Sharp Energy, Inc.	State Incorporated
Sharpgas, Inc.	Delaware
Subsidiary of Florida Public Utilities Company	State Incorporated
Flo-Gas Corporation	Florida
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

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. 333-213729, 333-239569, and 333-250803), Form S-8 (No. 333-192198) and Form S-4 (No. 333-201992) of Chesapeake Utilities Corporation of our report dated February 23, 2022, 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, 2021.

/s/ Baker Tilly US, LLP

Philadelphia, Pennsylvania

February 23, 2022

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, 2021 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 23, 2022

/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, 2021 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 23, 2022

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President, Chief Financial Officer, 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, 2021, 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 23, 2022

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, Senior Vice President and Chief Financial 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, 2021, 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 23, 2022

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.

XML

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2021	Feb. 18, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Document Transition Report	false
Entity File Number	001-11590
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	51-0064146
Entity Address, Address Line One	909 Silver Lake Boulevard
Entity Address, City or Town	Dover
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19904
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		17,657,537
Documents Incorporated by Reference	Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2022 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	2021
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Auditor [Line Items]
Auditor Name	Baker Tilly US, LLP
Auditor Location	Philadelphia, Pennsylvania
Auditor Firm ID	23

XML

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues
Regulated Energy	$ 383,920	$ 352,746	$ 343,006
Unregulated Energy	206,869	152,526	154,151
Other	(20,821)	(17,074)	(17,552)
Total operating revenues	569,968	488,198	479,605
Operating Expenses
Natural gas and electricity costs	100,737	91,994	102,803
Propane and natural gas costs	86,213	45,944	51,698
Operations	148,294	142,055	137,845
Maintenance	16,793	15,587	15,679
Gain from a settlement	0	(130)	(130)
Depreciation and amortization	62,661	58,117	45,424
Other taxes	24,158	21,908	20,001
Total operating expenses	438,856	375,475	373,320
Operating Income	131,112	112,723	106,285
Other income (expense), net	1,721	3,222	(1,847)
Interest charges	20,135	21,765	22,224
Income from Continuing Operations Before Income Taxes	112,698	94,180	82,214
Income Taxes on Continuing Operations	29,231	23,538	21,114
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	83,467	70,642	61,100
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(1)	686	(1,349)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	0	170	5,402
Net Income (Loss) Attributable to Parent	$ 83,466	$ 71,498	$ 65,153
Weighted Average Common Shares Outstanding:
Basic (in shares)	17,558,078	16,711,579	16,398,443
Diluted (in shares)	17,633,029	16,770,735	16,448,486
Basic Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share	$ 4.75	$ 4.23	$ 3.73
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0	0.05	0.24
Basic (in usd per share)	4.75	4.28	3.97
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share	4.73	4.21	3.72
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0	0.05
Diluted (in usd per share)	$ 4.73	$ 4.26	$ 3.96

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 83,466	$ 71,498	$ 65,153
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(20), $(18) and $(20), respectively	(57)	(59)	(57)
Net gain (loss), net of tax of $662, $(41), and $368, respectively	1,935	(154)	1,052
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $864, $1,392 and $(176), respectively	2,262	3,643	(434)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent	28	(28)
Total Other Comprehensive Income	4,168	3,402	561
Comprehensive Income	$ 87,634	$ 74,900	$ 65,714

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ (20,000)	$ (18,000)	$ (20,148)
Tax expense recognized on the net gain (loss)	662,000	(41,000)	368,387
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	864,000	1,392,000	$ (176,000)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	$ 12,000	$ (12,000)

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Activities
Net Income	$ 83,466	$ 71,498	$ 65,153
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	62,661	58,117	45,900
Depreciation and accretion included in operations expenses	10,228	9,599	8,752
Deferred income taxes, net	26,658	24,709	24,476
Gain on sale of discontinued operations	0	(200)	(7,344)
Realized (loss) on sale of assets/commodity contracts	(9,026)	(6,243)	(4,135)
Unrealized (gain) on investments/commodity contracts	(1,464)	(1,482)	(1,595)
Employee benefits and compensation	(53)	207	1,985
Share-based compensation	5,945	4,829	4,279
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(1,634)	(7,426)	36,489
Propane inventory, storage gas and other inventory	(9,517)	1,709	8,227
Regulatory assets/liabilities, net	(18,464)	(4,973)	(7,812)
Prepaid expenses and other current assets	(1,520)	2,424	11,115
Accounts payable and other accrued liabilities	8,285	4,941	(62,021)
Income taxes receivable	(4,575)	7,165	(4,750)
Customer deposits and refunds	3,176	2,238	(1,811)
Accrued compensation	1,198	(2,473)	2,120
Other assets and liabilities, net	(4,860)	(5,723)	(16,064)
Net cash provided by operating activities	150,504	158,916	102,964
Investing Activities
Property, plant and equipment expenditures	(186,924)	(165,511)	(184,727)
Proceeds from sale of assets	1,033	8,080	427
Acquisitions, net of cash acquired	(36,371)	(22,231)	(23,988)
Proceeds from the sale of discontinued operations	0	200	22,871
Environmental expenditures	(761)	(2,169)	(1,170)
Net cash used in investing activities	(223,023)	(181,631)	(186,587)
Financing Activities
Common stock dividends	(31,537)	(27,161)	(24,693)
Payments for Repurchase of Common Stock	15,851	22,627	(721)
Proceeds from issuance of common stock, net of expenses	0	60,980	0
Payment, Tax Withholding, Share-based Payment Arrangement	(1,478)	(977)	(692)
Change in cash overdrafts due to outstanding checks	(1,154)	(825)	(1,174)
Net borrowings (repayments) under line of credit agreements	46,647	(71,637)	(45,913)
Proceeds from issuance of long-term debt	59,478	89,822	199,648
Repayment of long-term debt and finance lease obligation	(13,811)	(53,600)	(41,936)
Net cash provided by financing activities	73,996	19,229	84,519
Net (Decrease) Increase in Cash and Cash Equivalents	1,477	(3,486)	896
Cash and Cash Equivalents — Beginning of Period	3,499	6,985	6,089
Cash and Cash Equivalents — End of Period	$ 4,976	$ 3,499	$ 6,985

XML

Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment
Regulated Energy	$ 1,720,287	$ 1,577,576
Unregulated Energy	357,259	300,647
Other businesses and eliminations	35,418	30,769
Total property, plant and equipment	2,112,964	1,908,992
Accumulated depreciation	417,479	368,743
Construction Work in Progress	49,393	60,929
Net property, plant and equipment	1,744,878	1,601,178
Current Assets
Cash and cash equivalents	4,976	3,499
Accounts Receivable, before Allowance for Credit Loss, Current	61,623	61,675
Allowance for uncollectible accounts	3,141	4,785
Trade receivables, net	58,482	56,890
Accrued Revenue	22,513	21,527
Propane inventory, at average cost	11,644	5,906
Other inventory, at average cost	9,345	5,539
Regulatory assets	19,794	10,786
Storage gas prepayments	3,691	2,455
Income taxes receivable	17,460	12,885
Prepaid expenses	17,121	13,239
Derivative assets, at fair value	7,076	3,269
Other current assets	1,033	436
Total current assets	173,135	136,431
Deferred Charges and Other Assets
Goodwill	44,708	38,731
Other intangible assets, net	13,192	8,292
Investments, Fair Value Disclosure	12,095	10,776
Operating Lease, Right-of-Use Asset	10,139	11,194
Regulatory assets	104,173	113,806
Receivables and other deferred charges	12,549	12,079
Total deferred charges and other assets	196,856	194,878
Total Assets	2,114,869	1,932,487
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)	8,593	8,499
Additional paid-in capital	371,162	348,482
Retained earnings	393,072	342,969
Accumulated other comprehensive income (loss)	1,303	(2,865)
Deferred compensation obligation	7,240	5,679
Treasury Stock, Value	(7,240)	(5,679)
Total stockholders’ equity	774,130	697,085
Long-term debt, net of current maturities	549,903	508,499
Total capitalization	1,324,033	1,205,584
Current Liabilities
Current portion of long-term debt	17,962	13,600
Short-term borrowing	221,634	175,644
Accounts payable	52,628	60,253
Customer deposits and refunds	36,488	33,302
Accrued interest	2,775	2,905
Dividends payable	8,466	7,683
Accrued compensation	15,505	13,994
Regulatory liabilities	2,312	6,284
Derivative liabilities, at fair value	743	127
Other accrued liabilities	17,920	15,240
Total current liabilities	376,433	329,032
Deferred Credits and Other Liabilities
Deferred income taxes	233,550	205,388
Regulatory liabilities	142,488	142,736
Environmental liabilities	3,538	4,299
Other pension and benefit costs	24,120	30,673
Operating Lease, Liability, Noncurrent	8,571	9,872
Deferred investment tax credits and other liabilities	2,136	4,903
Total deferred credits and other liabilities	414,403	397,871
Commitments and Contingencies
Total Capitalization and Liabilities	2,114,869	1,932,487
Regulated Energy	1,720,287	1,577,576
Unregulated Energy	357,259	300,647
Other businesses and eliminations	35,418	30,769
Total property, plant and equipment	2,112,964	1,908,992
Accumulated depreciation	417,479	368,743
Construction Work in Progress	49,393	60,929
Net property, plant and equipment	1,744,878	1,601,178
Cash and cash equivalents	4,976	3,499
Accounts Receivable, before Allowance for Credit Loss, Current	61,623	61,675
Allowance for uncollectible accounts	3,141	4,785
Trade receivables, net	58,482	56,890
Accrued Revenue	22,513	21,527
Propane inventory, at average cost	11,644	5,906
Other inventory, at average cost	9,345	5,539
Regulatory assets	19,794	10,786
Storage gas prepayments	3,691	2,455
Income taxes receivable	17,460	12,885
Prepaid expenses	17,121	13,239
Derivative assets, at fair value	7,076	3,269
Other current assets	1,033	436
Disposal Group, Including Discontinued Operation, Assets, Current	173,135	136,431
Goodwill	44,708	38,731
Other intangible assets, net	13,192	8,292
Investments, Fair Value Disclosure	12,095	10,776
Operating Lease, Right-of-Use Asset	10,139	11,194
Regulatory assets	104,173	113,806
Receivables and other deferred charges	12,549	12,079
Deferred Charges And Other Assets	196,856	194,878
Total identifiable assets	2,114,869	1,932,487
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)	8,593	8,499
Additional paid-in capital	371,162	348,482
Retained earnings	393,072	342,969
Accumulated other comprehensive income (loss)	1,303	(2,865)
Deferred compensation obligation	7,240	5,679
Treasury Stock, Value	7,240	5,679
Stockholders' Equity Attributable to Parent	774,130	697,085
Long-term debt, net of current maturities	549,903	508,499
Total capitalization	1,324,033	1,205,584
Current portion of long-term debt	17,962	13,600
Short-term borrowing	221,634	175,644
Accounts payable	52,628	60,253
Customer deposits and refunds	36,488	33,302
Accrued interest	2,775	2,905
Dividends payable	8,466	7,683
Accrued compensation	15,505	13,994
Regulatory liabilities	2,312	6,284
Derivative liabilities, at fair value	743	127
Other accrued liabilities	17,920	15,240
Liabilities, Current	376,433	329,032
Deferred income taxes	233,550	205,388
Regulatory liabilities	142,488	142,736
Environmental liabilities	3,538	4,299
Other pension and benefit costs	24,120	30,673
Operating Lease, Liability, Noncurrent	8,571	9,872
Deferred investment tax credits and other liabilities	2,136	4,903
Deferred Credits and Other Liabilities	414,403	397,871
Commitments and Contingencies
Liabilities and Equity	$ 2,114,869	$ 1,932,487

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 3,141	$ 4,785
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

XML

Consolidated Statements of Stockholders' Equity - USD ($)		Total		Common Stock [Member]	Additional Paid-In Capital [Member]		Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
Shares, Issued	[1],[2]			16,378,545
Stockholders' Equity Attributable to Parent		$ 518,439,000	[2]	$ 7,971,000	$ 255,651,000		$ 261,530,000	$ (6,713,000)	$ 3,854,000	$ (3,854,000)
Net Income		65,153,000					65,153,000
Other comprehensive loss		561,000						561,000
Dividends		(26,191,000)					(26,191,000)
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				0
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		(3,000)		$ 0	(3,000)
Share-based compensation, shares				25,231
Share-based compensation		3,618,000	[3],[4]	$ 13,000	3,605,000
Treasury stock activities		0							689,000	(689,000)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect							115,000	(115,000)
Shares, Issued	[1],[2]			16,403,776
Stockholders' Equity Attributable to Parent		561,577,000	[2]	$ 7,984,000	259,253,000		300,607,000	(6,267,000)	4,543,000	(4,543,000)
Net Income		71,498,000					71,498,000
Other comprehensive loss		3,402,000						3,402,000
Dividends		(29,106,000)					(29,106,000)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				$ 498,000	85,353,000
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		85,851,000
Share-based compensation, shares	[3],[4]			34,456
Share-based compensation		3,893,000	[3],[4]	$ 17,000	3,876,000	[3],[4]
Treasury stock activities									1,136,000	(1,136,000)
New Accounting Pronouncement of Change in Accounting Principle, Effect of Adoption		$ (30,000)					(30,000)
Stock Issued During Period, Shares, Dividend Reinvestment Plan		300,000		1,023,609
Stock Issued During Period, Value, Dividend Reinvestment Plan		$ 86.12
Shares, Issued	[1],[2]			17,461,841
Stockholders' Equity Attributable to Parent		697,085,000		$ 8,499,000	348,482,000		342,969,000	(2,865,000)	5,679,000	(5,679,000)
Net Income		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		18,248,000		$ 72,000	18,176,000
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				147,256
Share-based compensation, shares	[3],[4]			46,313
Share-based compensation		$ 4,526,000	[3],[4]	$ 22,000	4,504,000
Treasury stock activities									1,561,000	(1,561,000)
Stock Issued During Period, Shares, Dividend Reinvestment Plan		100,000
Stock Issued During Period, Value, Dividend Reinvestment Plan		$ 125.71
Shares, Issued	[1],[2]			17,655,410
Stockholders' Equity Attributable to Parent		$ 774,130,000		$ 8,593,000	$ 371,162,000		$ 393,072,000	$ 1,303,000	$ 7,240,000	$ (7,240,000)

[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 116,238, 105,087 and 95,329 shares at December 31, 2021, 2020 and 2019, 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 2021, 2020 and 2019, we withheld 14,020, 10,319 and 7,635 shares, respectively, for taxes.(5) Includes the Retirement Savings Plan, DRIP and ATM equity issuances.

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Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	116,238	105,087	95,329
Dividends Declared	$ 1.8800	$ 1.7250	$ 1.5850
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	14,020	10,319	7,635

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Organization and Basis of Presentation

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 and in Florida; 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; and (d) our subsidiary, based in Florida, that provides CNG, LNG and RNG transportation and pipeline solutions, primarily to utilities and pipelines throughout the eastern United States.

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 changed to conform to current period presentation.

Beginning in the third quarter of 2019, our management began executing a strategy to sell the operating assets of PESCO. In the fourth quarter of 2019, we closed on four separate transactions to sell PESCO's assets and contracts. As a result of these sales, we have fully exited the natural gas marketing business. Accordingly, PESCO’s historical financial results are reflected in our consolidated financial statements as discontinued operations, which required retrospective application to financial information for all periods presented. Refer to Note 4, Acquisitions for further information.

Covid-19 Effects

Effects of COVID-19

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 into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place.

Throughout 2021, restrictions continued to be lifted as vaccines have become widely available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. The expiration of the states of emergency in our service territories, along with the settlement of our limited proceeding in Florida, has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process.

We have been closely following the legal process related to the Occupational Safety and Health Administration (OSHA) Emergency Temporary Standard (ETS) mandating that all employers, with 100 or more employees, require COVID-19 vaccinations or weekly testing, which made its way to the United States Supreme Court. While OSHA has withdrawn the ETS as a temporary standard following the Supreme Court’s ruling, we will continue to monitor its status as a proposed rule, and any developments in the various appeals of the various district court orders enjoining the enforcement of the Executive Order regarding the federal contractor vaccine mandate. In light of the continued emergence and growing prevalence of the new variants of COVID-19, such as the Omicron variant, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, and stockholders and take all precautions warranted to operate safely and to comply with the CDC and OSHA standards, in order to protect our employees, customers and the communities we serve. Refer to Note 19, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses associated with COVID-19.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

The preparation of the consolidated financial statements in conformity 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 betterments 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 for continuing operations by classification as of December 31, 2021 and 2020 is provided in the following table:

	As of December 31,
(in thousands)	2021		2020
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	859,627	$	782,329
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	727,277		667,538
Electric distribution	133,383		127,710
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	176,095		151,258
Natural gas transmission and supply – Ohio	112,050		87,962
Electricity and steam generation	36,740		36,521
Mobile CNG and pipeline solutions	32,374		24,905
Other	35,418		30,769
Total property, plant and equipment	2,112,964		1,908,992
Less: Accumulated depreciation and amortization	(417,479)		(368,743)
Plus: Construction work in progress	49,393		60,929
Net property, plant and equipment	$	1,744,878	$	1,601,178

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, 2021 and 2020, the non-refundable contributions totaled $6.3 million and $3.7 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 ratemaking purposes when the completed projects are placed in service. During the years ended December 31, 2021, 2020 and 2019 AFUDC totaled $0.4 million, $0.7 million and $0.7 million, respectively, which 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 15, Leases, for additional information.

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $27.6 million of assets at December 31, 2021, which consist 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. The pipeline was placed in-service during the second quarter of 2020. Peninsula Pipeline's share of direct expenses for the jointly-owned pipeline are included in operating expenses of our consolidated statements of income. Accumulated depreciation for this pipeline totaled $0.9 million at December 31, 2021.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2021 and 2020, which consisted of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, previously jointly owned with Peoples Gas. Effective October 2020, the parties agreed to terminate the pre-existing ownership and capacity agreement and rescind their ownership interests in exchange for defined sections of the pipeline. This resulted in Peninsula Pipeline taking a 100% ownership in the northern end of the pipeline. Accumulated depreciation for this pipeline totaled $1.8 million and $1.7 million at December 31, 2021 and 2020, respectively.

Impairment of Long-lived Assets

We periodically evaluate whether events or circumstances have occurred, which indicate that other 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. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2021, 2020 and 2019:

	2021	2020	2019
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.5%	2.6%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.6%
Natural gas transmission – Florida	2.3%	2.3%	2.4%
Electric distribution	2.8%	2.9%	3.4%

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

We report certain depreciation and accretion in operations expense, rather than as a 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 expense 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, 2021, 2020 and 2019, we reported $10.2 million, $9.6 million and $8.8 million, respectively, of depreciation and accretion in operations expenses.

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 the 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, Regulated Operations, 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, except for two utilities that provide only unbundled delivery service (Chesapeake Utilities' Central Florida Gas division and FPU's Indiantown division). 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 delivery 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.

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 pandemics and 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 resulted in 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. 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.

During the first quarter of 2020, COVID-19 began to rapidly spread within the United States. Federal, state and local governments throughout the country imposed restrictions to promote social distancing to slow the spread of the virus, which has also had the effect of limiting commercial activity. These measures resulted in significant job losses and a slowing of economic activity across the United States and in the areas that we serve. We have considered the impact of COVID-19 on our receivables for the twelve months ended December 31, 2021, monitored developments that impact our customers’ ability to pay and have revised our estimates of expected credit losses to reflect these impacts.

(in thousands)
Balance at December 31, 2020	$	4,785
Additions:
Provision for credit losses	134
Recoveries	(125)
Deductions:
Write offs	(1,653)
Balance at December 31, 2021	$	3,141

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 was no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2021, 2020 or 2019.

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 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 implied fair value. The testing of goodwill for the years ended December 31, 2021, 2020 and 2019 indicated no goodwill impairment. 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.

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 Prudential 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 assets.

We estimate the health care cost trend rates used in determining our postretirement net 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 recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is 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 sales” treatment under ASC Topic 815 Derivatives and Hedging, 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

There are no new accounting pronouncements issued that are applicable to us.

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Earnings Per Share

12 Months Ended

Dec. 31, 2021

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,
	2021		2020		2019
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	83,467	$	70,642	$	61,100
Income/(Loss) from Discontinued Operations	(1)		856		4,053
Net Income	$	83,466	$	71,498	$	65,153
Weighted average shares outstanding	17,558,078		16,711,579		16,398,443
Earnings Per Share from Continuing Operations	$	4.75	$	4.23	$	3.73
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Basic Earnings Per Share	$	4.75	$	4.28	$	3.97
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	17,558,078		16,711,579		16,398,443
Effect of dilutive securities — Share-based compensation	74,951		59,156		50,043
Adjusted denominator — Diluted	17,633,029		16,770,735		16,448,486
Earnings Per Share from Continuing Operations	$	4.73	$	4.21	$	3.72
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Diluted Earnings Per Share	$	4.73	$	4.26	$	3.96

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Acquisitions

12 Months Ended

Dec. 31, 2021

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS

Acquisition of Diversified Energy

On December 15, 2021, Sharp acquired the propane operating assets of Diversified Energy for approximately $37.5 million, net of cash acquired. In connection with this acquisition, we recorded a $2.1 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. Included with the acquisition, was approximately $1.7 million of working capital from the Seller consisting predominantly of accounts receivable and propane inventory. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2021. There are multiple strategic benefits to this acquisition including it: (i) expands our propane service territory into North Carolina, South Carolina, Pennsylvania, and Virginia and (ii) includes an established customer base with opportunities for future growth. Through this acquisition, the Company expands its operating footprint into North Carolina and South Carolina and our propane business will add approximately 19,000 residential, commercial and agricultural customers, along with distribution of approximately 10.0 million gallons of propane annually. In connection with this acquisition, we recorded $23.1 million in property plant and equipment, $6.2 million in intangible assets associated with customer relationships and non-compete agreements and $5.9 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. In January 2022, we received a $0.8 million customary post-closing working capital true-up provision related to the working capital valuation at the time of closing.

Acquisition of Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired. Additionally, the purchase price included $0.3 million of working capital. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2020. There are multiple strategic

benefits to this acquisition including: (i) expansion of our propane service territory in Florida and (ii) establishment of a customer base with additional opportunities for future growth.

In connection with this acquisition, we recorded $3.5 million in property plant and equipment, $1.4 million in intangible assets associated with customer relationships and non-compete agreements and $1.8 million in goodwill, all of which is deductible for income tax purposes.

Acquisition of Elkton Gas

In July 2020, we closed on the acquisition on of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland for approximately $15.6 million, net of cash acquired. Additionally, the purchase price included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland.

In connection with this acquisition, we recorded $15.9 million in property, plant and equipment, $0.6 million in accounts receivable, $2.6 million in other liabilities, $2.6 million in regulatory liabilities and $4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. Upon reaching the end of the acquisition measurement period, we recognized offsetting adjustments to the acquisition date fair values of several of the assets acquired and liabilities assumed. These adjustments did not materially impact our previously recognized amount of goodwill.

These acquisitions generated the following operating revenues and income:

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITIONWe 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 from continuing operations by major source based on product and service type for the years ended December 31, 2021, 2020 and 2019:

	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 division	34,074		—		—		34,074
FPU electric distribution	78,300		—		—		78,300
FPU natural gas distribution	100,535		—		—		100,535
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 delivery operations	—		142,082		—		142,082
Energy delivery 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 (1)	$	383,920	$	206,869	$	(20,821)	$	569,968

    

(1) 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.

	For the year ended December 31, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	63,389	$	—	$	—	$	63,389
Florida natural gas division	30,850		—		—		30,850
FPU electric distribution	76,863		—		—		76,863
FPU natural gas distribution	90,150		—		—		90,150
Maryland natural gas division	21,853		—		—		21,853
Sandpiper natural gas/propane operations	17,214		—		—		17,214
Elkton Gas	2,399		—		—		2,399
Total energy distribution	302,718		—		—		302,718
Energy transmission
Aspire Energy	—		27,951		—		27,951
Aspire Energy Express	16		—		—		16
Eastern Shore	75,117		—		—		75,117
Peninsula Pipeline	23,080		—		—		23,080
Total energy transmission	98,213		27,951		—		126,164
Energy generation
Eight Flags	—		16,147		—		16,147
Propane operations
Propane delivery operations	—		100,744		—		100,744
Energy delivery services
Marlin Gas Services	—		7,818		—		7,818
Other and eliminations
Eliminations	(48,185)		(134)		(17,602)		(65,921)
Other	—		—		528		528
Total other and eliminations	(48,185)		(134)		(17,074)		(65,393)
Total operating revenues (1)	$	352,746	$	152,526	$	(17,074)	$	488,198

(1) Total operating revenues for the year ended December 31, 2020, include other revenue (revenues from sources other than contracts with customers of $1.4 million and $0.2 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 years ended December 31, 2019
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	62,659	$	—	$	—	$	62,659
Florida natural gas division	28,485		—		—		28,485
FPU electric distribution	77,416		—		—		77,416
FPU natural gas distribution	82,418		—		—		82,418
Maryland natural gas division	22,517		—		—		22,517
Sandpiper natural gas/propane operations	19,068		—		—		19,068
Total energy distribution	292,563		—		—		292,563
Energy transmission
Aspire Energy	—		32,493		—		32,493
Aspire Energy Express	—		—		—		—
Eastern Shore	72,924		—		—		72,924
Peninsula Pipeline	16,453		—		—		16,453
Total energy transmission	89,377		32,493		—		121,870
Energy generation
Eight Flags	—		16,749		—		16,749
Propane operations
Propane delivery operations	—		109,614		—		109,614
Energy delivery services
Marlin Gas Services	—		5,702		—		5,702
Other and eliminations
Eliminations	(38,934)		(10,407)		(18,081)		(67,422)
Other	—		—		529		529
Total other and eliminations	(38,934)		(10,407)		(17,552)		(66,893)
Total operating revenues (1)	$	343,006	$	154,151	$	(17,552)	$	479,605

(1) Total operating revenues for the year ended December 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 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 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 delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane 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.

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, 2021 and 2020 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	4,816	$	644
Balance at 12/31/2021	56,277		4,806		747
Increase (decrease)	$	677	$	(10)	$	103

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 Mid-Atlantic propane delivery 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, 2021 and 2020, we recognized revenue of $1.1 million and $1.3 million, respectively.

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, 2021 are expected to be recognized as follows:

(in thousands)	2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	33,925	$	26,334	$	24,103	$	23,231	$	21,964	$	179,866
Natural gas distribution operations	6,747		6,174		5,946		5,410		5,179		33,543
FPU electric distribution	652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	41,324	$	33,160	$	30,701	$	28,916	$	27,418	$	213,959

Practical expedients

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.

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Segment Information

12 Months Ended

Dec. 31, 2021

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) 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 operations, and mobile compressed natural gas distribution and pipeline solutions operations. 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 table presents information about our reportable segments.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	381,879	$	350,853	$	340,857
Unregulated Energy	188,089		137,345		138,748
Total operating revenues, unaffiliated customers	$	569,968	$	488,198	$	479,605
Intersegment Revenues (1)
Regulated Energy	$	2,041	$	1,893	$	2,149
Unregulated Energy	18,780		15,181		15,403
Other businesses	527		528		529
Total intersegment revenues	$	21,348	$	17,602	$	18,081
Operating Income (Loss)
Regulated Energy	$	106,064	$	92,124	$	86,584
Unregulated Energy	24,382		20,664		19,938
Other businesses and eliminations	666		(65)		(237)
Operating Income	131,112		112,723		106,285
Other income (expense), net	1,721		3,222		(1,847)
Interest charges	20,135		21,765		22,224
Income from Continuing Operations before Income Taxes	112,698		94,180		82,214
Income Taxes on Continuing Operations	29,231		23,538		21,114
Income from Continuing Operations	83,467		70,642		61,100
Income (loss) from Discontinued Operations, Net of Tax	(1)		686		(1,349)
Gain on sale of Discontinued Operations, Net of tax	—		170		5,402
Net Income	$	83,466	$	71,498	$	65,153
Depreciation and Amortization
Regulated Energy	$	48,748	$	46,079	$	35,227
Unregulated Energy	13,869		11,988		10,130
Other businesses and eliminations	44		50		67
Total depreciation and amortization	$	62,661	$	58,117	$	45,424
Capital Expenditures
Regulated Energy	$	139,733	147,100		$	130,604
Unregulated Energy	81,651		46,295		60,034
Other businesses	6,425		2,480		8,348
Total capital expenditures	$	227,809	$	195,875	$	198,986

     

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

	As of December 31,
	2021		2020
Identifiable Assets
Regulated Energy segment	$	1,629,191	$	1,547,619
Unregulated Energy segment	439,114		347,665
Other businesses and eliminations	46,564		37,203
Total identifiable assets	$	2,114,869	$	1,932,487

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Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2021, 2020 and 2019 were as follows:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Cash paid for interest	$	20,809	$	22,884	$	23,856
Cash (received) paid for income taxes, net of refunds	$	8,395	$	(8,135)	$	3,221

Non-cash investing and financing activities during the years ended December 31, 2021, 2020, and 2019 were as follows: 

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	16,164	$	23,625	$	13,470
Common stock issued for the Retirement Savings Plan	$	1,712	$	1,605	$	—
Common stock issued under the SICP	$	2,834	$	1,971	$	1,691

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Derivative Instruments

12 Months Ended

Dec. 31, 2021

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, 2021 and 2020, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of December 31, 2021, 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	21.2	Cash flow hedges	June, 2024
Sharp	Propane (gallons)	Sales	4.4	Cash flow hedges	December, 2022
Sharp	Propane (gallons)	Purchases	0.3	N/A	March 2022

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 2021 through June 2024) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. If the index prices are lower than the contract prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $3.6 million of unrealized gain from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2022.

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 the second quarter of 2020, we entered into interest rate swaps with notional amounts totaling $100.0 million associated with three of our short-term lines of credit which expired in October 2020. The interest rate swaps were entered to hedge the variability in cash flows attributable to changes in the short-term borrowing rates during this period. Pricing on the interest rate swaps ranged between 0.2615 and 0.3875 percent for the period. In the fourth quarter of 2020, we entered into additional interest rate swaps with notional amount of $60.0 million through December 2021 with pricing of 0.20 percent and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest swap was cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate. At December 31, 2021 all of our interest rate swaps had expired and we have not entered into any new derivative contracts associated with our outstanding short-term borrowings.

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, the balance related to the account is as follows:

(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,081	$	1,505

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, 2021 and 2020 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	16	$	—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	—		14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	7,060		3,255
Total Derivative Assets		$	7,076	$	3,269

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	743		64
Interest rate swap agreements	Derivative liabilities, at fair value	—		40
Total Derivative Liabilities		$	743	$	127

 The effects of gains and losses from derivative instruments are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2021		2020		2019
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	(1)	$	—	$	—
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	(24)		(12)		—
Put/Call option	Propane inventory	—		34		—
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	(536)		—		—
Propane swap agreements	Propane and natural gas costs	7,187		2,428		1,520
Propane swap agreements	Other comprehensive income (loss)	3,126		5,035		(253)
Interest rate swap agreements	Interest expense	(28)		60		—
Interest rate swap agreements	Other comprehensive income (loss)	—		(40)		—
Natural gas swap contracts	Other comprehensive income (loss)	—		—		(63)
Natural gas futures contracts	Other comprehensive income (loss)	—		—		(294)
Total		$	9,724	$	7,505	$	910

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2021

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 the following:

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

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2021 and 2020, respectively:

			Fair Value Measurements Using:
As of December 31, 2021	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	$	26	$	26	$	—	$	—
Investments—guaranteed income fund	2,036		—		—		2,036
Investments—mutual funds and other	10,033		10,033		—		—
Total investments	12,095		10,059		—		2,036
Derivative assets	7,076		—		7,076		—
Total assets	$	19,171	$	10,059	$	7,076	$	2,036
Liabilities:
Derivative liabilities	$	743	$	—	$	743	$	—

			Fair Value Measurements Using:
As of December 31, 2020	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	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

	For the Year Ended December 31,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	88		261
Transfers/disbursements	(241)		1,065
Investment income	33		27
Ending Balance	$	2,036	$	2,156

Investment income from the Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.

At December 31, 2021 and 2020, 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 and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its near-term maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2021, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $568.8 million, compared to the estimated fair value of $597.2 million. At December 31, 2020, long-term debt, which includes the current maturities and debt issuance costs, had a carrying value of $523.0 million, compared to a fair value of $548.5 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 3 measurement.

See Note 17, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.

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Investments

12 Months Ended

Dec. 31, 2020

Investments [Abstract]

Investments

INVESTMENTS

 The investment balances at December 31, 2021 and 2020, consisted of the following:

	As of December 31,
(in thousands)	2021		2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	12,069	$	10,755
Investments in equity securities	26		21
Total	$	12,095	$	10,776

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2021, 2020 and 2019, we recorded net unrealized gains of $1.5 million, $1.5 million, and $1.6 million, respectively in other income (expense), net in the consolidated statements of income related to these investments. For the investments in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Goodwill and Other Intangible Assets

GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill from continuing operations as of December 31, 2021 and 2020 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731
Additions (1)	72		5,905		5,977
Balance at December 31, 2021	$	7,689	$	37,019	$	44,708

(1)Includes goodwill from the purchase of operating assets of Diversified Energy in December 2021 and Elkton Gas in the third quarter of 2020.

The annual impairment testing for the years 2021 and 2020 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2021 and 2020 are as follows:

	As of December 31,
	2021				2020
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	16,814	$	5,125	$	10,680	$	4,269
Non-Compete agreements (1)	2,431		1,078		2,375		768
Patents	452		354		452		236
Other	270		218		270		212
Total	$	19,967	$	6,775	$	13,777	$	5,485

(1) The customer relationship and non-compete agreements amounts include $6.1 million and less than $0.1 million, respectively, as a result of the purchase of the operating assets of Diversified Energy in December 2021 and $1.3 million and $0.1 million, respectively, recorded as a result of the purchase of the operating assets of Western Natural Gas in October 2020.

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 12 years. Amortization expense of intangible assets for the year ended December 31, 2021, 2020 and 2019 was $1.3 million, $1.2 million and $0.8 million, respectively. Amortization expense of intangible assets is expected to be $1.4 million for the year 2022, $1.3 million for the years 2023 through 2025, and $1.1 million for 2026.

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Income Taxes

12 Months Ended

Dec. 31, 2021

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 2015 are subject to examination. At December 31, 2021, the 2015 through 2019 federal income tax returns are under examination, and no report has been issued at this time.

We expect to have federal NOLs totaling $6.3 million and $12.2 million in 2019 and 2018 respectively upon the settlement of the Internal Revenue Service examination described above. Under the CARES Act, discussed below, we elected to carry the losses back to 2015 and 2013. For state income tax purposes, we had NOLs in various states of $14.6 million and $40.0 million as of December 31, 2021 and 2020, respectively, almost all of which will expire in 2039. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.5 million and $1.6 million related to state NOL carry-forwards at December 31, 2021 and 2020, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOLs 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. Our income tax expense for the years ended December 31, 2021 and 2020 included a tax benefit of $0.9 million and $1.8 million, respectively, 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.

On December 22, 2017, President Trump signed into law the TCJA. 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 and thereafter 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 19, 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 2021, 2020, and 2019; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2021, 2020, and 2019 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2021 and 2020.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Current Income Tax Expense
Federal	$	2,775	$	(2,777)	$	(2,252)
State	(96)		2,162		(491)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	2,632		(662)		(2,790)
Deferred Income Tax Expense (1)
Property, plant and equipment	24,074		23,224		25,907
Deferred gas costs	1,857		(714)		79
Pensions and other employee benefits	(655)		(75)		(454)
FPU merger-related premium cost and deferred gain	(351)		156		(278)
Net operating loss carryforwards	97		5,107		(3,772)
Other	1,577		(3,498)		2,422
Total deferred income tax expense	26,599		24,200		23,904
Income Tax Expense from Continuing Operations	29,231		23,538		21,114
Income Tax Expense from Discontinued Operations	—		153		1,416
Total Income Tax	$	29,231	$	23,691	$	22,530

(1) Includes $8.2 million, $4.9 million, and $4.7 million of deferred state income taxes for the years 2021, 2020 and 2019, respectively.

	For the Year Ended December 31,
	2021			2020			2019
(in thousands)
Reconciliation of Effective Income Tax Rates from Continuing Operations
Federal income tax expense (1)	$	23,666		$	19,778		$	17,264
State income taxes, net of federal benefit	6,371			5,051			5,093
ESOP dividend deduction	(180)			(218)			(173)
CARES Act Tax Benefit	(919)			(1,841)			—
Depreciation	(15)			—			—
Other	308			768			(1,070)
Total Income Tax Expense from Continuing Operations	$	29,231		$	23,538		$	21,114
Effective Income Tax Rate from Continuing Operations	25.94		%	24.99		%	25.65		%

(1) Federal income taxes were calculated at 21 percent for 2021, 2020, and 2019.

	As of December 31,
	2021		2020
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	224,034	$	199,287
Acquisition adjustment	6,266		6,618
Loss on reacquired debt	183		201
Deferred gas costs	2,366		509
Natural gas conversion costs	5,529		5,379
Storm reserve liability	5,783		7,073
Other	6,301		5,587
Total deferred income tax liabilities	250,462		224,654
Deferred income tax assets:
Pension and other employee benefits	5,354		4,636
Environmental costs	996		1,064
Net operating loss carryforwards	1,490		1,587
Storm reserve liability	448		409
Accrued expenses	4,843		6,153
Other	3,781		5,417
Total deferred income tax assets	16,912		19,266
Deferred Income Taxes Per Consolidated Balance Sheets	$	233,550	$	205,388

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Long-Term Debt

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2021		2020
Uncollateralized Senior Notes:
5.93% note, due October 31, 2023	$	6,000	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	14,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
2.49% notes Due January 25, 2037	50,000		—
Equipment security note
2.46% note, due September 24, 2031	9,378		—
Less: debt issuance costs	(913)		(901)
Total long-term debt	567,865		522,099
Less: current maturities	(17,962)		(13,600)
Total long-term debt, net of current maturities	$	549,903	$	508,499

Notes Purchase Agreement

On December 16, 2021, we agreed to issue and MetLife agreed to purchase 2.95 percent Senior Notes due March 15, 2042 in the aggregate principal amount of $50 million. We expect to issue the Notes on or before March 15, 2022. The Company anticipates using the proceeds received from the issuances of the Notes to reduce short-term borrowings under the Company’s revolving credit facility and/or to fund capital expenditures. These Senior Notes, when issued, will have similar covenants and default provisions as the existing senior notes, and will have an annual principal payment beginning in the eleventh year after the issuance.

Equipment Security Note

On September 24, 2021, we entered into an Equipment Financing Agreement with Banc of America Leasing & Capital, LLC to issue $9.6 million in sustainable financing associated with the purchase of qualifying equipment by our subsidiary, Marlin Gas Services. The equipment security note bears a 2.46 percent interest rate and has a term of 10 years. Under the terms of the agreement, we granted a security interest in the equipment to the lender, to serve as collateral.

Annual maturities

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

Year	2022		2023		2024		2025		2026		Thereafter		Total
(in thousands)
Payments	$	17,962	$	21,483	$	18,505	$	25,528	$	34,551	$	450,749	$	568,778

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. The following table summarizes our shelf agreements at December 31, 2021:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		(50,000)		100,000
Total	$	520,000	$	(220,000)	$	(50,000)	$	250,000

(1) The Prudential and MetLife Shelf Agreements expire in April 2023 and May 2023, respectively.

(2) Unfunded commitments of $50 million reflects Senior Notes expected to be issued on or before March 15, 2022..

The Senior Notes, Shelf Agreements or Shelf 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.

Uncollateralized Senior Notes

All of our Uncollateralized Senior Notes require periodic principal and interest payments as specified in each note. They also contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40.0 percent of total capitalization (including short-term borrowings), and the fixed charge coverage ratio must be at least 1.2 times. The most recent Senior Notes issued since September 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50.0 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain Uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2021, the cumulative consolidated net income base was $664.5 million, offset by restricted payments of $289.4 million, leaving $375.1 million of cumulative net income free of restrictions. As of December 31, 2021, we were in compliance with all of our debt covenants.

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Short-Term Borrowing

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Short-Term Borrowing

SHORT-TERM BORROWINGS

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At December 31, 2021 and 2020, we had $221.6 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 0.83 percent and 1.28 percent, respectively.

In August 2021, we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the facility consist of a $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three one-year extension options, which can be authorized by our Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the facility and to the extent that an individual loan under the Revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2021, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026. Both tranches are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon a total indebtedness to total capitalization ratio. As of December 31, 2021, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of December 31, 2021, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

Our total available credit under the Revolver at December 31, 2021 was $173.1 million. As of December 31, 2021, we had issued $5.3 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

In the fourth quarter of 2020, we entered into two $30.0 million interest rate swaps with a total notional amount of $60.0 million through December 2021 with pricing of 0.20 percent and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. At December 31, 2021, all of our interest rate swaps had expired and we have not entered into any new derivative contracts associated with our outstanding short-term borrowings.

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Leases

12 Months Ended

Dec. 31, 2021

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 all 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. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. 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, 2021, 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 which preclude our ability to pay dividends, obtain financing or enter into additional leases. As of December 31, 2021, 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	2021		2020
Operating lease cost (1)	Operations expense	$	2,064	$	2,029

(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 sheet at December 31, 2021 and 2020:

(in thousands)	Balance sheet classification	December 31, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,139	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,996	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,571		9,872
Total lease liabilities		$	10,567	$	11,619

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2021 and 2020:

	December 31, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.10		8.70
Weighted-average discount rate
Operating leases	3.6	%	3.8	%

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, 2021 and 2020:

	Year Ended December 31,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	1,996	$	1,956

The following table presents the future undiscounted maturities of our operating leases at December 31, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2022	$	2,019
2023	1,902
2024	1,672
2025	1,341
2026	885
Thereafter	3,668
Total lease payments	11,487
Less: Interest	(920)
Present value of lease liabilities	$	10,567

(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, 2021

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

STOCKHOLDERS' EQUITY

Common Stock Issuances

In June 2020, we filed a shelf registration statement with the SEC to facilitate the issuance of our common stock. In August 2020, we filed a prospectus supplement under the shelf registration statement for an ATM equity program under which we may issue and sell shares of our common stock up to an aggregate offering price of $75.0 million. In the third and fourth quarters of 2020, we issued 0.7 million shares of common stock at an average price per share of $82.93 and received net proceeds of approximately $61.0 million, after deducting commissions and other fees of $1.5 million.

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. 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. In 2021, we issued just over 0.1 million shares at an average price per share of $125.71 and received net proceeds of $15.2 million under the DRIP. In the third and fourth quarters of 2020, we issued 0.3 million shares at an average price per share of $86.12 and received net proceeds of $22.0 million under the DRIP.

We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, 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 and natural gas swaps and futures contracts, designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements, designated as cash flow hedges, are the components of our accumulated other comprehensive loss. The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the years ended December 31, 2021 and 2020. 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, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income (loss) before reclassifications	(578)		5,400		16		4,838
Amounts reclassified from accumulated other comprehensive income (loss)	365		(1,757)		(44)		(1,436)
Net current-period other comprehensive income (loss)	(213)		3,643		(28)		3,402
As of December 31, 2020	(5,146)		2,309		(28)		(2,865)
Other comprehensive income before reclassifications	262		7,075		—		7,337
Amounts reclassified from accumulated other comprehensive income (loss)	1,616		(4,813)		28		(3,169)
Net current-period other comprehensive income	1,878		2,262		28		4,168
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2021, 2020 and 2019. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	For the Year Ended December 31,
(in thousands)	2021		2020		2019
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(2,243)		(592)		(2,600)
Total before income taxes	(2,166)		(515)		(2,523)
Income tax benefit (4)	550		150		656
Net of tax	$	(1,616)	$	(365)	$	(1,867)
Gains on commodity contracts cash flow hedges
Propane swap agreements (2)	$	6,651	$	2,428	$	1,520
Natural gas swaps (2)(3)	—		—		7
Natural gas futures (2)(3)	—		—		2,096
Total before income taxes	6,651		2,428		3,623
Income tax expense (4)	(1,838)		(671)		(1,028)
Net of tax	$	4,813	$	1,757	$	2,595
Gains and (losses) on interest rate swap cash flow hedges:
Interest rate swap agreements	$	(28)	$	60	$	—
Total before income taxes	(28)		60		—
Income tax expense (4)	—		(16)		—
Net of tax	$	(28)	$	44	$	—
Total reclassifications for the period	$	3,169	$	1,436	$	728

(1) These amounts are included in the computation of net periodic benefits. See Note 17, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details.

(3) PESCO's results are reflected as discontinued operations in our consolidated statements of income.

(4) The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2021

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. We record as a component of other comprehensive income/loss or a regulatory asset the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs.

Defined Benefit Pension Plans

At December 31, 2021 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake SERP.

During the fourth quarter of 2021, we formally terminated the Chesapeake Pension Plan. Accordingly, a portion of the pension settlement expense associated with the termination was allocated to our Regulated Energy operations and was recorded as regulatory assets, previously approved in all of the impacted jurisdictions. The remaining portion of the pension settlement expense totaling $0.6 million was recorded in other expense in our consolidated statement of income which reflected the amount allocated to our Unregulated Energy operations or was deemed not recoverable through the regulatory process.

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 additional 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. Benefits under the Chesapeake SERP for the first sub-plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake SERP was frozen were credited with two additional years of service. 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 three plans at both December 31, 2021 and 2020, 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, 2021 and 2020 and the net periodic cost for the years ended December 31, 2021, 2020 and 2019 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2021			2020			2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,146		$	6,214		$	70,366		$	65,304		$	2,212		$	2,157
Interest cost	141			176			1,714			2,085			48			63
Actuarial (gain) loss	(371)			450			(1,953)			6,069			(12)			144
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Benefit obligation — end of year	—			6,146			67,030			70,366			2,096			2,212
Change in plan assets:
Fair value of plan assets — beginning of year	4,609			4,630			55,966			49,703			—			—
Actual return on plan assets	(237)			369			4,246			6,581			—			—
Employer contributions	1,544			304			1,597			2,774			152			152
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Fair value of plan assets — end of year	—			4,609			58,712			55,966			—			—
Reconciliation:
Funded status	—			(1,537)			(8,318)			(14,400)			(2,096)			(2,212)
Accrued pension cost	$	—		$	(1,537)		$	(8,318)		$	(14,400)		$	(2,096)		$	(2,212)
Assumptions:
Discount rate	2.50		%	2.25		%	2.75		%	2.50		%	2.50		%	2.25		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	—		%	—		%

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2021(2)			2020			2019(1)			2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic pension cost:
Interest cost	$	141		$	176		$	375		$	1,714		$	2,085		$	2,452		$	48		$	63		$	74
Expected return on assets	(166)			(157)			(487)			(3,306)			(2,967)			(2,770)			—			—			—
Amortization of actuarial loss	257			243			391			612			552			505			28			20			85
Settlement expense	1,810			203			1,982			—			—			—			—			—			58
Net periodic pension cost	2,042			465			2,261			(980)			(330)			187			76			83			217
Amortization of pre-merger regulatory asset	—			—			—			—			—			543			—			—			—
Total periodic cost	$	2,042		$	465		$	2,261		$	(980)		$	(330)		$	730		$	76		$	83		$	217
Assumptions:
Discount rate	2.25		%	3.00		%	3.00		%	2.50		%	3.25		%	4.25		%	2.25		%	3.00		%	4.00		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	—		%	—		%	—		%

(1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

(2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

Included in the net periodic costs for the FPU Pension Plan for the year ended December 31, 2019 is amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU's regulated operations for the changes in funded status that occurred, but were not recognized as part of net periodic cost, prior to the merger with Chesapeake Utilities in October 2009. This was previously deferred as a regulatory asset to be recovered through rates pursuant to an order by the Florida PSC. As of December 31, 2019, this regulatory asset was fully amortized. Excluding the service cost component, the other components of the net periodic costs have been recorded or reclassified to other expense, net of tax, in the consolidated statements of income.

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. At December 31, 2021, there are no remaining assets in the Chesapeake Pension Plan. The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2021, 2020 and 2019:

	FPU Pension Plan
At December 31,	2021		2020		2019
Asset Category
Equity securities	52	%	54	%	53	%
Debt securities	38	%	37	%	37	%
Other	10	%	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 plans. 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 (this allocation range applied to the Chesapeake Pension Plan prior to the de-risking strategy executed during the fourth quarter of 2019):

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	4	%	10	%
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, 2021 and 2020, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:

	Fair Value Measurement Hierarchy
	At December 31, 2021								At December 31, 2020
Asset Category	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	4,302	$	—	$	—	$	4,302	$	3,615	$	—	$	—	$	3,615
U.S. Mid Cap (1)	1,835		—		—		1,835		1,672		—		—		1,672
U.S. Small Cap (1)	954		—		—		954		891		—		—		891
International (2)	10,863		—		—		10,863		11,307		—		—		11,307
Alternative Strategies (3)	5,888		—		—		5,888		5,586		—		—		5,586
	23,842		—		—		23,842		23,071		—		—		23,071
Mutual Funds - Debt securities
Fixed income (4)	19,551		—		—		19,551		21,563		—		—		21,563
High Yield (4)	3,014		—		—		3,014		2,606		—		—		2,606
	22,565		—		—		22,565		24,169		—		—		24,169
Mutual Funds - Other
Commodities (5)	2,297		—		—		2,297		2,246		—		—		2,246
Real Estate (6)	2,729		—		—		2,729		1,954		—		—		1,954
Guaranteed deposit (7)	—		—		497		497		—		—		1,019		1,019
	5,026		—		497		5,523		4,200		—		1,019		5,219
Total Pension Plan Assets in fair value hierarchy	$	51,433	$	—	$	497	51,930		$	51,440	$	—	$	1,019	52,459
Investments measured at net asset value (8)							6,782								8,116
Total Pension Plan Assets							$	58,712							$	60,575

(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) 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, 2021 and 2020, our pension plans 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 following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

	For the Year Ended December 31,
	2021		2020
(in thousands)
Balance, beginning of year	$	1,019	$	1,147
Purchases	3,160		3,190
Transfers in	5,914		921
Disbursements	(9,587)		(4,290)
Investment income	(9)		51
Balance, end of year	$	497	$	1,019

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. The following table sets forth the funded status at December 31, 2021 and 2020:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,033		$	1,100		$	1,009		$	1,224
Interest cost	22			26			24			30
Plan participants contributions	190			166			29			37
Actuarial loss (gain)	159			(34)			71			(181)
Benefits paid	(470)			(225)			(129)			(101)
Benefit obligation — end of year	934			1,033			1,004			1,009
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	280			59			100			64
Plan participants contributions	190			166			29			37
Benefits paid	(470)			(225)			(129)			(101)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(934)			(1,033)			(1,004)			(1,009)
Accrued postretirement cost	$	(934)		$	(1,033)		$	(1,004)		$	(1,009)
Assumptions:
Discount rate	2.83		%	2.25		%	2.51		%	2.50		%

Net periodic postretirement benefit costs for 2021, 2020, and 2019 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	22		$	26		$	39		$	24		$	30		$	48
Amortization of actuarial loss (gain)	34			24			46			(9)			(19)			—
Amortization of prior service cost	(77)			(77)			(77)			—			—			—
Net periodic cost	(21)			(27)			8			15			11			48
Amortization of pre-merger regulatory asset	—			—			—			—			6			8
Total periodic cost	$	(21)		$	(27)		$	8		$	15		$	17		$	56
Assumptions
Discount rate	2.25		%	3.00		%	4.00		%	2.50		%	3.25		%	4.25		%

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive loss or as a regulatory asset as of December 31, 2021:

(in thousands)	FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service (credit)	$	—	$	—	$	(293)	$	—	$	(293)
Net loss (gain)	17,737		659		671		(114)		18,953
Total	$	17,737	$	659	$	378	$	(114)	$	18,660
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,370	$	659	$	378	$	(22)	$	4,385
Post-merger regulatory asset	14,367		—		—		(92)		14,275
Total unrecognized cost	$	17,737	$	659	$	378	$	(114)	$	18,660

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2021 is net of income tax benefits of $1.1 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations, which is included in the above table as a post-merger regulatory asset. As of December 31, 2021, the pre-merger regulatory asset related to the FPU Pension and FPU Medical Plan was fully amortized.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2021, considering the expected lives of each of the plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Due to the termination of the Chesapeake Pension Plan during the fourth quarter of 2021, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake Utilities' and FPU’s plans. 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 2021 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 2022, we expect to contribute $0.3 million to the FPU Pension Plan and $0.2 million to the Chesapeake SERP. We also expect to contribute less than $0.1 million to both the Chesapeake Postretirement Plan and FPU Medical Plan, in 2022.

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)
2022	$	3,451	$	151	$	73	$	71
2023	$	3,537	$	149	$	68	$	70
2024	$	3,592	$	147	$	63	$	71
2025	$	3,690	$	160	$	59	$	70
2026	$	3,720	$	157	$	54	$	69
Years 2027 through 2031	$	18,588	$	723	$	218	$	324

(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

For the years ended December 31, 2021, 2020 and 2019, we sponsored a 401(k) Retirement Savings Plan. This plan 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 $5.9 million, $5.9 million, and $5.7 million for the years ended December 31, 2021, 2020 and 2019, respectively. As of December 31, 2021, 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 our common stock in the same amount that is received by all other stockholders. Such dividends are reinvested into our common stock. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheet, had a fair value of $12.1 million and $10.8 million at December 31, 2021 and 2020, respectively. (See Note 10, Investments, for further details). 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, which represent deferred stock units, and directors’ stock retainers are paid in shares of our common stock, 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 $7.2 million and $5.7 million at December 31, 2021 and 2020, 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, 2021

Text Block [Abstract]

Share-Based Compensation Plans

SHARE-BASED COMPENSATION PLANS

Our non-employee directors and key employees 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 369,099 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, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Awards to non-employee directors	$	782	$	733	$	620
Awards to key employees	5,163		4,096		3,659
Total compensation expense	5,945		4,829		4,279
Less: tax benefit	(1,535)		(1,254)		(1,117)
Share-based compensation amounts included in net income	$	4,410	$	3,575	$	3,162

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. In May 2021, after the most recent election of directors, each of our non-employee directors received an annual retainer of 683 shares of common stock under the SICP for service as a director through the 2022 Annual Meeting of Stockholders; accordingly, 6,830 shares, with a weighted average fair value of $117.11 per share, were issued and vested in 2021. At December 31, 2021, 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 2022.

In October 2021, a newly appointed member of the Board of Directors received a pro-rated retainer of 342 shares of common stock under the SICP to serve as a non-employee director through the 2022 Annual Meeting of Stockholders. The shares awarded to the non-employee director immediately vested upon issuance in October 2021, had a weighted average fair value of $129.09 per share, and will be expensed over the remaining service period ending on the date of the 2022 Annual Meeting of Stockholders.

In May 2020, after the most recent election of directors, each of our non-employee directors received an annual retainer of 887 shares of common stock under the SICP for board service through the 2021 Annual Meeting of Stockholders; accordingly, 8,870 shares, with a weighted average fair value of $84.47 per share, were issued and vested in 2020.

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 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 the Monte Carlo valuation to estimate the fair value of each share granted.

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

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2019	157,817	$	80.28
Granted	70,014	91.89
Vested	(35,651)	66.48
Expired	(5,302)	65.32
Outstanding — December 31, 2020	186,878	87.06
Granted	69,903	100.76
Vested	(53,147)	76.31
Expired	(852)	74.85
Forfeited (1)	(5,384)	$	93.39
Outstanding — December 31, 2021	197,398	$	94.15

(1) In conjunction with the retirement of one key employee during 2020, these shares were forfeited for the remainder of the service periods associated with awards granted during their employment with the Company.

For the year ended December 31, 2021, we granted awards of 69,903 shares of common stock to officers under the SICP, including awards granted in February 2021 and to key employees appointed in officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which are comprised of market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted.

The intrinsic value of these awards was $28.8 million, $20.2 million and $15.1 million in 2021, 2020 and 2019, respectively. At December 31, 2021, there was $4.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2023.

In 2021, 2020 and 2019, we withheld shares with a value at least equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives electing to receive the net shares. The below table presents the number of shares withheld /and amounts remitted to taxing authorities:

	For the Year Ended December 31,
	2021		2020		2019
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	14,020		10,319		7,635
Amounts remitted to tax authorities to satisfy obligations	$	1,478	$	977	$	692

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Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2021

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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.

Delaware

See the discussion below under COVID-19 impact.

Maryland

Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement plan with the Maryland PSC. The STRIDE plan accelerates Elkton Gas' Aldyl-A pipeline replacement program as costs of the plan are recovered through a fixed charge rider which is effective for five years. Under Elkton Gas’ STRIDE plan, the Aldyl-A pipelines will be fully replaced by 2023. In July 2021, Elkton Gas reached a settlement with the Maryland PSC Staff and the Maryland Office of Public Counsel that approved Elkton Gas’ STRIDE plan. The STRIDE plan allows for recovery of the associated revenue requirement through a monthly surcharge, which was implemented effective September 2021.

Florida

West Palm Beach Expansion Project: In August 2019, the Florida PSC approved Peninsula Pipeline’s Transportation Service Agreement with FPU. Peninsula Pipeline constructed several new interconnection points and pipeline expansions in Palm Beach County, Florida, which will enable FPU to serve an industrial research park and several new residential developments. Peninsula Pipeline is now providing transportation service to FPU, increasing reliability and system pressure as well as introducing diversity in the fuel source for natural gas to serve the increased demand in these areas. Interim services began in the fourth quarter of 2019, and we completed the remainder of the project in phases through the fourth quarter of 2021.

Winter Haven Expansion Project: In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use the additional firm service to support new incremental load due to growth, including providing service to a new can manufacturing facility, as well as provide reliability and operational benefits to CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. The Transportation Service Agreement was approved by the Florida PSC in September 2021. Construction commenced in February 2021 and the expected in-service date is March 2022.

Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas 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 will construct 11 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021. Construction also commenced in June 2021 and the expected in-service date is December 2022.

Eastern Shore

Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that provides an additional 14,300 Dts/d of firm service to four customers. This includes six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. The project is now fully in service as the construction of the Somerset County, Maryland expansion was completed in the third quarter of 2021.

Capital Cost Surcharge: In June 2021, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge is an approved item in the settlement of Eastern Shore’s last rate case. In conjunction

with the filing of this surcharge, pursuant to the settlement agreement, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge became effective July 15, 2021.

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 to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued through the fourth quarter of 2021. Chesapeake Utilities is considered an “essential business,” which has 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 these unprecedented times.

In 2021, restrictions were gradually lifted as vaccines became widely available in the United States. The state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021. However, in light of the winter surge of COVID-19 cases, in January 2022, another state of emergency was declared in Delaware and Maryland. Considering the prevalence of new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC and the Occupational Safety and Health Administration, with a goal of minimizing further exposure for our employees, customers and the communities.

In April 2020, the Maryland PSC issued an order that authorized utilities to establish a regulatory asset to record prudently incurred incremental costs related to COVID-19, beginning on March 16, 2020. The Maryland PSC found that the creation of a regulatory asset for COVID-19 related expenses will facilitate the recovery of those costs prudently incurred to serve customers during the COVID-19 pandemic, and that the deferral of such costs is appropriate because the current catastrophic health emergency is outside the control of the utility and is a non-recurring event. The Maryland PSC reviewed and issued guidance regarding the distribution of funds and the manner in which the utilities will allocate the funds to customers with eligible arrearages. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas received $0.3 million in the third quarter of 2021 to credit the accounts of those customers experiencing financial hardship in becoming current on their past due balances.

In May 2020, the Delaware PSC issued an order that authorized Delaware utilities to establish a regulatory asset to record COVID-19 related incremental costs incurred to ensure customers have essential utility services, for the period beginning on March 24, 2020 and ending 30 days after the state of emergency ends. The state of emergency was lifted July 12, 2021. However, in light of the winter surge of COVID-19 cases, a new state of emergency was declared in January 2022. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs. Funds to assist with individual customer arrearages have become available through the Delaware State Housing Authority. We are working to ensure that customers know how to seek this support and then apply it to their overdue utility bills.

The Company’s Florida regulated business units reached a settlement with the Florida OPC in June 2021 related to incremental expenses incurred due to COVID-19. The settlement allows the units to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021. 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 will amortize the regulatory asset over two years and recover it 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 division. This settlement agreement was approved by the Florida PSC on July 8, 2021 and the final order was issued on July 22, 2021.

In the fourth quarter of 2020, we began recording regulatory assets based on the net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric business units as authorized by the Delaware, Maryland and Florida PSCs. As of December 31, 2021 and 2020, our total COVID-19 regulatory asset balance was $2.3 million and $1.9 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, 2021 and 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	December 31, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,591	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,840	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,656	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,032	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,189	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$271	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,237	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,091	$1,124	PSC approved amortization of ADIT in March 2018.

Regulatory Assets and Liabilities

At December 31, 2021 and 2020, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets. 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,
	2021		2020
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	9,199	$	2,078
Under-recovered GRIP revenue (2)	2,101		278
Deferred postretirement benefits (3)	16,749		17,716
Deferred conversion and development costs (1)	23,383		23,054
Environmental regulatory assets and expenditures (4)	1,258		1,743
Acquisition adjustment (5)	27,182		28,756
Loss on reacquired debt (6)	721		795
Deferred costs associated with COVID-19 (7)	2,289		1,925
Deferred storm costs (8)	36,004		44,320
Other	5,081		3,927
Total Regulatory Assets	$	123,967	$	124,592
Regulatory Liabilities
Self-insurance (9)	$	563	$	533
Over-recovered purchased fuel and conservation cost recovery (1)	1,073		4,422
Over-recovered GRIP revenue (2)	11		338
Storm reserve (9)	2,829		2,673
Accrued asset removal cost (10)	47,887		45,315
Deferred income taxes due to rate change (11)	88,804		90,845
Interest related to storm recovery (8)	2,146		3,353
Other	1,487		1,541
Total Regulatory Liabilities	$	144,800	$	149,020

(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) 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’ Central Florida Gas division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(3) 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 17, Employee Benefit Plans, for additional information.

(4) All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 20, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

(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.

(6) Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

(7) 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.

(8) 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.

(9) 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.

(10) See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(11) 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 12, Income Taxes, for additional information.

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Environmental Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

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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, 2021 and 2020, we had approximately $5.2 million and $5.9 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2021 and 2020, we have cumulative regulatory assets of $1.3 million and $1.7 million, respectively, in regulatory assets for future recovery of environmental costs for customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. As of December 31, 2021 and 2020, we have recovered approximately $12.9 million and $12.4 million, respectively, leaving approximately $1.1 million and $1.6 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

Remediation is ongoing for the 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 following is a summary of our remediation status and estimated costs to implement clean-up of our West Palm Beach Florida site:

Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected be completed in 2022.	Between $3.3 million to $14.2 million, including costs associated with the relocation of FPU’s operations at this site, and any potential costs associated with future redevelopment of the properties.

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2021

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Other Commitments and Contingencies

OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

In March 2020, 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, 2020 and expire in March 2023.

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 are for a 10-year term that commenced in November 2020 and expire in October 2030.

Chesapeake Utilities' Florida Division 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, 2021, FPU was in compliance with all of the requirements of its fuel 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	2022		2023-2024		2025-2026		Beyond 2026		Total
(in thousands)
Purchase Obligations	$	89,557	$	82,412	$	70,114	$	174,203	$	416,286

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, 2021 was $20.0 million. The aggregate amount guaranteed at December 31, 2021 was approximately $13.1 million with the guarantees expiring on various dates through December 1, 2022.

As of December 31, 2021, we have issued letters of credit totaling approximately $5.3 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 25, 2022. There have been no draws on these letters of credit as of December 31, 2021. 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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Quarterly Financial Data

12 Months Ended

Dec. 31, 2021

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Quarterly Financial Data (Unaudited)

QUARTERLY FINANCIAL DATA (UNAUDITED)

In our opinion, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.

	For the Quarters Ended
	March 31		June 30		September 30		December 31
(in thousands except per share amounts)
2020 (1)
Operating Revenues	$	152,690	$	97,051	$	101,419	$	137,038
Operating Income	$	42,134	$	17,977	$	17,406	$	35,206
Net Income:
Income from Continuing Operations	$	29,041	$	10,661	$	9,280	$	21,661
Earnings/(Loss) from Discontinued Operations, Net of Tax	(111)		125		(19)		691
Gain on sale of Discontinued Operations, Net of Tax	—		170		—		—
Net Income	$	28,930	$	10,956	$	9,261	$	22,352
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.65	$	0.56	$	1.23
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		0.02		—		0.04
Basic Earnings Per Share of Common Stock	$	1.76	$	0.67	$	0.56	$	1.27
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.64	$	0.56	$	1.22
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		0.02		—		0.04
Diluted Earnings Per Share of Common Stock	$	1.76	$	0.66	$	0.56	$	1.26
2019 (1)
Operating Revenues	$	160,464	$	94,542	$	92,626	$	131,974
Operating Income	$	44,122	$	18,165	$	14,357	$	29,641
Net Income:
Income from Continuing Operations	$	28,811	$	8,914	$	6,251	$	17,123
Earnings/(Loss) from Discontinued Operations, Net of Tax	(148)		(610)		(630)		39
Gain on sale of Discontinued Operations, Net of Tax	—		—		—		5,402
Net Income	$	28,663	$	8,304	$	5,621	$	22,564
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.76	$	0.54	$	0.38	$	1.05
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		(0.03)		(0.04)		0.33
Basic Earnings Per Share of Common Stock	$	1.75	$	0.51	$	0.34	$	1.38
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.75	$	0.54	$	0.38	$	1.04
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		(0.04)		(0.04)		0.33
Diluted Earnings Per Share of Common Stock	$	1.74	$	0.50	$	0.34	$	1.37

(1) The sum of the four quarters does not equal the total for the year due to rounding.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Use of Estimates

Use of EstimatesThe preparation of the consolidated financial statements in conformity 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 betterments 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 for continuing operations by classification as of December 31, 2021 and 2020 is provided in the following table:

	As of December 31,
(in thousands)	2021		2020
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	859,627	$	782,329
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	727,277		667,538
Electric distribution	133,383		127,710
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	176,095		151,258
Natural gas transmission and supply – Ohio	112,050		87,962
Electricity and steam generation	36,740		36,521
Mobile CNG and pipeline solutions	32,374		24,905
Other	35,418		30,769
Total property, plant and equipment	2,112,964		1,908,992
Less: Accumulated depreciation and amortization	(417,479)		(368,743)
Plus: Construction work in progress	49,393		60,929
Net property, plant and equipment	$	1,744,878	$	1,601,178

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, 2021 and 2020, the non-refundable contributions totaled $6.3 million and $3.7 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 ratemaking purposes when the completed projects are placed in service. During the years ended December 31, 2021, 2020 and 2019 AFUDC totaled $0.4 million, $0.7 million and $0.7 million, respectively, which 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 15, Leases, for additional information.

Jointly-owned Pipelines

Property, plant and equipment for our Florida natural gas transmission operation included $27.6 million of assets at December 31, 2021, which consist 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. The pipeline was placed in-service during the second quarter of 2020. Peninsula Pipeline's share of direct expenses for the jointly-owned pipeline are included in operating expenses of our consolidated statements of income. Accumulated depreciation for this pipeline totaled $0.9 million at December 31, 2021.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2021 and 2020, which consisted of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, previously jointly owned with Peoples Gas. Effective October 2020, the parties agreed to terminate the pre-existing ownership and capacity agreement and rescind their ownership interests in exchange for defined sections of the pipeline. This resulted in Peninsula Pipeline taking a 100% ownership in the northern end of the pipeline. Accumulated depreciation for this pipeline totaled $1.8 million and $1.7 million at December 31, 2021 and 2020, respectively.

Impairment of Long-lived Assets

We periodically evaluate whether events or circumstances have occurred, which indicate that other 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. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2021, 2020 and 2019:

	2021	2020	2019
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.5%	2.6%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.6%
Natural gas transmission – Florida	2.3%	2.3%	2.4%
Electric distribution	2.8%	2.9%	3.4%

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

We report certain depreciation and accretion in operations expense, rather than as a 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 expense 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, 2021, 2020 and 2019, we reported $10.2 million, $9.6 million and $8.8 million, respectively, of depreciation and accretion in operations expenses.

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 the 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, Regulated Operations, 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, except for two utilities that provide only unbundled delivery service (Chesapeake Utilities' Central Florida Gas division and FPU's Indiantown division). 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 delivery 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.

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 pandemics and 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 resulted in 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. 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.

During the first quarter of 2020, COVID-19 began to rapidly spread within the United States. Federal, state and local governments throughout the country imposed restrictions to promote social distancing to slow the spread of the virus, which has also had the effect of limiting commercial activity. These measures resulted in significant job losses and a slowing of economic activity across the United States and in the areas that we serve. We have considered the impact of COVID-19 on our receivables for the twelve months ended December 31, 2021, monitored developments that impact our customers’ ability to pay and have revised our estimates of expected credit losses to reflect these impacts.

(in thousands)
Balance at December 31, 2020	$	4,785
Additions:
Provision for credit losses	134
Recoveries	(125)
Deductions:
Write offs	(1,653)
Balance at December 31, 2021	$	3,141

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 was no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2021, 2020 or 2019.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible AssetsGoodwill 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 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 implied fair value. The testing of goodwill for the years ended December 31, 2021, 2020 and 2019 indicated no goodwill impairment. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

Other Deferred ChargesOther 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 CostAs 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 Prudential 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 assets.

We estimate the health care cost trend rates used in determining our postretirement net 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 recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is 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 sales” treatment under ASC Topic 815 Derivatives and Hedging, 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]

Recently Adopted Accounting Standards

There are no new accounting pronouncements issued that are applicable to us.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Property, Plant and Equipment [Table Text Block]

A summary of property, plant and equipment for continuing operations by classification as of December 31, 2021 and 2020 is provided in the following table:

	As of December 31,
(in thousands)	2021		2020
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	859,627	$	782,329
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	727,277		667,538
Electric distribution	133,383		127,710
Unregulated Energy
Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida	176,095		151,258
Natural gas transmission and supply – Ohio	112,050		87,962
Electricity and steam generation	36,740		36,521
Mobile CNG and pipeline solutions	32,374		24,905
Other	35,418		30,769
Total property, plant and equipment	2,112,964		1,908,992
Less: Accumulated depreciation and amortization	(417,479)		(368,743)
Plus: Construction work in progress	49,393		60,929
Net property, plant and equipment	$	1,744,878	$	1,601,178

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. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2021, 2020 and 2019:

	2021	2020	2019
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.5%	2.6%
Natural gas transmission – Delmarva Peninsula	2.7%	2.7%	2.6%
Natural gas transmission – Florida	2.3%	2.3%	2.4%
Electric distribution	2.8%	2.9%	3.4%

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, 2021

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,
	2021		2020		2019
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	83,467	$	70,642	$	61,100
Income/(Loss) from Discontinued Operations	(1)		856		4,053
Net Income	$	83,466	$	71,498	$	65,153
Weighted average shares outstanding	17,558,078		16,711,579		16,398,443
Earnings Per Share from Continuing Operations	$	4.75	$	4.23	$	3.73
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Basic Earnings Per Share	$	4.75	$	4.28	$	3.97
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	17,558,078		16,711,579		16,398,443
Effect of dilutive securities — Share-based compensation	74,951		59,156		50,043
Adjusted denominator — Diluted	17,633,029		16,770,735		16,448,486
Earnings Per Share from Continuing Operations	$	4.73	$	4.21	$	3.72
Earnings Per Share from Discontinued Operations	—		0.05		0.24
Diluted Earnings Per Share	$	4.73	$	4.26	$	3.96

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Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2021

Dec. 31, 2020

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

for the years ended December 31, 2021, 2020 and 2019:

	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 division	34,074		—		—		34,074
FPU electric distribution	78,300		—		—		78,300
FPU natural gas distribution	100,535		—		—		100,535
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 delivery operations	—		142,082		—		142,082
Energy delivery 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 (1)	$	383,920	$	206,869	$	(20,821)	$	569,968

    

(1) 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.

	For the year ended December 31, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	63,389	$	—	$	—	$	63,389
Florida natural gas division	30,850		—		—		30,850
FPU electric distribution	76,863		—		—		76,863
FPU natural gas distribution	90,150		—		—		90,150
Maryland natural gas division	21,853		—		—		21,853
Sandpiper natural gas/propane operations	17,214		—		—		17,214
Elkton Gas	2,399		—		—		2,399
Total energy distribution	302,718		—		—		302,718
Energy transmission
Aspire Energy	—		27,951		—		27,951
Aspire Energy Express	16		—		—		16
Eastern Shore	75,117		—		—		75,117
Peninsula Pipeline	23,080		—		—		23,080
Total energy transmission	98,213		27,951		—		126,164
Energy generation
Eight Flags	—		16,147		—		16,147
Propane operations
Propane delivery operations	—		100,744		—		100,744
Energy delivery services
Marlin Gas Services	—		7,818		—		7,818
Other and eliminations
Eliminations	(48,185)		(134)		(17,602)		(65,921)
Other	—		—		528		528
Total other and eliminations	(48,185)		(134)		(17,074)		(65,393)
Total operating revenues (1)	$	352,746	$	152,526	$	(17,074)	$	488,198

(1) Total operating revenues for the year ended December 31, 2020, include other revenue (revenues from sources other than contracts with customers of $1.4 million and $0.2 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 years ended December 31, 2019
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	62,659	$	—	$	—	$	62,659
Florida natural gas division	28,485		—		—		28,485
FPU electric distribution	77,416		—		—		77,416
FPU natural gas distribution	82,418		—		—		82,418
Maryland natural gas division	22,517		—		—		22,517
Sandpiper natural gas/propane operations	19,068		—		—		19,068
Total energy distribution	292,563		—		—		292,563
Energy transmission
Aspire Energy	—		32,493		—		32,493
Aspire Energy Express	—		—		—		—
Eastern Shore	72,924		—		—		72,924
Peninsula Pipeline	16,453		—		—		16,453
Total energy transmission	89,377		32,493		—		121,870
Energy generation
Eight Flags	—		16,749		—		16,749
Propane operations
Propane delivery operations	—		109,614		—		109,614
Energy delivery services
Marlin Gas Services	—		5,702		—		5,702
Other and eliminations
Eliminations	(38,934)		(10,407)		(18,081)		(67,422)
Other	—		—		529		529
Total other and eliminations	(38,934)		(10,407)		(17,552)		(66,893)
Total operating revenues (1)	$	343,006	$	154,151	$	(17,552)	$	479,605

(1) Total operating revenues for the year ended December 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 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, 2021 and 2020 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	4,816	$	644
Balance at 12/31/2021	56,277		4,806		747
Increase (decrease)	$	677	$	(10)	$	103

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Revenue for these businesses for the remaining performance obligations at December 31, 2021 are expected to be recognized as follows:

(in thousands)	2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	33,925	$	26,334	$	24,103	$	23,231	$	21,964	$	179,866
Natural gas distribution operations	6,747		6,174		5,946		5,410		5,179		33,543
FPU electric distribution	652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	41,324	$	33,160	$	30,701	$	28,916	$	27,418	$	213,959

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Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information, by Segment [Table Text Block]

The following table presents information about our reportable segments.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	381,879	$	350,853	$	340,857
Unregulated Energy	188,089		137,345		138,748
Total operating revenues, unaffiliated customers	$	569,968	$	488,198	$	479,605
Intersegment Revenues (1)
Regulated Energy	$	2,041	$	1,893	$	2,149
Unregulated Energy	18,780		15,181		15,403
Other businesses	527		528		529
Total intersegment revenues	$	21,348	$	17,602	$	18,081
Operating Income (Loss)
Regulated Energy	$	106,064	$	92,124	$	86,584
Unregulated Energy	24,382		20,664		19,938
Other businesses and eliminations	666		(65)		(237)
Operating Income	131,112		112,723		106,285
Other income (expense), net	1,721		3,222		(1,847)
Interest charges	20,135		21,765		22,224
Income from Continuing Operations before Income Taxes	112,698		94,180		82,214
Income Taxes on Continuing Operations	29,231		23,538		21,114
Income from Continuing Operations	83,467		70,642		61,100
Income (loss) from Discontinued Operations, Net of Tax	(1)		686		(1,349)
Gain on sale of Discontinued Operations, Net of tax	—		170		5,402
Net Income	$	83,466	$	71,498	$	65,153
Depreciation and Amortization
Regulated Energy	$	48,748	$	46,079	$	35,227
Unregulated Energy	13,869		11,988		10,130
Other businesses and eliminations	44		50		67
Total depreciation and amortization	$	62,661	$	58,117	$	45,424
Capital Expenditures
Regulated Energy	$	139,733	147,100		$	130,604
Unregulated Energy	81,651		46,295		60,034
Other businesses	6,425		2,480		8,348
Total capital expenditures	$	227,809	$	195,875	$	198,986

     

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

	As of December 31,
	2021		2020
Identifiable Assets
Regulated Energy segment	$	1,629,191	$	1,547,619
Unregulated Energy segment	439,114		347,665
Other businesses and eliminations	46,564		37,203
Total identifiable assets	$	2,114,869	$	1,932,487

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Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2021, 2020 and 2019 were as follows:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Cash paid for interest	$	20,809	$	22,884	$	23,856
Cash (received) paid for income taxes, net of refunds	$	8,395	$	(8,135)	$	3,221

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2021, 2020, and 2019 were as follows: 

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	16,164	$	23,625	$	13,470
Common stock issued for the Retirement Savings Plan	$	1,712	$	1,605	$	—
Common stock issued under the SICP	$	2,834	$	1,971	$	1,691

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of December 31, 2021, 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	21.2	Cash flow hedges	June, 2024
Sharp	Propane (gallons)	Sales	4.4	Cash flow hedges	December, 2022
Sharp	Propane (gallons)	Purchases	0.3	N/A	March 2022

Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]

(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,081	$	1,505

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, 2021 and 2020 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	16	$	—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	—		14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	7,060		3,255
Total Derivative Assets		$	7,076	$	3,269

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	743		64
Interest rate swap agreements	Derivative liabilities, at fair value	—		40
Total Derivative Liabilities		$	743	$	127

Derivative Instruments, Gain (Loss) [Table Text Block]

The effects of gains and losses from derivative instruments are as follows:

	Amount of Gain (Loss) on Derivatives:
	Location of Gain (Loss) on Derivatives	For the Year Ended December 31,
(in thousands)		2021		2020		2019
Derivatives not designated as hedging instruments
Propane swap agreements	Propane and natural gas costs	$	(1)	$	—	$	—
Derivatives designated as fair value hedges
Put/Call option	Propane and natural gas costs	(24)		(12)		—
Put/Call option	Propane inventory	—		34		—
Derivatives designated as cash flow hedges
Propane swap agreements	Revenues	(536)		—		—
Propane swap agreements	Propane and natural gas costs	7,187		2,428		1,520
Propane swap agreements	Other comprehensive income (loss)	3,126		5,035		(253)
Interest rate swap agreements	Interest expense	(28)		60		—
Interest rate swap agreements	Other comprehensive income (loss)	—		(40)		—
Natural gas swap contracts	Other comprehensive income (loss)	—		—		(63)
Natural gas futures contracts	Other comprehensive income (loss)	—		—		(294)
Total		$	9,724	$	7,505	$	910

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021 and 2020, respectively:

			Fair Value Measurements Using:
As of December 31, 2021	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	$	26	$	26	$	—	$	—
Investments—guaranteed income fund	2,036		—		—		2,036
Investments—mutual funds and other	10,033		10,033		—		—
Total investments	12,095		10,059		—		2,036
Derivative assets	7,076		—		7,076		—
Total assets	$	19,171	$	10,059	$	7,076	$	2,036
Liabilities:
Derivative liabilities	$	743	$	—	$	743	$	—

			Fair Value Measurements Using:
As of December 31, 2020	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	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

Schedule of Changes in Fair Value of Plan Assets

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

	For the Year Ended December 31,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	88		261
Transfers/disbursements	(241)		1,065
Investment income	33		27
Ending Balance	$	2,036	$	2,156

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Investments (Tables)

12 Months Ended

Dec. 31, 2021

Investments [Abstract]

Investments schedule [Table Text Block]

	As of December 31,
(in thousands)	2021		2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	12,069	$	10,755
Investments in equity securities	26		21
Total	$	12,095	$	10,776

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Schedule of Carrying Value of Goodwill

The carrying value of goodwill from continuing operations as of December 31, 2021 and 2020 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731
Additions (1)	72		5,905		5,977
Balance at December 31, 2021	$	7,689	$	37,019	$	44,708

(1)Includes goodwill from the purchase of operating assets of Diversified Energy in December 2021 and Elkton Gas in the third quarter of 2020.

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, 2021 and 2020 are as follows:

	As of December 31,
	2021				2020
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	16,814	$	5,125	$	10,680	$	4,269
Non-Compete agreements (1)	2,431		1,078		2,375		768
Patents	452		354		452		236
Other	270		218		270		212
Total	$	19,967	$	6,775	$	13,777	$	5,485

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

The following tables provide: (a) the components of income tax expense in 2021, 2020, and 2019; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2021, 2020, and 2019 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2021 and 2020.

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Current Income Tax Expense
Federal	$	2,775	$	(2,777)	$	(2,252)
State	(96)		2,162		(491)
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	2,632		(662)		(2,790)
Deferred Income Tax Expense (1)
Property, plant and equipment	24,074		23,224		25,907
Deferred gas costs	1,857		(714)		79
Pensions and other employee benefits	(655)		(75)		(454)
FPU merger-related premium cost and deferred gain	(351)		156		(278)
Net operating loss carryforwards	97		5,107		(3,772)
Other	1,577		(3,498)		2,422
Total deferred income tax expense	26,599		24,200		23,904
Income Tax Expense from Continuing Operations	29,231		23,538		21,114
Income Tax Expense from Discontinued Operations	—		153		1,416
Total Income Tax	$	29,231	$	23,691	$	22,530

(1) Includes $8.2 million, $4.9 million, and $4.7 million of deferred state income taxes for the years 2021, 2020 and 2019, respectively.

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates

	For the Year Ended December 31,
	2021			2020			2019
(in thousands)
Reconciliation of Effective Income Tax Rates from Continuing Operations
Federal income tax expense (1)	$	23,666		$	19,778		$	17,264
State income taxes, net of federal benefit	6,371			5,051			5,093
ESOP dividend deduction	(180)			(218)			(173)
CARES Act Tax Benefit	(919)			(1,841)			—
Depreciation	(15)			—			—
Other	308			768			(1,070)
Total Income Tax Expense from Continuing Operations	$	29,231		$	23,538		$	21,114
Effective Income Tax Rate from Continuing Operations	25.94		%	24.99		%	25.65		%

(1) Federal income taxes were calculated at 21 percent for 2021, 2020, and 2019.

Schedule of Accumulated Deferred Income Tax Assets and Liabilities

	As of December 31,
	2021		2020
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	224,034	$	199,287
Acquisition adjustment	6,266		6,618
Loss on reacquired debt	183		201
Deferred gas costs	2,366		509
Natural gas conversion costs	5,529		5,379
Storm reserve liability	5,783		7,073
Other	6,301		5,587
Total deferred income tax liabilities	250,462		224,654
Deferred income tax assets:
Pension and other employee benefits	5,354		4,636
Environmental costs	996		1,064
Net operating loss carryforwards	1,490		1,587
Storm reserve liability	448		409
Accrued expenses	4,843		6,153
Other	3,781		5,417
Total deferred income tax assets	16,912		19,266
Deferred Income Taxes Per Consolidated Balance Sheets	$	233,550	$	205,388

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2021		2020
Uncollateralized Senior Notes:
5.93% note, due October 31, 2023	$	6,000	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	14,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
2.49% notes Due January 25, 2037	50,000		—
Equipment security note
2.46% note, due September 24, 2031	9,378		—
Less: debt issuance costs	(913)		(901)
Total long-term debt	567,865		522,099
Less: current maturities	(17,962)		(13,600)
Total long-term debt, net of current maturities	$	549,903	$	508,499

Schedule of Maturities of Long-term Debt [Table Text Block]

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

Year	2022		2023		2024		2025		2026		Thereafter		Total
(in thousands)
Payments	$	17,962	$	21,483	$	18,505	$	25,528	$	34,551	$	450,749	$	568,778

Line of Credit Facility [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

The following table summarizes our shelf agreements at December 31, 2021:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		(50,000)		100,000
Total	$	520,000	$	(220,000)	$	(50,000)	$	250,000

(1) The Prudential and MetLife Shelf Agreements expire in April 2023 and May 2023, respectively.

(2) Unfunded commitments of $50 million reflects Senior Notes expected to be issued on or before March 15, 2022..

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Lease, Cost [Table Text Block]

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	2021		2020
Operating lease cost (1)	Operations expense	$	2,064	$	2,029

(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 sheet at December 31, 2021 and 2020:

(in thousands)	Balance sheet classification	December 31, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,139	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,996	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,571		9,872
Total lease liabilities		$	10,567	$	11,619

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, 2021 and 2020:

	December 31, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.10		8.70
Weighted-average discount rate
Operating leases	3.6	%	3.8	%

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, 2021 and 2020:

	Year Ended December 31,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	1,996	$	1,956

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

The following table presents the future undiscounted maturities of our operating leases at December 31, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2022	$	2,019
2023	1,902
2024	1,672
2025	1,341
2026	885
Thereafter	3,668
Total lease payments	11,487
Less: Interest	(920)
Present value of lease liabilities	$	10,567

(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, 2021

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the years ended December 31, 2021 and 2020. 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, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income (loss) before reclassifications	(578)		5,400		16		4,838
Amounts reclassified from accumulated other comprehensive income (loss)	365		(1,757)		(44)		(1,436)
Net current-period other comprehensive income (loss)	(213)		3,643		(28)		3,402
As of December 31, 2020	(5,146)		2,309		(28)		(2,865)
Other comprehensive income before reclassifications	262		7,075		—		7,337
Amounts reclassified from accumulated other comprehensive income (loss)	1,616		(4,813)		28		(3,169)
Net current-period other comprehensive income	1,878		2,262		28		4,168
As of December 31, 2021	$	(3,268)	$	4,571	$	—	$	1,303

Reclassification out of Accumulated Other Comprehensive Income

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2021, 2020 and 2019. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	For the Year Ended December 31,
(in thousands)	2021		2020		2019
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(2,243)		(592)		(2,600)
Total before income taxes	(2,166)		(515)		(2,523)
Income tax benefit (4)	550		150		656
Net of tax	$	(1,616)	$	(365)	$	(1,867)
Gains on commodity contracts cash flow hedges
Propane swap agreements (2)	$	6,651	$	2,428	$	1,520
Natural gas swaps (2)(3)	—		—		7
Natural gas futures (2)(3)	—		—		2,096
Total before income taxes	6,651		2,428		3,623
Income tax expense (4)	(1,838)		(671)		(1,028)
Net of tax	$	4,813	$	1,757	$	2,595
Gains and (losses) on interest rate swap cash flow hedges:
Interest rate swap agreements	$	(28)	$	60	$	—
Total before income taxes	(28)		60		—
Income tax expense (4)	—		(16)		—
Net of tax	$	(28)	$	44	$	—
Total reclassifications for the period	$	3,169	$	1,436	$	728

(1) These amounts are included in the computation of net periodic benefits. See Note 17, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details.

(3) PESCO's results are reflected as discontinued operations in our consolidated statements of income.

(4) The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2021

Schedule of Assets by Investment Type

The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2021, 2020 and 2019:

	FPU Pension Plan
At December 31,	2021		2020		2019
Asset Category
Equity securities	52	%	54	%	53	%
Debt securities	38	%	37	%	37	%
Other	10	%	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 (this allocation range applied to the Chesapeake Pension Plan prior to the de-risking strategy executed during the fourth quarter of 2019):

Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	4	%	10	%
Cash	0	%	5	%

Summary of Pension Plan Assets

At December 31, 2021 and 2020, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:

	Fair Value Measurement Hierarchy
	At December 31, 2021								At December 31, 2020
Asset Category	Level 1		Level 2		Level 3		Total		Level 1		Level 2		Level 3		Total
(in thousands)
Mutual Funds - Equity securities
U.S. Large Cap (1)	$	4,302	$	—	$	—	$	4,302	$	3,615	$	—	$	—	$	3,615
U.S. Mid Cap (1)	1,835		—		—		1,835		1,672		—		—		1,672
U.S. Small Cap (1)	954		—		—		954		891		—		—		891
International (2)	10,863		—		—		10,863		11,307		—		—		11,307
Alternative Strategies (3)	5,888		—		—		5,888		5,586		—		—		5,586
	23,842		—		—		23,842		23,071		—		—		23,071
Mutual Funds - Debt securities
Fixed income (4)	19,551		—		—		19,551		21,563		—		—		21,563
High Yield (4)	3,014		—		—		3,014		2,606		—		—		2,606
	22,565		—		—		22,565		24,169		—		—		24,169
Mutual Funds - Other
Commodities (5)	2,297		—		—		2,297		2,246		—		—		2,246
Real Estate (6)	2,729		—		—		2,729		1,954		—		—		1,954
Guaranteed deposit (7)	—		—		497		497		—		—		1,019		1,019
	5,026		—		497		5,523		4,200		—		1,019		5,219
Total Pension Plan Assets in fair value hierarchy	$	51,433	$	—	$	497	51,930		$	51,440	$	—	$	1,019	52,459
Investments measured at net asset value (8)							6,782								8,116
Total Pension Plan Assets							$	58,712							$	60,575

Schedule of Level Three Defined Benefit Plan Assets Roll Forward

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2021 and 2020:

	For the Year Ended December 31,
	2021		2020
(in thousands)
Balance, beginning of year	$	1,019	$	1,147
Purchases	3,160		3,190
Transfers in	5,914		921
Disbursements	(9,587)		(4,290)
Investment income	(9)		51
Balance, end of year	$	497	$	1,019

Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets

The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive loss or as a regulatory asset as of December 31, 2021:

(in thousands)	FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service (credit)	$	—	$	—	$	(293)	$	—	$	(293)
Net loss (gain)	17,737		659		671		(114)		18,953
Total	$	17,737	$	659	$	378	$	(114)	$	18,660
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,370	$	659	$	378	$	(22)	$	4,385
Post-merger regulatory asset	14,367		—		—		(92)		14,275
Total unrecognized cost	$	17,737	$	659	$	378	$	(114)	$	18,660

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2021 is net of income tax benefits of $1.1 million.

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)
2022	$	3,451	$	151	$	73	$	71
2023	$	3,537	$	149	$	68	$	70
2024	$	3,592	$	147	$	63	$	71
2025	$	3,690	$	160	$	59	$	70
2026	$	3,720	$	157	$	54	$	69
Years 2027 through 2031	$	18,588	$	723	$	218	$	324

(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, 2021 and 2020 and the net periodic cost for the years ended December 31, 2021, 2020 and 2019 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2021			2020			2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,146		$	6,214		$	70,366		$	65,304		$	2,212		$	2,157
Interest cost	141			176			1,714			2,085			48			63
Actuarial (gain) loss	(371)			450			(1,953)			6,069			(12)			144
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Benefit obligation — end of year	—			6,146			67,030			70,366			2,096			2,212
Change in plan assets:
Fair value of plan assets — beginning of year	4,609			4,630			55,966			49,703			—			—
Actual return on plan assets	(237)			369			4,246			6,581			—			—
Employer contributions	1,544			304			1,597			2,774			152			152
Effect of settlement	(5,884)			(612)			—			—			—			—
Benefits paid	(32)			(82)			(3,097)			(3,092)			(152)			(152)
Fair value of plan assets — end of year	—			4,609			58,712			55,966			—			—
Reconciliation:
Funded status	—			(1,537)			(8,318)			(14,400)			(2,096)			(2,212)
Accrued pension cost	$	—		$	(1,537)		$	(8,318)		$	(14,400)		$	(2,096)		$	(2,212)
Assumptions:
Discount rate	2.50		%	2.25		%	2.75		%	2.50		%	2.50		%	2.25		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	—		%	—		%

Component of Net Periodic Pension Cost (Benefit)

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2021(2)			2020			2019(1)			2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic pension cost:
Interest cost	$	141		$	176		$	375		$	1,714		$	2,085		$	2,452		$	48		$	63		$	74
Expected return on assets	(166)			(157)			(487)			(3,306)			(2,967)			(2,770)			—			—			—
Amortization of actuarial loss	257			243			391			612			552			505			28			20			85
Settlement expense	1,810			203			1,982			—			—			—			—			—			58
Net periodic pension cost	2,042			465			2,261			(980)			(330)			187			76			83			217
Amortization of pre-merger regulatory asset	—			—			—			—			—			543			—			—			—
Total periodic cost	$	2,042		$	465		$	2,261		$	(980)		$	(330)		$	730		$	76		$	83		$	217
Assumptions:
Discount rate	2.25		%	3.00		%	3.00		%	2.50		%	3.25		%	4.25		%	2.25		%	3.00		%	4.00		%
Expected return on plan assets	3.50		%	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	—		%	—		%	—		%

Other Postretirement Benefit Plans

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following table sets forth the funded status at December 31, 2021 and 2020:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2021			2020			2021			2020
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,033		$	1,100		$	1,009		$	1,224
Interest cost	22			26			24			30
Plan participants contributions	190			166			29			37
Actuarial loss (gain)	159			(34)			71			(181)
Benefits paid	(470)			(225)			(129)			(101)
Benefit obligation — end of year	934			1,033			1,004			1,009
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	280			59			100			64
Plan participants contributions	190			166			29			37
Benefits paid	(470)			(225)			(129)			(101)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(934)			(1,033)			(1,004)			(1,009)
Accrued postretirement cost	$	(934)		$	(1,033)		$	(1,004)		$	(1,009)
Assumptions:
Discount rate	2.83		%	2.25		%	2.51		%	2.50		%

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for 2021, 2020, and 2019 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2021			2020			2019			2021			2020			2019
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	22		$	26		$	39		$	24		$	30		$	48
Amortization of actuarial loss (gain)	34			24			46			(9)			(19)			—
Amortization of prior service cost	(77)			(77)			(77)			—			—			—
Net periodic cost	(21)			(27)			8			15			11			48
Amortization of pre-merger regulatory asset	—			—			—			—			6			8
Total periodic cost	$	(21)		$	(27)		$	8		$	15		$	17		$	56
Assumptions
Discount rate	2.25		%	3.00		%	4.00		%	2.50		%	3.25		%	4.25		%

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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2021

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, 2021, 2020 and 2019:

	For the Year Ended December 31,
	2021		2020		2019
(in thousands)
Awards to non-employee directors	$	782	$	733	$	620
Awards to key employees	5,163		4,096		3,659
Total compensation expense	5,945		4,829		4,279
Less: tax benefit	(1,535)		(1,254)		(1,117)
Share-based compensation amounts included in net income	$	4,410	$	3,575	$	3,162

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 to taxing authorities:

	For the Year Ended December 31,
	2021		2020		2019
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	14,020		10,319		7,635
Amounts remitted to tax authorities to satisfy obligations	$	1,478	$	977	$	692

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, 2019	157,817	$	80.28
Granted	70,014	91.89
Vested	(35,651)	66.48
Expired	(5,302)	65.32
Outstanding — December 31, 2020	186,878	87.06
Granted	69,903	100.76
Vested	(53,147)	76.31
Expired	(852)	74.85
Forfeited (1)	(5,384)	$	93.39
Outstanding — December 31, 2021	197,398	$	94.15

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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, 2021

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, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,591	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,840	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,656	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,032	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,189	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$271	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,237	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,091	$1,124	PSC approved amortization of ADIT in March 2018.

Schedule of Regulatory Assets [Table Text Block]

At December 31, 2021 and 2020, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets. 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,
	2021		2020
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	9,199	$	2,078
Under-recovered GRIP revenue (2)	2,101		278
Deferred postretirement benefits (3)	16,749		17,716
Deferred conversion and development costs (1)	23,383		23,054
Environmental regulatory assets and expenditures (4)	1,258		1,743
Acquisition adjustment (5)	27,182		28,756
Loss on reacquired debt (6)	721		795
Deferred costs associated with COVID-19 (7)	2,289		1,925
Deferred storm costs (8)	36,004		44,320
Other	5,081		3,927
Total Regulatory Assets	$	123,967	$	124,592
Regulatory Liabilities
Self-insurance (9)	$	563	$	533
Over-recovered purchased fuel and conservation cost recovery (1)	1,073		4,422
Over-recovered GRIP revenue (2)	11		338
Storm reserve (9)	2,829		2,673
Accrued asset removal cost (10)	47,887		45,315
Deferred income taxes due to rate change (11)	88,804		90,845
Interest related to storm recovery (8)	2,146		3,353
Other	1,487		1,541
Total Regulatory Liabilities	$	144,800	$	149,020

(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) 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’ Central Florida Gas division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

(3) 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 17, Employee Benefit Plans, for additional information.

(4) All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 20, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

(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.

(6) Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

(7) 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.

(8) 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.

(9) 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.

(10) See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

(11) 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 12, Income Taxes, for additional information.

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Environmental Commitments and Contingencies Environmental Remediation Status (Tables)

12 Months Ended

Dec. 31, 2021

Environmental Remediation Obligations [Abstract]

Schedule of Environmental Loss Contingencies by Site [Table Text Block]

The following is a summary of our remediation status and estimated costs to implement clean-up of our West Palm Beach Florida site:

Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected be completed in 2022.	Between $3.3 million to $14.2 million, including costs associated with the relocation of FPU’s operations at this site, and any potential costs associated with future redevelopment of the properties.

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Other Commitments and Contingencies Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2021

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	2022		2023-2024		2025-2026		Beyond 2026		Total
(in thousands)
Purchase Obligations	$	89,557	$	82,412	$	70,114	$	174,203	$	416,286

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2021

Text Block [Abstract]

Schedule of Quarterly Financial Information

Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.

	For the Quarters Ended
	March 31		June 30		September 30		December 31
(in thousands except per share amounts)
2020 (1)
Operating Revenues	$	152,690	$	97,051	$	101,419	$	137,038
Operating Income	$	42,134	$	17,977	$	17,406	$	35,206
Net Income:
Income from Continuing Operations	$	29,041	$	10,661	$	9,280	$	21,661
Earnings/(Loss) from Discontinued Operations, Net of Tax	(111)		125		(19)		691
Gain on sale of Discontinued Operations, Net of Tax	—		170		—		—
Net Income	$	28,930	$	10,956	$	9,261	$	22,352
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.65	$	0.56	$	1.23
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		0.02		—		0.04
Basic Earnings Per Share of Common Stock	$	1.76	$	0.67	$	0.56	$	1.27
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.64	$	0.56	$	1.22
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		0.02		—		0.04
Diluted Earnings Per Share of Common Stock	$	1.76	$	0.66	$	0.56	$	1.26
2019 (1)
Operating Revenues	$	160,464	$	94,542	$	92,626	$	131,974
Operating Income	$	44,122	$	18,165	$	14,357	$	29,641
Net Income:
Income from Continuing Operations	$	28,811	$	8,914	$	6,251	$	17,123
Earnings/(Loss) from Discontinued Operations, Net of Tax	(148)		(610)		(630)		39
Gain on sale of Discontinued Operations, Net of Tax	—		—		—		5,402
Net Income	$	28,663	$	8,304	$	5,621	$	22,564
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.76	$	0.54	$	0.38	$	1.05
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		(0.03)		(0.04)		0.33
Basic Earnings Per Share of Common Stock	$	1.75	$	0.51	$	0.34	$	1.38
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.75	$	0.54	$	0.38	$	1.04
Earnings/(Loss) Per Share from Discontinued Operations	(0.01)		(0.04)		(0.04)		0.33
Diluted Earnings Per Share of Common Stock	$	1.74	$	0.50	$	0.34	$	1.37

(1) The sum of the four quarters does not equal the total for the year due to rounding.

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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, 2021 USD ($) mi	Dec. 31, 2020 USD ($) mi	Dec. 31, 2019 USD ($)
Property, Plant and Equipment [Line Items]
Contributions in Aid of Construction	$ 6,300	$ 3,700
Public Utilities, Allowance for Funds Used During Construction, Description	$ 400	700	$ 700
Number of Months to Establish ROU Asset and Liability	12 months
Property, plant and equipment
Total property, plant and equipment	$ 2,112,964	1,908,992
Less: Accumulated depreciation and amortization	(417,479)	(368,743)
Net property, plant and equipment	1,744,878	1,601,178
Construction Work in Progress	49,393	60,929
Jointly Owned Pipeline [Member]
Property, plant and equipment
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	900
Natural Gas
Property, plant and equipment
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	1,800	1,700
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	859,627	782,329
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	727,277	667,538
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	112,050	87,962
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	133,383	127,710
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	176,095	151,258
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	36,740	36,521
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	32,374	24,905
Other
Property, plant and equipment
Total property, plant and equipment	$ 35,418	$ 30,769
Natural Gas Operations
Property, plant and equipment
Miles Of Natural Gas Pipeline | mi	26	16
Jointly Owned Pipeline [Member]
Property, plant and equipment
Net property, plant and equipment	$ 27,600
Natural gas distribution operations [Member]
Property, plant and equipment
Net property, plant and equipment	$ 6,700

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) utility mi	Dec. 31, 2020 USD ($) mi	Dec. 31, 2019 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Operating Lease, Liability	$ 10,567
Number of Utilities that do not have cost recovery mechanism	1
Delay of Revenue Recognition Due To Implementation of New Standard | utility	2
Maturity Period To Be Considered Cash Equivalents	3 months
Contributions or Advances in Aid of Construction	$ 6,300	$ 3,700
Net property, plant and equipment	1,744,878	1,601,178
Accumulated depreciation	417,479	368,743
Depreciation and accretion reported in operations expenses	10,200	9,600	$ 8,800
Operating Lease, Right-of-Use Asset	$ 10,139	$ 11,194
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Length of pipeline | mi	26	16
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, 2021	Dec. 31, 2020	Dec. 31, 2019
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	2.50%	2.50%	2.60%
Natural gas transmission | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.70%	2.70%	2.60%
Natural gas transmission | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.30%	2.30%	2.40%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.80%	2.90%	3.40%

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Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2021
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, 2021	Dec. 31, 2020
Accounting Policies [Abstract]
Additions, Charged to Income	$ 134
Additions, Other Accounts	(125)
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	(1,653)
Accounts Receivable, Allowance for Credit Losses, Current, Disclosure	$ 3,141	$ 4,785

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Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent									$ 83,467	$ 70,642	$ 61,100
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax										$ 856	$ 4,053
Income (Loss) from Continuing Operations, Per Basic Share									$ 4.75	$ 4.23	$ 3.73
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share									$ 0	$ 0.05	$ 0.24
Calculation of Basic Earnings Per Share:
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	$ 83,466	$ 71,498	$ 65,153
Weighted shares outstanding - Basic (in shares)									17,558,078	16,711,579	16,398,443
Basic Earnings Per Share (in usd per share)	$ 1.27	$ 0.56	$ 0.67	$ 1.76	$ 1.38	$ 0.34	$ 0.51	$ 1.75	$ 4.75	$ 4.28	$ 3.97
Calculation of Diluted Earnings Per Share:
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	$ 83,466	$ 71,498	$ 65,153
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									17,558,078	16,711,579	16,398,443
Share-based Compensation									74,951	59,156	50,043
Adjusted denominator — Diluted									17,633,029	16,770,735	16,448,486
Income (Loss) from Continuing Operations, Per Diluted Share									$ 4.73	$ 4.21	$ 3.72
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share									0	0.05	0.24
Diluted (in usd per share)	$ 1.26	$ 0.56	$ 0.66	$ 1.76	$ 1.37	$ 0.34	$ 0.50	$ 1.74	$ 4.73	$ 4.26	$ 3.96

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Acquisitions - Additional Information (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2021 USD ($)	Sep. 30, 2021 USD ($)	Jun. 30, 2021 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($) Dekatherm	Dec. 31, 2019 USD ($)
Cash paid for acquisition									$ 36,371	$ 22,231	$ 23,988
Revenues									569,968	488,198	479,605
Operating Income (Loss)									131,112	112,723	106,285
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	83,466	71,498	65,153
Elkton Gas [Member]
Revenues									7,105	$ 2,399
Marlin Gas Services [Member]
Additional Compressed Natural Gas Deliverability | Dekatherm										7,000
Regulated Energy [Member]
Operating Income (Loss)									106,064	$ 92,124	86,584
Regulated Energy [Member] | Elkton Gas [Member]
Operating Income (Loss)									$ 1,000	418
Number of customers acquired through acquisition									7,000
Business Combination, Consideration Transferred									$ 15,600
Business Combination, Working Capital	600								600
Property, Plant and Equipment, Acquired During Period	15,900								15,900
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	2,600								2,600
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Regulatory Liabilities									2,600
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	4,300								4,300
Unregulated Energy
Operating Income (Loss)									24,382	20,664	$ 19,938
Unregulated Energy | Western Natural Gas [Member]
Revenues									2,594	555
Operating Income (Loss)									550	$ 120
Business Combination, Consideration Transferred									6,700
Business Combination, Working Capital	300								300
Property, Plant and Equipment, Acquired During Period	3,500								3,500
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	1,800								1,800
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	1,400								1,400
Unregulated Energy | Diversified Energy
Revenues									1,423
Operating Income (Loss)									$ 300
Number of customers acquired through acquisition									19,000
Business Combination, Consideration Transferred									$ 37,500
Business Combination, Working Capital	1,700								1,700
Business Combination, Contingent Consideration, Liability	2,100								2,100
Property, Plant and Equipment, Acquired During Period	23,100								23,100
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	5,900								5,900
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	6,200								6,200
Business Acquisition, Preacquisition Contingency, Amount of Settlement	$ 800								$ 800
Gallons acquired through acquisition									10,000,000

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Acquisitions Divestitures (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts Receivable, before Allowance for Credit Loss, Current		$ 61,623	$ 61,675
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		(417,479)	(368,743)
Discontinued Operation, Tax Effect of Discontinued Operation		0	(153)	$ (1,416)
Disposal Group, Including Discontinued Operation, Assets, Current		173,135	136,431
Deferred Income Tax Expense (Benefit)	[1]	26,599	24,200	23,904
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		$ 0	$ 170	$ 5,402

[1] (1) Includes $8.2 million, $4.9 million, and $4.7 million of deferred state income taxes for the years 2021, 2020 and 2019, respectively.

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Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 56,277	$ 55,600
Contract with Customer, Asset, Net, Noncurrent	4,806	4,816
Contract with Customer, Liability, Current	747	644
Increase (Decrease) in Receivables	677
Increase (Decrease) in Other Noncurrent Assets	(10)
Increase (Decrease) in Other Current Liabilities	103
Contract with Customer, Liability, Revenue Recognized	$ 1,100	$ 1,300

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Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020		Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Revenues	$ 569,968		$ 488,198		$ 479,605
Revenue from Contract with Customer, Excluding Assessed Tax	569,968	[1]	488,198	[2]	479,605	[3]
Contract with Customer, Liability, Revenue Recognized	1,100		1,300
Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(20,821)	[1]	(17,074)	[2]	(17,552)	[3]
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	527		528		529
Other [Member] | Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	527		528		529
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	141,891		126,164		121,870
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(75,903)		(65,921)		(67,422)
Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(21,348)		(17,602)		(18,081)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	383,920	[1]	352,746	[2]	343,006	[3]
Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	334,404		302,718		292,563
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	103,728		98,213		89,377
Regulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(54,212)		(48,185)		(38,934)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	206,869	[1]	152,526	[2]	154,151	[3]
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	38,163		27,951		32,493
Unregulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(343)		(134)		(10,407)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues	200		1,400		(100)
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues	400		200		300
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34,074		30,850		62,659
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	71,195		63,389		28,485
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	78,300		76,863		77,416
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	100,535		90,150		82,418
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	22,449		21,853		22,517
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	20,746		17,214		19,068
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	38,163		27,951		32,493
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	76,911		75,117		72,924
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	26,630		23,080		16,453
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,652		16,147		16,749
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	142,082		100,744		109,614
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	8,315		7,818		5,702
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(75,376)		(65,393)		(66,893)
Eliminations [Member] | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(20,821)		(17,074)		(17,552)
Eliminations [Member] | Regulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(54,212)		(48,185)		(38,934)
Eliminations [Member] | Unregulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(343)		(134)		$ (10,407)
Aspire Energy Express | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	187		16
Elkton Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 7,105		$ 2,399

[1] 1) 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

[2] (1) Total operating revenues for the year ended December 31, 2020, include other revenue (revenues from sources other than contracts with customers of $1.4 million and $0.2 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) Total operating revenues for the year ended December 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 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, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 33,925
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,747
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | 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]: 2020-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 41,324
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 26,334
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 6,174
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | 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]: 2021-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 33,160
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 24,103
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 5,946
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | 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]: 2022-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 30,701
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 23,231
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 5,410
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | 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]: 2023-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 28,916
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	$ 21,964
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	$ 5,179
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	$ 275
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	$ 27,418
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	$ 179,866
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
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	$ 33,543
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
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	$ 550
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
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	$ 213,959

XML

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										$ 569,968	$ 488,198	$ 479,605
Intersegment Revenues (1)
Total intersegment revenues										569,968	488,198	479,605
Operating Income
Operating Income										131,112	112,723	106,285
Other income										1,721	3,222	(1,847)
Interest charges										20,135	21,765	22,224
Income Before Income taxes										112,698	94,180	82,214
Income Taxes on Continuing Operations										29,231	23,538	21,114
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent										83,467	70,642	61,100
Net Income		$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	83,466	71,498	65,153
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent										(1)	686	(1,349)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax										0	170	5,402
Depreciation and Amortization
Total depreciation and amortization										62,661	58,117	45,424
Identifiable Assets
Total identifiable assets		2,114,869				1,932,487				2,114,869	1,932,487
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax										(1)	686	(1,349)
Regulated Energy
Operating Income
Operating Income										106,064	92,124	86,584
Depreciation and Amortization
Total depreciation and amortization										48,748	46,079	35,227
Payments to Acquire Productive Assets										139,733	147,100	130,604
Unregulated Energy
Operating Income
Operating Income										24,382	20,664	19,938
Depreciation and Amortization
Total depreciation and amortization										13,869	11,988	10,130
Payments to Acquire Productive Assets										81,651	46,295	60,034
Other
Operating Income
Operating Income										666	(65)	(237)
Depreciation and Amortization
Payments to Acquire Productive Assets										6,425	2,480	8,348
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization										44	50	67
Total for Segments [Member]
Depreciation and Amortization
Payments to Acquire Productive Assets										227,809	195,875	198,986
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										569,968	488,198	479,605
Intersegment Revenues (1)
Total intersegment revenues										569,968	488,198	479,605
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										381,879	350,853	340,857
Intersegment Revenues (1)
Total intersegment revenues										381,879	350,853	340,857
Identifiable Assets
Total identifiable assets		1,629,191				1,547,619				1,629,191	1,547,619
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										188,089	137,345	138,748
Intersegment Revenues (1)
Total intersegment revenues										188,089	137,345	138,748
Identifiable Assets
Total identifiable assets		439,114				347,665				439,114	347,665
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									21,348	17,602	18,081
Intersegment Revenues (1)
Total intersegment revenues	[1]									21,348	17,602	18,081
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										2,041	1,893	2,149
Intersegment Revenues (1)
Total intersegment revenues										2,041	1,893	2,149
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										18,780	15,181	15,403
Intersegment Revenues (1)
Total intersegment revenues										18,780	15,181	15,403
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										527	528	529
Intersegment Revenues (1)
Total intersegment revenues										527	528	$ 529
Other And Intersegment Eliminations
Identifiable Assets
Total identifiable assets		$ 46,564				$ 37,203				$ 46,564	$ 37,203

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

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Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 20,809	$ 22,884	$ 23,856
Cash paid for income taxes	$ 8,395	$ (8,135)	$ 3,221

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Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 16,164	$ 23,625	$ 13,470
Non Cash Performance Incentive Plan DRP	1,712	1,605	0
Performance Incentive Plan	$ 2,834	$ 1,971	$ 1,691

XML

Derivative Instruments - Additional Information (Detail) $ in Thousands, gal in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2021 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2021 USD ($) gal	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		$ 743	$ 743	$ 127
Unrealized Gain (Loss) on Derivatives			9,724	7,505	$ 910
Notional Amount of Nonderivative Instruments		$ 60,000	$ 30,000	100,000
Number of short-term lines of Credit, rate swap			3
Subsequent Event
Derivative [Line Items]
Notional Amount of Nonderivative Instruments	$ 40,000
Fixed Swap Rate	0.17%
Interest Rate Swap Rate, Low Range [Member]
Derivative [Line Items]
Fixed Swap Rate		0.20%	0.2615%
Interest Rate Swap Rate, High Range [Member]
Derivative [Line Items]
Fixed Swap Rate		0.205%	0.3875%
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Put Option
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current				23
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		$ 743	$ 743	64
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		0	0	40
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			3,600
Other Payables to Broker-Dealers and Clearing Organizations		$ 4,081	$ 4,081	1,505
Derivative, Nonmonetary Notional Amount, Volume | gal			0.3
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			$ 0	0	(294)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			0	0	(63)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			3,126	5,035	(253)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			0	(40)
Cost of Sales [Member] | Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			(1)	0	0
Cost of Sales [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			7,187	2,428	1,520
Cost of Sales [Member] | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			(24)	(12)	$ 0
Inventories [Member] | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			$ 0	34
Interest Expense | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net				$ 60

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 7,076	$ 3,269
Energy Marketing Contract Liabilities, Current	743	127
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	743	64
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	0	40
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	7,060	3,255
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Put Option
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 16	14
Energy Marketing Contract Liabilities, Current		$ 23

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current	$ 743	$ 127
Gain (Loss) on derivatives	9,724	7,505	$ 910
Cost of Sales | Derivatives not designated as hedging instruments | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(1)	0	0
Cost of Sales | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(24)	(12)	0
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	7,187	2,428	1,520
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	0	0	(294)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	3,126	5,035	(253)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	0	0	$ (63)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	0	(40)
Interest Expense | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		60
Inventories [Member] | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	34
Revenues | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(536)
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	743	64
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	$ 0	$ 40

XML

Derivative Instruments Volume of Derivative Activity (Details) - Sharp Energy Inc [Member]	12 Months Ended
	Dec. 31, 2021 gal
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	300,000
Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	21,200,000
Swap Sales
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	4,400,000

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 568.8	$ 523.0
Fair value of long-term debt	$ 597.2	$ 548.5

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Assets:
Investments	$ 12,095	$ 10,776
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	10,059	8,620
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	7,076	3,269
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	743	127
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	2,036	2,156
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	26	21
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	2,036	2,156
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	10,033	8,599
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	10,059	8,620
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	2,036	2,156
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	7,076	3,269
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	19,171	14,045
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	743	127
Fair Value | Equity Securities [Member]
Assets:
Investments	26	21
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	2,036	2,156
Fair Value | Other Investments [Member]
Assets:
Investments	10,033	8,599
Fair Value | Investments [Member]
Assets:
Investments	12,095	10,776
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 7,076	$ 3,269

XML

Fair Value of Financial Instruments Fair Value of Financial Instruments - Summary of Changes in Fair Value of Instruments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 2,156	$ 803
Purchases and adjustments	88	261
Transfers/disbursements	241	(1,065)
Investment income	33	27
Ending Balance	$ 2,036	$ 2,156

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Investments - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Investments [Abstract]
Unrealized gain, net of other expenses	$ 1.5	$ 1.5	$ 1.6

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Investments - Schedule of Investment (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Investment [Line Items]
Investments, Fair Value Disclosure	$ 12,095	$ 10,776
Rabbi Trust Associated With Deferred Compensation [Member]
Investment [Line Items]
Investments, Fair Value Disclosure	12,069	10,755
Fair Value, Inputs, Level 1 [Member] | Investments in equity securities
Investment [Line Items]
Investments, Fair Value Disclosure	$ 26	$ 21

XML

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 19,967	$ 13,777
Acquired finite-lived intangible assets, weighted average useful life		12 years
Goodwill		$ 44,708	38,731
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		1,400
Amortization of intangible assets		1,300	1,200	$ 800
Amortization of intangible assets, 2020		1,100
Amortization of intangible assets, 2019		1,300
Regulated Energy
Goodwill [Line Items]
Goodwill		7,689	7,617
Unregulated Energy
Goodwill [Line Items]
Goodwill		37,019	31,114
Customer list
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[1]	$ 16,814	10,680
Customer list | Minimum [Member]
Goodwill [Line Items]
Amortized period of acquired intangible assets		5 years
Customer list | Western Natural Gas [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 1,300
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[1]	2,431	$ 2,375
Noncompete Agreements [Member] | Western Natural Gas [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 100

[1] 1) The customer relationship and non-compete agreements amounts include $6.1 million and less than $0.1 million, respectively, as a result of the purchase of the operating assets of Diversified Energy in December 2021 and $1.3 million and $0.1 million, respectively, recorded as a result of the purchase of the operating assets of Western Natural Gas in October 2020.

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 19,967	$ 13,777
Finite-Lived Intangible Assets, Accumulated Amortization		6,775	5,485
Goodwill		44,708	38,731
Goodwill, Transfers	[1]	5,977
Regulated Energy
Goodwill [Line Items]
Goodwill		7,689	7,617
Goodwill, Transfers	[1]	72
Unregulated Energy
Goodwill [Line Items]
Goodwill		37,019	31,114
Goodwill, Transfers	[1]	5,905
Customer Lists [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	16,814	10,680
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	5,125	4,269
Customer Lists [Member] | Diversified Energy
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		6,100
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	2,431	2,375
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	1,078	768
Noncompete Agreements [Member] | Diversified Energy
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		100
Patents [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		452	452
Finite-Lived Intangible Assets, Accumulated Amortization		354	236
Other Intangible Assets [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		270	270
Finite-Lived Intangible Assets, Accumulated Amortization		$ 218	$ 212

[1] (1)Includes goodwill from the purchase of operating assets of Diversified Energy in December 2021 and Elkton Gas in the third quarter of 2020.

[2] 1) The customer relationship and non-compete agreements amounts include $6.1 million and less than $0.1 million, respectively, as a result of the purchase of the operating assets of Diversified Energy in December 2021 and $1.3 million and $0.1 million, respectively, recorded as a result of the purchase of the operating assets of Western Natural Gas in October 2020.

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Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		$ 19,967	$ 13,777
Accumulated Amortization		6,775	5,485
Customer Lists [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	16,814	10,680
Accumulated Amortization	[1]	5,125	4,269
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	2,431	2,375
Accumulated Amortization	[1]	1,078	768
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		452	452
Accumulated Amortization		354	236
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		270	270
Accumulated Amortization		$ 218	$ 212

[1] 1) The customer relationship and non-compete agreements amounts include $6.1 million and less than $0.1 million, respectively, as a result of the purchase of the operating assets of Diversified Energy in December 2021 and $1.3 million and $0.1 million, respectively, recorded as a result of the purchase of the operating assets of Western Natural Gas in October 2020.

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Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax			$ 6,300	$ (12,200)
Deferred Tax Assets, Operating Loss Carryforwards	$ 1,490	$ 1,587
Net Operating Losses and Tax Carryback	(919)	(1,841)
Deferred State and Local Income Tax Expense (Benefit)	8,200	4,900	$ 4,700
Deferred Tax Assets, Operating Loss Carryforwards, Total	1,500	1,600
Net Operating Losses and Tax Carryback, Total	(900)	(1,800)
Deferred Tax Assets, Operating Loss Carryforwards	$ 1,490	1,587
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%		35.00%
State
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax	$ 14,600	$ 40,000

XML

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Income Tax Expense
Federal		$ 2,775	$ (2,777)	$ (2,252)
State		(96)	2,162	(491)
Other		(47)	(47)	(47)
Total current income tax expense (benefit)		2,632	(662)	(2,790)
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	26,599	24,200	23,904
Income Tax Expense from Continuing Operations		29,231	23,538	21,114
Discontinued Operation, Tax Effect of Gain (Loss) from Disposal of Discontinued Operation		0	153	1,416
Income Tax Expense (Benefit), Continuing Operations, Discontinued Operations		29,231	23,691	22,530
Deferred State and Local Income Tax Expense (Benefit)		8,200	4,900	4,700
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		24,074	23,224	25,907
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		1,857	(714)	79
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		(655)	(75)	(454)
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense		(351)	156	(278)
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		97	5,107	(3,772)
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ 1,577	$ (3,498)	$ 2,422

[1] (1) Includes $8.2 million, $4.9 million, and $4.7 million of deferred state income taxes for the years 2021, 2020 and 2019, respectively.

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Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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%		35.00%
Reconciliation of Effective Income Tax Rates Continuing Operations
Federal income tax expense (1)	[1]	$ 23,666	$ 19,778	$ 17,264
State income taxes, net of federal benefit		6,371	5,051	5,093
ESOP dividend deduction		(180)	(218)	(173)
Other		308	768	(1,070)
Income Tax Expense from Continuing Operations		$ 29,231	$ 23,538	$ 21,114
Effective Income Tax Rate from Continuing Operations		25.94%	24.99%	25.65%
Effective Income Tax Rate Reconciliation, Nondeductible Expense, Depreciation, Amount		$ (15)
Net Operating Losses and Tax Carryback		$ (919)	$ (1,841)

[1] Federal income taxes were calculated at 21 percent for 2021, 2020, and 2019.

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Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 8,200	$ 4,900	$ 4,700
Deferred income tax liabilities:
Property, plant and equipment	224,034	199,287
Acquisition adjustment	6,266	6,618
Deferred Tax Liabilities Loss On Reacquired Debt	183	201
Deferred Income Tax Liability - Deferred Gas Costs	2,366	509
Deferred Income Tax Liability, Natural Gas Conversion Costs	5,529	5,379
Deferred Income Tax Liability, Storm Reserve	5,783	7,073
Other	6,301	5,587
Total deferred income tax liabilities	250,462	224,654
Deferred income tax assets:
Pension and other employee benefits	5,354	4,636
Environmental costs	996	1,064
Net operating loss carryforwards	1,490	1,587
Storm reserve liability	448	409
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals	4,843	6,153
Other	3,781	5,417
Total deferred income tax assets	16,912	19,266
Deferred income taxes	$ 233,550	$ 205,388

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Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 8.2	$ 4.9	$ 4.7

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2019
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%	35.00%

XML

Income Taxes Federal Tax Reform (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2019
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	$ 250,000
Percentage of equity of total capitalization	40.00%
Fixed charge coverage ratio	1.2
Required net book value of regulated business assets, minimum percentage of consolidated total assets	50.00%
Maximum limit on payment of dividends	$ 10,000
Cumulative consolidated net income base	664,500
Cumulative net income with restrictions	289,400
Long-term debt including current maturities	568,800	$ 523,000
Long-term Debt and Lease Obligation	567,865	522,099
Total long-term debt, net of current maturities	549,903	508,499
Unamortized Debt Issuance Expense	(913)	(901)
Long-term Debt and Lease Obligation, Current	$ (17,962)	(13,600)
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	$ 14,500	17,400
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	$ 4,900	5,600
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	$ 14,000	16,000
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	$ 40,000	45,000
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	$ 6,000	9,000
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	$ 70,000	70,000
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
Equipment Security Note
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Long-term debt including current maturities	$ 9,378
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
Marlin Gas Services [Member] | Equipment Security Note
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 9,600

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Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Restricted Payment	$ 289,400
Long-term Debt	568,800	$ 523,000
Less: debt issuance costs	(913)	(901)
Long-term Debt and Lease Obligation	567,865	522,099
Less: current maturities	(17,962)	(13,600)
Total long-term debt, net of current maturities	549,903	508,499
Unrestricted Payment	375,100
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	$ 6,000	9,000
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 14,500	17,400
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 4,900	5,600
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 14,000	16,000
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	$ 40,000	45,000
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	$ 70,000	70,000
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%

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Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2021
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

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Long-Term Debt Annual Maturities (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months	$ 17,962
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two	21,483
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Three	18,505
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four	25,528
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Five	34,551
Long-term Debt, Maturities, Repayments of Principal in Rolling after Year Five	450,749
Total Future Repayments	$ 568,778

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Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Line of Credit Facility [Line Items]
Long-term Debt	$ (568,800)	$ (523,000)
Debt Instrument, Unused Borrowing Capacity, Amount	250,000
Prudential [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(220,000)
Debt Instrument, Unused Borrowing Capacity, Amount	150,000
MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	150,000
Debt Instrument, Unused Borrowing Capacity, Amount	100,000
Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(220,000)
Aggregated Unfunded Commitments [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(50,000)
Aggregated Unfunded Commitments [Member] | MetLife [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(50,000)
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (70,000)	(70,000)
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%
Maximum [Member] | Prudential [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	$ 370,000
Maximum [Member] | Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	$ 520,000

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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, 2021 USD ($)	Dec. 31, 2020 USD ($)
Short-term Debt [Line Items]
Short-term borrowings		$ 221,634,000	$ 221,634,000	$ 175,644,000
Line of Credit Facility, Aggregate Borrowing Capacity		$ 200,000,000	$ 200,000,000
Number Of Unsecured Bank Credit Facilities			3
Short-term Debt, Weighted Average Interest Rate, at Point in Time		0.83%	0.83%	1.28%
Ratio of Indebtedness to Net Capital		0.65	0.65
Long-term debt including current maturities		$ 568,800,000	$ 568,800,000	$ 523,000,000
Line of Credit Facility, Commitment Fee Percentage			95.00%
Line of Credit Facility, Remaining Borrowing Capacity		173,100,000	$ 173,100,000
Letters of Credit Outstanding, Amount		5,300,000	5,300,000
Notional Amount of Nonderivative Instruments		60,000,000	30,000,000	$ 100,000,000
Financing Receivable, Revolving		400,000,000	400,000,000
Subsequent Event
Short-term Debt [Line Items]
Notional Amount of Nonderivative Instruments	$ 40,000,000
Fixed Swap Rate	0.17%
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity		$ 400,000,000	$ 400,000,000
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 0.75 percent
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			Lender's base rate, plus 0.75 percent
Interest Rate Swap Rate, Low Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate		0.20%	0.2615%
Interest Rate Swap Rate, High Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate		0.205%	0.3875%
Revolving Line of Credit, Short-term
Short-term Debt [Line Items]
Financing Receivable, Revolving		$ 200,000,000	$ 200,000,000
Debt Instrument, Interest Rate, Stated Percentage		70.00%	70.00%
Revolving Line of Credit, Long-term
Short-term Debt [Line Items]
Debt Instrument, Fee			0.09

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Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 200,000
Line of Credit Facility, Remaining Borrowing Capacity	173,100
Short-term borrowing	$ 221,634	$ 175,644
Number Of Unsecured Bank Credit Facilities	3
Committed Line of Credit Facility One [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 0.75 percent
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate, plus 0.75 percent
Committed Line of Credit Facility Five [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate, plus 0.85 percent
Committed Line of Credit Facility Four [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 1.125 percent
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 0.75 percent

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Leases Schedule of Future Minimum Rental Payment for Operating Leases (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2,019	[1]
Lessee Future Operating Lease Option Payments	2,100
Lessee, Operating Lease, Liability, Payments, Due Year Two	1,902	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,672	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,341	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Five	885	[1]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	3,668	[1]
Lessee, Operating Lease, Liability, Payments, Due	11,487	[1]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(920)
Operating Lease, Liability	$ 10,567

[1] (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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Leases Lease Cost Additional (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Lease, Cost	[1]	$ 2,064	$ 2,029

[1] 1) Includes short-term leases and variable lease costs, which are immaterial

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Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 10,139	$ 11,194
Operating Lease, Liability, Current	1,996	1,747
Operating Lease, Liability, Noncurrent	8,571	9,872
Total Operating and Finance Lease Liabilities	$ 10,567	$ 11,619

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Leases Weighted Average Remaining Lease Term Additional Information (Details)	Dec. 31, 2021	Dec. 31, 2020
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	8 years 1 month 6 days	8 years 8 months 12 days
Operating Lease, Weighted Average Discount Rate, Percent	3.60%	3.80%

XML

Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Leases Cash Flows [Abstract]
Operating Lease, Payments	$ 1,996	$ 1,956

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Stockholders' Equity Additional Details (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
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	$ 0	$ 60,980,000	$ 0
Common Stock Shares Issued At The Market	700,000
Shares Issued Price Per Share - At The Market	$ 82.93
Proceeds From Issuance Of Common Stock - At The Market	$ 61,000,000
Fees on Equity Issuance - At The Market	$ 1,500,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan	100,000	300,000
Stock Issued During Period, Value, Dividend Reinvestment Plan	$ 125.71	$ 86.12
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan	15,200,000	$ 22,000,000
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, 2021	Dec. 31, 2020
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (2,865)	$ (6,267)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	7,337	4,838
Amounts reclassified from accumulated other comprehensive income/(loss)	(3,169)	(1,436)
Net current-period other comprehensive income/(loss)	4,168	3,402
Accumulated other comprehensive loss at end of period	1,303	(2,865)
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	(5,146)	(4,933)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	262	(578)
Amounts reclassified from accumulated other comprehensive income/(loss)	1,616	365
Net current-period other comprehensive income/(loss)	1,878	(213)
Accumulated other comprehensive loss at end of period	(3,268)	(5,146)
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	2,309	(1,334)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	7,075	5,400
Amounts reclassified from accumulated other comprehensive income/(loss)	(4,813)	(1,757)
Net current-period other comprehensive income/(loss)	2,262	3,643
Accumulated other comprehensive loss at end of period	4,571	2,309
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	(28)	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0	16
Amounts reclassified from accumulated other comprehensive income/(loss)	28	(44)
Net current-period other comprehensive income/(loss)	28	(28)
Accumulated other comprehensive loss at end of period	$ 0	$ (28)

XML

Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020		Dec. 31, 2019
Amortization of defined benefit pension and postretirement plan items:
Income tax benefit		$ (29,231)	$ (23,538)		$ (21,114)
Accumulated other comprehensive income (loss)		1,303	(2,865)		(6,267)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		7,337	4,838
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(3,169)	(1,436)
Other Comprehensive Income (Loss), Net of Tax		4,168	3,402
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive income (loss)		4,571	2,309		(1,334)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		7,075	5,400
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(4,813)	(1,757)
Other Comprehensive Income (Loss), Net of Tax		2,262	3,643
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive income (loss)		0	(28)		0
Other Comprehensive Income (Loss), before Reclassifications, before Tax		0	16
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		28	(44)
Other Comprehensive Income (Loss), Net of Tax		28	(28)
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive income (loss)		(3,268)	(5,146)		(4,933)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		262	(578)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		1,616	365
Other Comprehensive Income (Loss), Net of Tax		1,878	(213)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of defined benefit pension and postretirement plan items:
Net of tax		3,169	1,436		728
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of defined benefit pension and postretirement plan items:
Prior service cost	[1]	77	77		77
Net gain		(2,243)	(592)	[1]	(2,600)	[1]
Total before income taxes		(2,166)	(515)		(2,523)
Income tax benefit	[2]	550	150		656
Net of tax		(1,616)	(365)		(1,867)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes		6,651	2,428		3,623
Income tax benefit	[2]	(1,838)	(671)		(1,028)
Net of tax		4,813	1,757		2,595
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes		(28)	60
Income tax benefit	[2]		(16)
Net of tax		(28)	44
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements		(28)	60
Propane Swap Agreement [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[3]	6,651	2,428		1,520
Natural Gas Futures [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[3],[4]	0	0		2,096
Natural Gas Swaps [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[3],[4]	$ 0	$ 0		$ 7

[1] 1) These amounts are included in the computation of net periodic benefits. See Note 17, Employee Benefit Plans, for additional details.

[2] (4) The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

[3] 2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details.

[4] (3) PESCO's results are reflected as discontinued operations in our consolidated statements of income.

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Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2021 USD ($) shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Income tax benefits		$ 1,100
Total unrecognized cost		18,660
Expected Amortization Of Pre Merger Regulatory Asset		$ 0
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
Deferred Pension Settlement Expense		$ 600		$ 700
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		$ 5,900	$ 5,900	5,700
Shares reserved to fund future contributions | shares		798,586
Investments, Fair Value Disclosure		$ 12,095	10,776
Deferred compensation obligation		$ 7,240	5,679
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
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Unfunded accumulated benefit obligation		$ 0	(1,537)
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		17,737
Unfunded accumulated benefit obligation		(8,318)	(14,400)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		300
Expected contribution	[1]	3,451
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		659
Unfunded accumulated benefit obligation		(2,096)	(2,212)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		200
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		$ 378
Unfunded accumulated benefit obligation		$ (934)	(1,033)
Expected Amortization Of Pre Merger Regulatory Asset			0	$ 0
Health care inflation rate		6.00%
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 100
Expected contribution	[2]	73
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		114
Unfunded accumulated benefit obligation		$ (1,004)	(1,009)
Health care inflation rate		5.00%
Expected contribution	[2]	$ 71
Rabbi Trust Associated With Deferred Compensation [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure		$ 12,069	10,755
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		$ 12,100	10,800
Deferred Compensation Equity		$ 7,200	$ 5,700

[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, 2021		Dec. 31, 2020	Dec. 31, 2019
Change in benefit obligation:
Interest cost	$ 48		$ 63	$ 74
Assumptions:
Deferred Pension Settlement Expense	600			700
Chesapeake Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	6,146		6,214
Interest cost	141	[1]	176	375	[2]
Actuarial loss	(371)		450
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	(5,884)		(612)
Benefits paid	(32)		(82)
Benefit obligation - end of year	0		6,146	6,214
Change in plan assets:
Balance, beginning of year	4,609		4,630
Actual return on plan assets	(237)		369
Employer contributions	1,544		304
Defined Benefit Plan, Plan Assets, Payment for Settlement	(5,884)		(612)
Benefits paid	(32)		(82)
Balance, end of year	0		4,609	$ 4,630
Reconciliation:
Funded status	0		(1,537)
Accrued pension cost	$ 0		$ (1,537)
Assumptions:
Discount rate	2.50%		2.25%
Expected return on plan assets	3.50%		3.50%	6.00%
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 70,366		$ 65,304
Interest cost	1,714		2,085	$ 2,452
Actuarial loss	(1,953)		6,069
Benefits paid	(3,097)		(3,092)
Benefit obligation - end of year	67,030		70,366	65,304
Change in plan assets:
Balance, beginning of year	55,966		49,703
Actual return on plan assets	4,246		6,581
Employer contributions	1,597		2,774
Benefits paid	(3,097)		(3,092)
Balance, end of year	58,712		55,966	$ 49,703
Reconciliation:
Funded status	(8,318)		(14,400)
Accrued pension cost	$ (8,318)		$ (14,400)
Assumptions:
Discount rate	2.75%		2.50%
Expected return on plan assets	6.00%		6.00%	6.50%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year	$ 2,212		$ 2,157
Interest cost	48		63
Actuarial loss	(12)		144
Benefits paid	(152)		(152)
Benefit obligation - end of year	2,096		2,212	$ 2,157
Change in plan assets:
Employer contributions	152		152
Benefits paid	(152)		(152)
Reconciliation:
Funded status	(2,096)		(2,212)
Accrued pension cost	$ (2,096)		$ (2,212)
Assumptions:
Discount rate	2.50%		2.25%
Chesapeake Postretirement Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1,033		$ 1,100
Interest cost	22		26	39
Plan participants contributions	190		166
Actuarial loss	159		(34)
Benefits paid	(470)		(225)
Benefit obligation - end of year	934		1,033	1,100
Change in plan assets:
Balance, beginning of year	0		0
Employer contributions	280		59
Plan participants contributions	190		166
Benefits paid	(470)		(225)
Balance, end of year	0		0	0
Reconciliation:
Funded status	(934)		(1,033)
Accrued pension cost	$ (934)		$ (1,033)
Assumptions:
Discount rate	2.83%		2.25%
FPU Medical Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1,009		$ 1,224
Interest cost	24		30	48
Plan participants contributions	29		37
Actuarial loss	71		(181)
Benefits paid	(129)		(101)
Benefit obligation - end of year	1,004		1,009	1,224
Change in plan assets:
Balance, beginning of year	0		0
Employer contributions	100		64
Plan participants contributions	29		37
Benefits paid	(129)		(101)
Balance, end of year	0		0	$ 0
Reconciliation:
Funded status	(1,004)		(1,009)
Accrued pension cost	$ (1,004)		$ (1,009)
Assumptions:
Discount rate	2.51%		2.50%

[1] (2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

[2] (1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

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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, 2021		Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 48		$ 63	$ 74
Prior service cost (credit)		(293)
Net loss		18,953
Total		18,660
Accumulated other comprehensive loss pre-tax		4,385
Post-merger regulatory asset		(14,275)
Total unrecognized cost		(18,660)
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		141	[1]	176	375	[2]
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		166	[1]	157	487	[2]
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(257)	[1]	(243)	(391)	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		(1,810)	[1]	(203)	(1,982)	[2]
Net Periodic Cost Benefit		2,042	[1]	465	2,261	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		2,042	[1]	465	2,261	[2]
Amortization Of Pre Merger Regulatory Asset		$ 0	[1]	$ 0	$ 0	[2]
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		2.25%		3.00%	3.00%
Expected return on plan assets		3.50%		3.50%	6.00%
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 1,714		$ 2,085	$ 2,452
Prior service cost (credit)		0
Net loss		17,737
Total		17,737
Accumulated other comprehensive loss pre-tax	[3]	3,370
Post-merger regulatory asset		(14,367)
Total unrecognized cost		(17,737)
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		3,306		2,967	2,770
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(612)		(552)	(505)
Net Periodic Cost Benefit		(980)		(330)	187
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		(980)		(330)	730
Amortization Of Pre Merger Regulatory Asset		$ 0		$ 0	$ 543
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		2.50%		3.25%	4.25%
Expected return on plan assets		6.00%		6.00%	6.50%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 48		$ 63
Prior service cost (credit)		0
Net loss		659
Total		659
Accumulated other comprehensive loss pre-tax	[3]	659
Post-merger regulatory asset		0
Total unrecognized cost		(659)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(28)		(20)	$ (85)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0		0	(58)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 76		$ 83	$ 217
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		2.25%		3.00%	4.00%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 22		$ 26	$ 39
Prior service cost (credit)		(293)
Net loss		671
Total		378
Accumulated other comprehensive loss pre-tax	[3]	378
Post-merger regulatory asset		0
Total unrecognized cost		(378)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(34)		(24)	(46)
Net Periodic Cost Benefit		(21)		(27)	8
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ (21)		$ (27)	$ 8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		2.25%		3.00%	4.00%
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 24		$ 30	$ 48
Prior service cost (credit)		0
Net loss		(114)
Total		(114)
Accumulated other comprehensive loss pre-tax	[3]	(22)
Post-merger regulatory asset		(92)
Total unrecognized cost		(114)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(9)		19	0
Net Periodic Cost Benefit		15		11	48
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		15		17	56
Amortization Of Pre Merger Regulatory Asset		$ 0		$ 6	$ 8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		2.50%		3.25%	4.25%

[1] (2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

[2] (1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

[3] The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2021 is net of income tax benefits of $1.1 million.

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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 (Phantoms) (Detail) $ in Millions	Dec. 31, 2021 USD ($)
Disclosure 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 [Abstract]
Income tax benefits	$ 1.1

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Employee Benefit Plans - Schedule of Assets by Investment Type (Detail) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Inputs, Level 1, 2 and 3
Asset Category
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments	$ 51,930	$ 52,459
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	52.00%	54.00%	53.00%
FPU Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	38.00%	37.00%	37.00%
FPU Pension Plan | Other
Asset Category
Percentage of assets by investment type	10.00%	9.00%	10.00%

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Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2021
Minimum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	14.00%
Minimum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	13.00%
Minimum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	26.00%
Minimum | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	4.00%
Minimum | Diversifying Assets
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7.00%
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	32.00%
Maximum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%
Maximum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%
Maximum | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	10.00%
Maximum | Diversifying Assets
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	19.00%
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, 2021	Dec. 31, 2020	Dec. 31, 2019
Debt and Equity Securities, FV-NI [Line Items]
Investments measured at net asset value	[1]	$ 6,782	$ 8,116
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		23,842	23,071
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	4,302	3,615
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1,835	1,672
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	954	891
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	10,863	11,307
Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	5,888	5,586
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		22,565	24,169
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	19,551	21,563
Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	3,014	2,606
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		5,523	5,219
Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	2,297	2,246
Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,729	1,954
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	497	1,019
Quoted Prices in Active Markets (Level 1)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		51,433	51,440
Quoted Prices in Active Markets (Level 1) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		23,842	23,071
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	4,302	3,615
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1,835	1,672
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	954	891
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	10,863	11,307
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	5,888	5,586
Quoted Prices in Active Markets (Level 1) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		22,565	24,169
Quoted Prices in Active Markets (Level 1) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	19,551	21,563
Quoted Prices in Active Markets (Level 1) | Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	3,014	2,606
Quoted Prices in Active Markets (Level 1) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		5,026	4,200
Quoted Prices in Active Markets (Level 1) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	2,297	2,246
Quoted Prices in Active Markets (Level 1) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,729	1,954
Quoted Prices in Active Markets (Level 1) | Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	0	0
Significant Other Observable Inputs (Level 2)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	0	0
Significant Other Observable Inputs (Level 2) | Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	0	0
Significant Other Observable Inputs (Level 2) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Other Observable Inputs (Level 2) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	0	0
Significant Other Observable Inputs (Level 2) | Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	0	0
Significant Other Observable Inputs (Level 2) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Other Observable Inputs (Level 2) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	0	0
Significant Other Observable Inputs (Level 2) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	0	0
Significant Other Observable Inputs (Level 2) | Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	0	0
Significant Unobservable Inputs (Level 3)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		497	1,019	$ 1,147
Significant Unobservable Inputs (Level 3) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Unobservable Inputs (Level 3) | Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Unobservable Inputs (Level 3) | Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Unobservable Inputs (Level 3) | Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	0	0
Significant Unobservable Inputs (Level 3) | Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	0	0
Significant Unobservable Inputs (Level 3) | Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	0	0
Significant Unobservable Inputs (Level 3) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		0	0
Significant Unobservable Inputs (Level 3) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	0	0
Significant Unobservable Inputs (Level 3) | Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	0	0
Significant Unobservable Inputs (Level 3) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		497	1,019
Significant Unobservable Inputs (Level 3) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	0	0
Significant Unobservable Inputs (Level 3) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	0	0
Significant Unobservable Inputs (Level 3) | Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	497	1,019
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		51,930	52,459
Fair Value Measured at Net Asset Value Per Share
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 58,712	$ 60,575

[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] Includes investment in a group annuity product issued by an insurance company.

XML

Employee Benefit Plans - Summary of Changes in Fair Value of Level 3 Investments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Alternative Investments, Fair Value of Plan Assets	[1]	$ 6,782	$ 8,116
Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		51,440
Balance, end of year		51,433	51,440
Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		1,019	1,147
Purchases		3,160	3,190
Transfers in		5,914	921
Disbursements		(9,587)	(4,290)
Investment Income		(9)	51
Balance, end of year		497	1,019
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		51,930	52,459
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		60,575
Balance, end of year		58,712	60,575
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		23,071
Balance, end of year		23,842	23,071
Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		23,071
Balance, end of year		23,842	23,071
Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		24,169
Balance, end of year		22,565	24,169
Debt securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		24,169
Balance, end of year		22,565	24,169
Debt securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Debt securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		5,219
Balance, end of year		5,523	5,219
Other Investments [Member] | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		4,200
Balance, end of year		5,026	4,200
Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		0
Balance, end of year		0	0
Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		1,019
Balance, end of year		497	1,019
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	[2]	3,615
Balance, end of year	[2]	4,302	3,615
Us Large Cap Equity Securities | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	3,615
Balance, end of year	[2]	4,302	3,615
Us Large Cap Equity Securities | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
Us Large Cap Equity Securities | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
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	[2]	1,672
Balance, end of year	[2]	1,835	1,672
Us Mid Cap Equity Securities | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	1,672
Balance, end of year	[2]	1,835	1,672
Us Mid Cap Equity Securities | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
Us Mid Cap Equity Securities | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
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	[2]	891
Balance, end of year	[2]	954	891
United States Equity Small Cap | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	891
Balance, end of year	[2]	954	891
United States Equity Small Cap | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
United States Equity Small Cap | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[2]	0
Balance, end of year	[2]	0	0
International All Cap Equity | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	11,307
Balance, end of year	[3]	10,863	11,307
International All Cap Equity | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	11,307
Balance, end of year	[3]	10,863	11,307
International All Cap Equity | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	0
Balance, end of year	[3]	0	0
International All Cap Equity | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	0
Balance, end of year	[3]	0	0
Alternative Strategies | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	5,586
Balance, end of year	[4]	5,888	5,586
Alternative Strategies | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	5,586
Balance, end of year	[4]	5,888	5,586
Alternative Strategies | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	0
Balance, end of year	[4]	0	0
Alternative Strategies | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	0
Balance, end of year	[4]	0	0
Fixed Income Securities [Member] | Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	21,563
Balance, end of year	[5]	19,551	21,563
Fixed Income Securities [Member] | Debt securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	21,563
Balance, end of year	[5]	19,551	21,563
Fixed Income Securities [Member] | Debt securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	0
Balance, end of year	[5]	0	0
Fixed Income Securities [Member] | Debt securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	0
Balance, end of year	[5]	0	0
High Yield Asset Backed Securities | Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	2,606
Balance, end of year	[5]	3,014	2,606
High Yield Asset Backed Securities | Debt securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	2,606
Balance, end of year	[5]	3,014	2,606
High Yield Asset Backed Securities | Debt securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	0
Balance, end of year	[5]	0	0
High Yield Asset Backed Securities | Debt securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[5]	0
Balance, end of year	[5]	0	0
Commodities | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	2,246
Balance, end of year	[6]	2,297	2,246
Commodities | Other Investments [Member] | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	2,246
Balance, end of year	[6]	2,297	2,246
Commodities | Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	0
Balance, end of year	[6]	0	0
Commodities | Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[6]	0
Balance, end of year	[6]	0	0
Real Estate [Member] | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[7]	1,954
Balance, end of year	[7]	2,729	1,954
Real Estate [Member] | Other Investments [Member] | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[7]	1,954
Balance, end of year	[7]	2,729	1,954
Real Estate [Member] | Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[7]	0
Balance, end of year	[7]	0	0
Real Estate [Member] | Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[7]	0
Balance, end of year	[7]	0	0
Guaranteed deposit | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[8]	1,019
Balance, end of year	[8]	497	1,019
Guaranteed deposit | Other Investments [Member] | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[8]	0
Balance, end of year	[8]	0	0
Guaranteed deposit | Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[8]	0
Balance, end of year	[8]	0	0
Guaranteed deposit | Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[8]	1,019
Balance, end of year	[8]	$ 497	$ 1,019

[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] 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, 2021		Dec. 31, 2020	Dec. 31, 2019
Components of net periodic cost:
Interest cost	$ 48		$ 63	$ 74
Expected Amortization Of Pre Merger Regulatory Asset	0
Chesapeake Postretirement Plan
Components of net periodic cost:
Interest cost	22		26	39
Amortization of prior service cost	(77)		(77)	(77)
Actuarial (gain) loss	34		24	46
Net periodic pension cost	(21)		(27)	8
Expected Amortization Of Pre Merger Regulatory Asset			0	0
Net periodic postretirement cost	$ (21)		$ (27)	$ 8
Assumptions
Discount rate	2.25%		3.00%	4.00%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	$ 190		$ 166
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	159		(34)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(470)		(225)
Defined Benefit Plan, Plan Assets, Amount	0		0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	280		59
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	190		166
Defined Benefit Plan, Plan Assets, Benefits Paid	(470)		(225)
Funded status	(934)		(1,033)
Accrued pension cost	$ (934)		$ (1,033)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.83%		2.25%
FPU Medical Plan
Components of net periodic cost:
Interest cost	$ 24		$ 30	48
Amortization of prior service cost	0		0	0
Actuarial (gain) loss	9		(19)	0
Net periodic pension cost	15		11	48
Amortization of pre-merger regulatory asset	0		6	8
Net periodic postretirement cost	$ 15		$ 17	$ 56
Assumptions
Discount rate	2.50%		3.25%	4.25%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	$ 29		$ 37
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	71		(181)
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(129)		(101)
Defined Benefit Plan, Plan Assets, Amount	0		0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	100		64
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	29		37
Defined Benefit Plan, Plan Assets, Benefits Paid	(129)		(101)
Funded status	(1,004)		(1,009)
Accrued pension cost	$ (1,004)		$ (1,009)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.51%		2.50%
Chesapeake SERP
Components of net periodic cost:
Interest cost	$ 48		$ 63
Actuarial (gain) loss	28		20	85
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0		0	58
Net periodic postretirement cost	$ 76		$ 83	$ 217
Assumptions
Discount rate	2.25%		3.00%	4.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ (12)		$ 144
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)
Funded status	(2,096)		(2,212)
Accrued pension cost	$ (2,096)		$ (2,212)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.50%		2.25%
Chesapeake Pension Plan
Components of net periodic cost:
Interest cost	$ 141	[1]	$ 176	$ 375	[2]
Expected return on assets	(166)	[1]	(157)	(487)	[2]
Actuarial (gain) loss	257	[1]	243	391	[2]
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	1,810	[1]	203	1,982	[2]
Net periodic pension cost	2,042	[1]	465	2,261	[2]
Amortization of pre-merger regulatory asset	0	[1]	0	0	[2]
Net periodic postretirement cost	$ 2,042	[1]	$ 465	$ 2,261	[2]
Assumptions
Discount rate	2.25%		3.00%	3.00%
Expected return on plan assets	3.50%		3.50%	6.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ (371)		$ 450
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(32)		(82)
Defined Benefit Plan, Plan Assets, Amount	0		4,609	$ 4,630
Defined Benefit Plan, Plan Assets, Contributions by Employer	1,544		304
Defined Benefit Plan, Plan Assets, Benefits Paid	(32)		(82)
Funded status	0		(1,537)
Accrued pension cost	$ 0		$ (1,537)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.50%		2.25%
FPU Pension Plan
Components of net periodic cost:
Interest cost	$ 1,714		$ 2,085	2,452
Expected return on assets	(3,306)		(2,967)	(2,770)
Actuarial (gain) loss	612		552	505
Net periodic pension cost	(980)		(330)	187
Amortization of pre-merger regulatory asset	0		0	543
Net periodic postretirement cost	$ (980)		$ (330)	$ 730
Assumptions
Discount rate	2.50%		3.25%	4.25%
Expected return on plan assets	6.00%		6.00%	6.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ (1,953)		$ 6,069
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(3,097)		(3,092)
Defined Benefit Plan, Plan Assets, Amount	58,712		55,966	$ 49,703
Defined Benefit Plan, Plan Assets, Contributions by Employer	1,597		2,774
Defined Benefit Plan, Plan Assets, Benefits Paid	(3,097)		(3,092)
Funded status	(8,318)		(14,400)
Accrued pension cost	$ (8,318)		$ (14,400)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.75%		2.50%

[1] (2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

[2] (1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

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Employee Benefit Plans - Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2021		Dec. 31, 2020	Dec. 31, 2019
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 0	[1]	$ 0	$ 0	[2]
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	0		0	543
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 0		$ 6	$ 8

[1] (2) As a result of the termination of the Chesapeake Pension Plan in 2021, we recorded $0.6 million as the final settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

[2] (1) As a result of annuity purchases and lump sum payments associated with the de-risking of the Chesapeake Pension Plan, the discount rate for Chesapeake Pension Plan was re-measured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded an estimated $0.7 million for the settlement expense in our consolidated statement of income which reflected a portion of the pension settlement expense that was deemed not recoverable through the regulatory process.

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Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2021 USD ($)
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	$ 3,451	[1]
2018	3,537	[1]
2019	3,592	[1]
2020	3,690	[1]
2021	3,720	[1]
Years 2022 through 2026	18,588	[1]
Chesapeake SERP
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	151	[2]
2018	149	[2]
2019	147	[2]
2020	160	[2]
2021	157	[2]
Years 2022 through 2026	723	[2]
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	73	[2]
2018	68	[2]
2019	63	[2]
2020	59	[2]
2021	54	[2]
Years 2022 through 2026	218	[2]
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	71	[2]
2018	70	[2]
2019	71	[2]
2020	70	[2]
2021	69	[2]
Years 2022 through 2026	$ 324	[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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Employee Benefit Plans Employee benefit plans phantoms (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Funded status	$ 0	$ (1,537)

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Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to the awards to Non employee directors		$ 4.1
Shares reserved for issuance		798,586
Number of Shares, Granted		683	887
Number of shares withheld		14,020	10,319	7,635
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortization of expense equally over a service period		1 year
Number of Shares, Granted	342
Weighted average grant-date fair value of awards granted	$ 129.09	$ 117.11	$ 84.47
Total [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Granted		6,830	8,870
Awards to non-employee director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to the awards to Non employee directors		$ 0.3
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		$ 76.31	$ 66.48
Number of Shares, Granted		69,903	70,014
Weighted average grant-date fair value of awards granted		$ 100.76	$ 91.89
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested		$ 28.8	$ 20.2	$ 15.1
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance		369,099

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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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 5,945	$ 4,829	$ 4,279
Less: tax benefit	(1,535)	(1,254)	(1,117)
Share-Based Compensation amounts included in net income	4,410	3,575	3,162
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	4,100
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	782	733	620
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	28,800	20,200	15,100
Total compensation expense	$ 5,163	$ 4,096	$ 3,659

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Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2021	Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted		683	887
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount		$ 4.1
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period For Amortization Of Share Based Expenses		1 year
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	342
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	$ 129.09	$ 117.11	$ 84.47

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Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2021	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted		683	887
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance		186,878	157,817
Number of Shares, Granted		69,903	70,014
Number of Shares, Vested		(53,147)	(35,651)
Number of Shares, Expired			(5,302)
Number of Shares, Outstanding Ending Balance		197,398	186,878
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		$ 87.06	$ 80.28
Weighted Average Grant Date Fair Value, Granted		100.76	91.89
Weighted Average Grant Date Fair Value, Vested		76.31	66.48
Weighted Average Grant Date Fair Value, Expired			65.32
Weighted Average Grant Date Fair Value, Outstanding Ending Balance		$ 94.15	$ 87.06
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	[1]	5,384
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	[1]	$ 93.39
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		$ 74.85
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number		852

[1] In conjunction with the retirement of one key employee during 2020, these shares were forfeited for the remainder of the service periods associated with awards granted during their employment with the Company.

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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, 2021	Dec. 31, 2020	Dec. 31, 2019
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation	14,020	10,319	7,635
Payment, Tax Withholding, Share-based Payment Arrangement	$ 1,478	$ 977	$ 692

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Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021 USD ($) dekatherm / d Dekatherm mi	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Rates and Other Regulatory Activities [Line Items]
Restricted Payment	$ 289,400
Regulatory Assets	123,967	$ 124,592
Revenues	569,968	488,198	$ 479,605
COVID-19 Regulatory Asset	$ 2,300	1,900
Peninsula Pipeline [Member] | Callahan Project [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Pipeline Miles | mi	26
Diameter of Pipe | mi	16
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
COVID-19 Settlement Amount	$ 2,100
Eastern Shore Gas Company | Del-Mar Pathway Project [Domain]
Rates and Other Regulatory Activities [Line Items]
firm natural gas transportation deliverability | dekatherm / d	14,300
Eastern Shore Gas Company | Del-Mar Pathway Project [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Pipeline Miles | mi	6
number of customers	4
Number of Mainline Pipeline Miles | mi	13
Hurricane Michael
Rates and Other Regulatory Activities [Line Items]
Regulatory Liability, Amortization Period, Low Range	6 years
Regulatory Liability, Amortization Period, Revised	10 years
TCJA
Rates and Other Regulatory Activities [Line Items]
Regulatory Liability, Amortization Period, Low Range	5 years
Regulatory Liability, Amortization Period, Revised	80 years
Peninsula Pipeline Company | Winter Haven Expansion
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	6,800
Peninsula Pipeline Company | Beachside Expansion
Rates and Other Regulatory Activities [Line Items]
Number of Mainline Pipeline Miles | mi	11
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	10,176
Delmarva
Rates and Other Regulatory Activities [Line Items]
COVID-19 Settlement Amount	$ 300
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid	34,200
Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	900
Maryland Division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	365
Sandpiper [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	608
Delaware natural gas division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	1,500
Elkton Gas [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	47
Elkton Gas [Member]
Rates and Other Regulatory Activities [Line Items]
Revenues	$ 7,105	$ 2,399
Elkton Gas [Member] | Regulated Energy [Member]
Rates and Other Regulatory Activities [Line Items]
Number of customers acquired through acquisition	7,000

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Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2021	Dec. 31, 2020
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 123,967	$ 124,592
Regulatory Liabilities		144,800	149,020
Self Insured Liabilities [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	563	533
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	1,073	4,422
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	2,829	2,673
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	47,887	45,315
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[4]	88,804	90,845
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		1,487	1,541
Storm Cost Recovery, Interest
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[5]	2,146	3,353
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	9,199	2,078
Under-recovered GRIP Revenue [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	2,101	278
Regulatory Liabilities	[6]	11	338
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	16,749	17,716
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	23,383	23,054
Environmental Regulatory Assets And Expenditures [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[8]	1,258	1,743
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	27,182	28,756
Loss on Reacquired Debt [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[10]	721	795
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		5,081	3,927
COVID-19 Deferred Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[11]	2,289	1,925
Deferred Storm Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[5]	36,004	44,320
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34,200
Regulatory Liabilities		19,189	$ 19,257
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.

[3] See Note 1, 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 12, 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 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’ Central Florida Gas division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.

[7] 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 17, Employee Benefit Plans, for additional information.

[8] All of our environmental expenditures incurred to date and our current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 20, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

[9] 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.

[10] Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

[11] 7) 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.

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Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 144,800	$ 149,020
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	12,591	12,728
Maryland Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,840	3,970
Sandpiper [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,656	3,713
Central Florida Gas Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	8,032	8,184
Florida Public Utilities Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	19,189	19,257
Fort Meade and Indiantown Divisions [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	271	309
FPU electric division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	5,237	6,694
Elkton Gas [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 1,091	$ 1,124

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Environmental Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2021 USD ($) site	Dec. 31, 2020 USD ($)
Environmental Commitments And Contingencies [Line Items]
Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 3,538,000	$ 4,299,000
Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	1,300,000	1,700,000
Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Remediation Expense	900,000
Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	300,000
West Palm Beach Florida | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	14,200,000
West Palm Beach Florida | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	3,300,000
FPU
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	5,200,000	5,900,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	12,900,000	12,400,000
FPU | Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	$ 1,100,000	$ 1,600,000

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Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2021 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	$ 89,557
Total purchase obligations for 2019 - 2020	82,412
Total purchase obligations for 2021 - 2022	70,114
Total purchase obligations thereafter	174,203
Aggregate guaranteed amount	20,000
Guarantor Obligations, Current Carrying Value	13,100
Amount of letter of credit to our current primary insurance company	$ 5,300
Florida Natural Gas Distribution and Eight Flags [Member]
Subsequent Event [Line Items]
Number of Years for Asset Management Agreement	10 years

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Other Commitments and Contingencies Purchase Obligations (Details) $ in Thousands	Dec. 31, 2021 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 89,557
Purchase Obligation, Due in Second and Third Year	82,412
Purchase Obligation, Due in Fourth and Fifth Year	70,114
Purchase Obligation, Due after Fifth Year	174,203
Purchase Obligation	$ 416,286

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Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2021	Sep. 30, 2021	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disclosure Quarterly Financial Data Schedule Of Quarterly Financial Information [Abstract]
Revenues									$ 569,968	$ 488,198	$ 479,605
Operating Income									131,112	112,723	106,285
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	83,466	71,498	65,153
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent									83,467	70,642	61,100
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent									(1)	686	(1,349)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax									$ 0	$ 170	$ 5,402
Income (Loss) from Continuing Operations, Per Basic Share									$ 4.75	$ 4.23	$ 3.73
Earnings per share:
Basic (in usd per share)	$ 1.27	$ 0.56	$ 0.67	$ 1.76	$ 1.38	$ 0.34	$ 0.51	$ 1.75	4.75	4.28	3.97
Income (Loss) from Continuing Operations, Per Diluted Share									4.73	4.21	3.72
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share									0	0.05	0.24
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share									0	0.05	0.24
Diluted (in usd per share)	$ 1.26	$ 0.56	$ 0.66	$ 1.76	$ 1.37	$ 0.34	$ 0.50	$ 1.74	$ 4.73	$ 4.26	$ 3.96

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Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 1,337	$ 1,058
Additions, Charged to Income	3,827	1,392
Additions, Other Accounts	613	278
Deductions	(992)	(1,391)
Balance at End of Year	$ 4,785	$ 1,337