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, 2020

☐ 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, 2020, 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 $1.3 billion.

The number of shares of Chesapeake Utilities Corporation's common stock outstanding as of February 18, 2021 was 17,473,124

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2021 Annual Meeting of Shareholders are incorporated by reference in Part II and Part III hereof.

Table of Contents

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2020

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	2
Item 1A. Risk Factors	12
Item 1B. Unresolved Staff Comments	19
Item 2. Properties	19
Item 3. Legal Proceedings	20
Item 4. Mine Safety Disclosures	20
Part II	21
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	21
Item 6. Selected Financial Data	23
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	25
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	45
Item 8. Financial Statements and Supplementary Data	48
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	103
Item 9A. Controls and Procedures	103
Item 9B. Other Information	104
Part III	104
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance	104
Item 11. Executive Compensation	104
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Item 13. Certain Relationships and Related Transactions, and Director Independence	104
Item 14. Principal Accounting Fees and Services	104
Part IV	104
Item 15. Exhibits, Financial Statement Schedules	104
Item 16. Form 10-K Summary	110
Signatures	110

Table of Contents

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification issued by the FASB

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

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

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

COVID-19: An infectious disease caused by a newly 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

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

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

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

GAAP: Generally Accepted Accounting Principles

GRIP: Gas Reliability Infrastructure Program

Gross Margin: a non-GAAP measure defined as operating revenues less the cost of sales. The Company's cost of sales includes purchased fuel cost for natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities and excludes depreciation, amortization and accretion

Table of Contents

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, which has been subsequently amended, 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 new $375 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 respective 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

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

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 effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and

•risks related to the outbreak of a pandemic, including the duration and scope of the pandemic and the corresponding impact on our supply chains, our personnel, our contract counterparties, general economic conditions and growth, and the financial markets.

Chesapeake Utilities Corporation 2020 Form 10-K Page 1

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ITEM 1. Business.

Corporate Overview and Strategy

Chesapeake Utilities Corporation is a Delaware corporation formed in 1947 with operations primarily in the Mid-Atlantic region, 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 utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. We are focused on identifying and developing 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 natural gas operations that provide a stable base of earnings, as well as investments in other related (non-regulated businesses) and services. 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 for collaboration and efficiencies across the organization.

•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 renewable 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

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, 2020 and total assets as of December 31, 2020, for our Regulated Energy segment by operation and area served:

Operations	Areas Served	Net Income		Total Assets
(in thousands)
Natural Gas Distribution
Delmarva Natural Gas (1)	Delaware/Maryland	$	9,448	$	319,028
Central Florida Gas and FPU	Florida	12,542		451,966
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	20,320		471,492
Peninsula Pipeline	Florida	9,359		129,862
Aspire Energy Express	Ohio	34		1,599
Electric Distribution
FPU	Florida	3,942		173,672
Total Regulated Energy		$	55,645	$	1,547,619

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

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 margin (which we define as operating revenues less purchased gas or electric 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 and Divestitures 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, 2020:

	Delmarva Natural Gas Distribution (2)				Florida Natural Gas Distribution (3)				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	64,640	62	%	$	38,975	32	%	$	45,550	59	%
Commercial	30,788		29	%	30,745		26	%	34,494		45	%
Industrial	9,138		9	%	39,054		32	%	1,336		2	%
Other (1)	290		<1%		12,225		10	%	(4,517)		(6)	%
Total Operating Revenues	$	104,856	100	%	$	120,999	100	%	$	76,863	100	%
Volumes (in Dts for natural gas/KW Hours for electric)
Residential	3,697,300		29	%	1,897,364		4	%	305,020		50	%
Commercial	3,671,768		29	%	5,921,505		14	%	293,262		48	%
Industrial	5,236,104		40	%	32,215,804		75	%	14,806		2	%
Other	270,013		2	%	2,900,247		7	%	—		—	%
Total Volumes	12,875,185		100	%	42,934,920		100	%	613,088		100	%
Average Number of Customers (4)
Residential	84,191		91	%	77,936		91	%	25,044		77	%
Commercial	7,764		9	%	5,574		6	%	7,280		23	%
Industrial	195		<1%		2,530		3	%	2		<1%
Other	16		<1%		14		<1%		—		—	%
Total Average Number of Customers	92,166		100	%	86,054		100	%	32,326		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) Operating revenues, volumes and average customers for the Delmarva natural gas distribution operations includes those for Elkton Gas which was acquired in July 2020. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions and Divestitures in the consolidated financial statements) for further information.

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

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(4) Average number of customers is based on the twelve-month average for the year ended December 31, 2020.

The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, 2020, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, 2020:

	Eastern Shore				Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated (1)	$	26,855	36	%	$	20,827	90	%
Local distribution companies - non-affiliated	24,953		33	%	840		4	%
Commercial and industrial - affiliated	—		—	%	1,120		5	%
Commercial and industrial - non-affiliated	22,905		31	%	264		1	%
Other (2)	404		<1%		29		<1%
Total Operating Revenues	$	75,117	100	%	$	23,080	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	148,795		49	%	306,400		98	%
Local distribution companies - non-affiliated	58,576		20	%	4,825		1	%
Commercial and industrial - affiliated	—		—	%	1,500		1	%
Commercial and industrial - non-affiliated	93,540		31	%	600		<1%
Total Contracted firm transportation capacity	300,911		100	%	313,325		100	%
Design day capacity (in Dts/d)	300,911		100	%	313,325		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 cost of sales 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.

Regulatory Overview

The following table highlights key regulatory information for each of our principal Regulated Energy operations. Peninsula Pipeline is not regulated with regard to cost of service by either the Florida PSC 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.

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(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 August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as regulatory assets for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs included a component of an overall return on capital additions and regulatory assets. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested to 10 years, and included costs related to Hurricane Dorian of approximately $1.2 million in this filing.

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 undepreciated plant. 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.

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

Chesapeake Utilities Corporation 2020 Form 10-K Page 5

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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 interstate 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.

Electric Distribution

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

Supplies, Transmission and Storage

Natural Gas Distribution

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

The Delmarva natural gas distribution systems are directly connected to Eastern Shore’s pipeline, which has connections to other pipelines that provide us with transportation and storage. These operations can also use propane-air and liquefied natural gas peak-shaving equipment to serve customers. 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. Previously, our Delmarva Peninsula natural gas distribution operation had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. 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 May 2019, FPU natural gas distribution and Eight Flags entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. Short-term agreements were entered for a term beginning July 2019 through October 2020 with long-term agreements executed for a 10-year term commencing on November 2020. 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.

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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	148,795	2021-2035
	Columbia Gas(1)	5,246	2023-2024
	Transco(1)	30,419	2021-2028
	TETLP(1)	50,000	2027
Florida Natural Gas Distribution	Gulfstream(2)	10,000	2022
	FGT	45,909 - 77,317	2022-2041
	Peninsula Pipeline	306,400	2033-2048
	Peoples Gas	160	2024
	Florida Southeast Connection LLC	5,000	2044
	Southern Natural Gas Company	1,750	2030

(1) Transcontinental Gas Pipe Line Company, LLC ("Transco"), Columbia Gas Transmission, LLC ("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, LLC ("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 is expected to commence construction of the gas transmission facilities to provide the firm transportation service to the power generation facility in the fourth quarter of 2021. 

Electric Distribution

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

Area Served by Contract	Counterparty	Contracted Amount (MW)	Contract Expiration Date
Northwest Florida	Gulf Power Company	Full Requirement*	2026
Northeast Florida	Florida Power & Light Company	Full Requirement*	2026
Northeast Florida	Eight Flags	21	2036
Northeast Florida	Rayonier	1.7 to 3.0	2036
Northeast Florida	WestRock Company	As-available	N/A

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

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Unregulated Energy

The following table presents net income for the year ended December 31, 2020 and total assets as of December 31, 2020, for our Unregulated Energy segment by operation and area served:

Operations	Area Served	Net Income		Total Assets
(in thousands)
Propane Operations (Sharp, FPU and Flo-gas) (1)	Delaware, Maryland, Virginia, Pennsylvania, Florida	$	6,485	$	144,805
Energy Transmission (Aspire Energy)	Ohio	3,407		115,882
Energy Generation (Eight Flags)	Florida	2,260		40,666
Marlin Gas Services	The Eastern U.S.	1,404		45,541
Total		$	13,556	$	346,894

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

Propane Operations - Operational Highlights

For the year ended December 31, 2020, 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	$	33,119	33	%	13,031	21	%	42,817	64	%
Residential metered	14,718		15	%	5,207	9	%	17,654	26	%
Commercial bulk	21,240		21	%	15,511	25	%	6,178	10	%
Commercial metered	1,465		1	%	614	1	%	250	<1%
Wholesale	17,444		17	%	24,647	40	%	46	<1%
AutoGas	2,864		3	%	2,563	4	%	89	<1%
Other (3)	9,894		10	%	—	—	%	—	—	%
Total	$	100,744	100	%	61,573	100	%	67,034	100	%

(1) Average number of customers is based on a twelve-month average for the year ended December 31, 2020.

(2) Operating revenues, volumes and average customer includes those for Western Natural Gas that was acquired in October 2020. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions and Divestitures 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.

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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 Delaware, Maryland, Florida, Pennsylvania and Virginia, which have a total storage capacity of 8.3 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 2,700 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 21,400 end-use customers. Aspire Energy purchases natural gas to serve these customers from conventional producers in the Marcellus and Utica natural gas production areas. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

For the twelve-month period ended December 31, 2020, Aspire Energy's operating revenues and deliveries by customer type were as follows:

	Operating revenues				Deliveries
	(in thousands)		% of Total		(in thousands Dts)	% of Total
Supply to Columbia Gas of Ohio	$	11,088	40	%	2,363	39	%
Supply to CGC	11,838		42	%	1,612	27	%
Supply to Marketers - unaffiliated	3,162		11	%	1,966	32	%
Other (including natural gas gathering and processing)	1,863		7	%	131	2	%
Total	$	27,951	100	%	6,072	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 renewable natural gas market needs.

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Divestiture of PESCO

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, which provided natural gas management and supply services to commercial and industrial customers in Florida, Delaware, Maryland, Pennsylvania, Ohio and other states. 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. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions and Divestitures, in the consolidated financial statements) for further information.

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

We are a trusted energy delivery company providing essential, safe, reliable, affordable, sustainable and efficient energy solutions to existing and new communities. 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 President and CEO begins and ends every speech to employees by expressing his gratitude for everything they do to ensure safety and enable the Company to generate strong financial performance, year-over-year. Our employees are the key to our success. Our leadership and human resources teams are responsible for attracting and retaining top talent. 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, 2020, we had a total of 947 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 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, competitive pay, career growth opportunities, paid volunteer time, and a culture of recognition. In 2020, the Company was recognized as a Top Workplace for the ninth consecutive year. These honors were based entirely on feedback from employees who were surveyed by the research firm ‘Energage’. Because of these accolades, early in 2021, the Company earned national recognition as an inaugural 2021 Top Workplaces USA award recipient among mid-sized companies.

In 2020, the Company enhanced our diversity initiatives and established an Equity, Diversity and Inclusion (“EDI”) Council with newly expanded Employee Resource Groups (“ERG”). This initiative aligns with our current employee recognition and appreciation programs and our Women in Energy ERG where we celebrate the dedication and success of women employees within the energy industry and our Company. We are committed to a workplace that embraces a culture of equity, diversity and inclusion that is open to individuals of different backgrounds, perspectives, genders and gender identities, races and ethnicities, sexual orientations, religious beliefs, and individuals with disabilities. Additionally, in 2020, we hosted monthly “EDI Wise” presentations whose primary purpose is to educate and inform employees about topics around equity, diversity and inclusion. These presentations are recorded and are available to employees across the enterprise for viewing at their convenience.

COVID-19 Response

On March 13, 2020, the United States declared a national emergency in response to the COVID-19 pandemic. Subsequently, states enacted stay-at-home orders to slow the spread of the virus that causes COVID-19, and reduce the burden on the U.S.

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health care system. In response to COVID-19, we promptly implemented our long-standing emergency response plan in coordination and collaboration with the Board of Directors, senior leadership and our entire team across the organization. Our objectives were simple – do whatever it takes to ensure the health, safety and well-being of our employees, customers and the communities we serve. Our information systems team swiftly established protocols and security to ensure that the members of our team had the technology and accessibility to safely work in a remote environment, given consideration to job requirements. We worked with our operations team to ensure that our employees were designated essential workers, received personal protective equipment and were compensated with premium pay for working on the front lines.

We created several Pandemic Taskforce teams and our Human Resources Taskforce took the lead on a Return to Work protocol for those employees who were sick. Through these efforts, as well as our continued commitment to monitor, assess and implement guidance and best practices recommended by the CDC, we have been able to maintain the continuity of the essential services that we provide, while also minimizing the spread of the virus and promoting the health, well-being and safety of our employees, customers and communities. While we continued to provide these services, we recognized the impacts of the pandemic on the communities where we live and work. We took immediate steps and (i) donated an additional $200,000, beyond our historical levels of charitable giving, to support response and relief organizations assisting communities affected by the COVID-19 pandemic and (ii) authorized a one-time grant from our SHARING program for customers economically impacted by the spread of the pandemic. To minimize financial hardships, at the onset of COVID-19, the Company’s regulated businesses suspended disconnections and waived late payment fees for all of our customers.

Our response to COVID-19 and financial performance in 2020 was a direct result of the strength and dedication of our team members, our strong culture, our solid corporate governance practices, and the channels through which we engage and collaborate across our family of businesses. 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 2020, and received updates on the Company’s actions related to COVID-19, the Company’s safety 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 and the inclusion of safety moments at key team meetings.

To meet our safety goals 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. For example, our new $1.0 million state-of-the-art training center, named ‘Safety Town,’ provides employees hands-on training and simulated on-the-job field experiences, which will help us maintain the integrity of our current infrastructure and future projects. This center will enable us to further our community outreach, through the training of many regional first responders. Training and preparing our current and future employees and contractors is critical to maintaining a skilled workforce and ensuring the long-term safety of our local communities.

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.

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Information About Executive Officers

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

Name	Age	Executive Officer Since	Offices Held During the Past Five Years
Jeffry M. Householder	63	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	54	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	63	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	62	2010	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	51	2019	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, 909 Silver Lake Boulevard, 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, 2020, 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 our pension plans, which may require significant additional funding.

Our pension plans are closed to new employees, and the future benefits are frozen. The costs of providing benefits and related funding requirements of these plans are subject to changes in the market value of the assets that fund the plans 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 our pension plans may require us to record higher pension expense and fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.

OPERATIONAL RISKS

We are dependent upon construction of new facilities to support future growth in earnings in our natural gas and electric distribution and natural gas transmission operations.

Construction of new facilities required to support future growth is subject to various regulatory and developmental risks, including but not limited to: (i) our ability to obtain timely certificate authorizations, necessary approvals and permits from regulatory agencies and on terms that are acceptable to us; (ii) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (iii) our inability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; (iv) lack of anticipated future growth in available natural gas and electricity supply; (v) insufficient customer throughput

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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.

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.

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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.

We continue to heavily rely on technological tools that support our business operations and corporate functions. 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. The failure of, or security breaches related to, our information technology infrastructure, could lead to system disruptions or cause facility shutdowns. If such a failure, attack, or security breach were to occur, our business, our earnings, results of operation and financial condition could be adversely affected. 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.

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 gross margins 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.

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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 margins 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 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

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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

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 $51 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.

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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. Changes in applicable 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.

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 could be negatively impacted by the recent outbreak of COVID-19.

The outbreak of COVID-19 poses a health and financial crisis in the United States and globally, and related government restrictions and requirements and private sector responses could adversely affect our business operations. It is impossible to predict the effect and ultimate impact of the COVID-19 pandemic as the situation continues to evolve. We are responding 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

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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 have a Pandemic Response Plan that dates back to 2007. As soon as there were indications that the virus was spreading from China to other countries, we updated this plan, and continue to modify and adapt our operations given the fluid situation to ensure the continued delivery of our essential services. This plan guides our emergency response, business continuity, and the precautionary measures we are taking on behalf of our employees, our customer and the communities we serve. We have taken extra precautions for our employees who work in the field and for employees who continue to work in our facilities, and we have implemented work from home policies where appropriate. We have canceled travel plans, stopped movement between offices, transitioned to virtual, or on-line work, meetings and events, and instituted “social distancing” as directed by the CDC and state and local governments in the areas we serve. We temporarily 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 also established critical teams and task forces to guide us through key aspects of this pandemic. This has, and continues to be, an evolving situation to which we have remained fully engaged. 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. We currently cannot estimate the potential future impacts to our financial position, results of operations, and cash flows.

Although it is not possible to reliably estimate the duration or severity of the pandemic and, hence, its financial impact on the Company, the extent to which COVID-19 impacts our 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, Florida, Pennsylvania and Ohio.

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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, 2020:

Operations	Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines)	1,864
Delmarva Natural Gas (Underground propane pipelines)	32
Central Florida Gas and FPU (Natural gas pipelines)	2,973
Natural Gas Transmission
Eastern Shore	501
Peninsula Pipeline	129
Electric Distribution
FPU	900
Total	6,399

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, 2020 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)	8.3
Underground propane distribution mains (miles)	204
Unregulated Energy Transmission and gathering (Aspire Energy)
Natural gas pipelines (miles)	2,700

Florida liens

Until December 2020, all of the assets owned by FPU were subject to a lien in favor of the holders of its 9.08 percent first mortgage bonds securing its indebtedness under its Mortgage Indenture and Deed of Trust. These assets were not subject to any other lien as all other debt is unsecured. In December 2020, we redeemed FPU’s 9.08 percent secured first mortgage bonds prior to their maturity and as a result FPU properties are no longer subject to a lien. See Note 13, Long-term Debt in the Consolidated Financial Statements, for additional details.

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.

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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, 2021, we had 2,127 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $1.725 per share in 2020 and $1.585 per share in 2019, and have paid a cash dividend to our common stock stockholders for 60 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, 2020.

	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, 2020 through October 31, 2020 (1)	544	$	84.15	—	—
November 1, 2020 through November 30, 2020	—	—		—	—
December 1, 2020 through December 31, 2020	—	—		—	—
Total	544	$	84.15	—	—

(1) In October 2020, we purchased 544 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.

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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, 2020, 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, 2015 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.

	2015		2016		2017		2018		2019		2020
Chesapeake Utilities	$	100	$	120	$	144	$	151	$	181	$	209
Industry Index	$	100	$	122	$	138	$	156	$	175	$	147
S&P 500 Index	$	100	$	112	$	136	$	130	$	171	$	203

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ITEM 6. SELECTED FINANCIAL DATA

	For the Year Ended December 31,
	2020		2019		2018		2017		2016
Operating (1)
(in thousands)
Revenues
Regulated Energy	$	352,746	$	343,006	$	345,281	$	326,310	$	305,689
Unregulated Energy	152,526		154,151		161,905		140,076		108,364
Other businesses and eliminations	(17,074)		(17,552)		(16,870)		(16,740)		(9,318)
Total revenues	$	488,198	$	479,605	$	490,316	$	449,646	$	404,735
Operating income from Continuing Operations
Regulated Energy	$	92,124	$	86,584	$	79,215	$	74,584	$	71,515
Unregulated Energy	20,664		19,938		17,125		14,938		11,732
Other businesses and eliminations	(65)		(237)		(1,496)		205		402
Total operating income from Continuing Operations	$	112,723	$	106,285	$	94,844	$	89,727	$	83,649
Income from Continuing Operations	$	70,642	$	61,100	$	56,968	$	60,321	$	43,283
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		(388)		(2,197)		1,392
Gain on sale of Discontinued Operations, Net of Tax	170		5,402		—		—		—
Net Income	$	71,498	$	65,153	$	56,580	$	58,124	$	44,675
Assets
(in thousands)
Gross property, plant and equipment (1)	$	1,908,992	$	1,746,532	$	1,568,441	$	1,310,993	$	1,175,595
Net property, plant and equipment (1)	$	1,601,178	$	1,463,797	$	1,353,520	$	1,124,938	$	986,664
Total assets (2)	$	1,932,487	$	1,783,198	$	1,693,671	$	1,414,934	$	1,229,219
Capital expenditures (3)	$	195,875	$	198,986	$	282,861	$	179,337	$	169,376
Capitalization
(in thousands)
Stockholders’ equity	$	697,085	$	561,577	$	518,439	$	486,294	$	446,086
Long-term debt, net of current maturities	508,499		440,168		316,020		197,395		136,954
Total capitalization	$	1,205,584	$	1,001,745	$	834,459	$	683,689	$	583,040
Current portion of long-term debt	13,600		45,600		11,935		9,421		12,099
Short-term debt	175,644		247,371		294,458		250,969		209,871
Total capitalization and short-term financing	$	1,394,828	$	1,294,716	$	1,140,852	$	944,079	$	805,010

(1) As a result of the sale of PESCO's assets and contracts during the fourth quarter of 2019, certain amounts have been revised to reflect application of classification of PESCO as a discontinued operation for all periods presented and assets held for sale.

(2) Total assets for 2016 through 2018, include assets for PESCO, whose assets and contracts were sold in the fourth quarter of 2019.

(3) As a result of the sale of PESCO's assets and contracts during the fourth quarter of 2019, capital expenditures for 2016 to 2018 were recast to exclude amounts associated with PESCO.

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	For the Year Ended December 31,
	2020			2019			2018			2017			2016
Common Stock Data and Ratios
Basic Earnings Per Share:
Earnings Per Share from Continuing Operations	$	4.23		$	3.73		$	3.48		$	3.69		$	2.78
Earnings/(Loss) Per Share from Discontinued Operations	0.05			0.24			(0.02)			(0.13)			0.09
Basic Earnings Per Share	$	4.28		$	3.97		$	3.46		$	3.56		$	2.87
Diluted Earnings Per Share
Earnings Per Share from Continuing Operations	$	4.21		$	3.72		$	3.47		$	3.68		$	2.77
Earnings/(Loss) Per Share from Discontinued Operations	0.05			0.24			(0.02)			(0.13)			0.09
Diluted Earnings Per Share	$	4.26		$	3.96		$	3.45		$	3.55		$	2.86
Diluted earnings per share growth - 1 year (1)	13.2		%	7.2		%	(5.7)		%	32.9		%	5.3		%
Diluted earnings per share growth - 5 year (1)	9.9		%	9.4		%	10.0		%	14.3		%	9.0		%
Diluted earnings per share growth - 10 year (1)	9.4		%	11.3		%	11.3		%	11.5		%	9.8		%
Return on average equity (1)	11.5		%	11.3		%	11.3		%	13.0		%	11.0		%
Common equity / total capitalization	57.8		%	56.1		%	62.1		%	71.1		%	76.5		%
Common equity / total capitalization and short-term financing	50.0		%	43.4		%	45.4		%	51.5		%	55.4		%
Capital expenditures / average total capitalization (1)	17.7		%	21.7		%	37.3		%	28.3		%	31.1		%
Book value per share	$	39.92		$	34.23		$	31.65		$	29.75		$	27.36
Weighted average number of shares outstanding	16,711,579			16,398,443			16,369,616			16,336,789			15,570,539
Shares outstanding at year-end	17,461,841			16,403,776			16,378,545			16,344,442			16,303,499
Cash dividends declared per share	$	1.73		$	1.59		$	1.44		$	1.28		$	1.20
Dividend yield (annualized) (2)	1.6		%	1.7		%	1.8		%	1.7		%	1.8		%
Book yield (3)	4.7		%	4.8		%	4.7		%	4.5		%	4.7		%
Payout ratio (1)(4)	40.9		%	42.6		%	41.4		%	34.7		%	43.2		%
Additional Data
Customers
Natural gas distribution	178,220			164,134			158,387			153,537			149,179
Electric distribution	32,326			31,818			32,185			32,026			31,695
Propane operations	67,034			59,671			56,915			54,760			54,947
Total employees	947			955			983			945			903

(1) Diluted earnings per share growth, return on average equity, capital expenditures / average capitalization and payout ratio are calculated for continuing operations.

(2) Dividend yield (annualized) is calculated by multiplying the fourth quarter dividend by four (4), then dividing that amount by the closing common stock price at December 31.

(3) The book yield is calculated by dividing cash dividends declared per share (for the year) by average book value per share (for the year).

(4) The payout ratio is calculated by dividing cash dividends declared per share (for the year) by basic earnings per share from continuing operations.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 24

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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 the fourth quarter of 2019, we completed the sale of the assets and contracts of PESCO. As a result, PESCO’s results for all periods presented have been separately reported as discontinued operations.

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 have continued to significantly impact economic conditions in the United States in 2020 and will continue into 2021. Chesapeake Utilities is considered an “essential business,” which allows us to continue operational activities and construction projects while the social distancing restrictions remain in place. In response to the COVID-19 pandemic and related restrictions, we implemented our pandemic response plan, which includes having all employees who can work remotely do so in order to promote social distancing and providing personal protective equipment to field employees to reduce the spread of COVID-19.

For the year ended December 31, 2020, the estimated impacts that COVID-19 had on our earnings were approximately $1.0 million, primarily driven by reduced consumption of energy largely in the commercial and industrial sectors and incremental expenses associated with COVID-19, including protective personal equipment, bad debt expense 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 the fourth quarter of 2020, we established regulatory assets for the net incremental expense incurred for our natural gas and electric distribution businesses as currently authorized by the Delaware, Maryland and Florida PSCs. We are committed to communicating timely updates and will continue to monitor developments affecting our employees, customers, suppliers, stockholders and take additional precautions as warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, state and local requirements in order to protect its employees, customers and the communities. 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.

The following discussions and those later in the document on operating income and segment results include the use of the term “gross margin," which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that 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 unregulated energy operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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

Chesapeake Utilities Corporation 2020 Form 10-K Page 25

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OVERVIEW AND HIGHLIGHTS

(in thousands except per share data)					Increase						Increase
For the Year Ended December 31,	2020		2019		(decrease)		2019		2018		(decrease)
Business Segment:
Regulated Energy	$	92,124	$	86,584	$	5,540	$	86,584	$	79,215	$	7,369
Unregulated Energy	20,664		19,938		726		19,938		17,125		2,813
Other businesses and eliminations	(65)		(237)		172		(237)		(1,496)		1,259
Operating Income	112,723		106,285		6,438		106,285		94,844		11,441
Other income (expense), net	3,222		(1,847)		5,069		(1,847)		(607)		(1,240)
Interest charges	21,765		22,224		(459)		22,224		16,146		6,078
Income from Continuing Operations Before Income Taxes	94,180		82,214		11,966		82,214		78,091		4,123
Income Taxes on Continuing Operations	23,538		21,114		2,424		21,114		21,123		(9)
Income from Continuing Operations	70,642		61,100		9,542		61,100		56,968		4,132
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		2,035		(1,349)		(388)		(961)
Gain on sale of Discontinued Operations, Net of tax	170		5,402		(5,232)		5,402		—		5,402
Net Income	71,498		65,153		6,345		65,153		56,580		8,573
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	4.23	$	3.73	$	0.50	$	3.73	$	3.48	$	0.25
Earnings/(loss) Per Share from Discontinued Operations	0.05		0.24		(0.19)		0.24		(0.02)		0.26
Basic Earnings Per Share of Common Stock	$	4.28	$	3.97	$	0.31	$	3.97	$	3.46	$	0.51
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.21	$	3.72	$	0.49	$	3.72	$	3.47	$	0.25
Earnings/(loss) Per Share from Discontinued Operations	0.05		0.24		(0.19)		0.24		(0.02)		0.26
Diluted Earnings Per Share of Common Stock	$	4.26	$	3.96	$	0.30	$	3.96	$	3.45	$	0.51

Chesapeake Utilities Corporation 2020 Form 10-K     Page 26

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2020 compared to 2019

Key variances in continuing operations between 2020 and 2019 included:

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Year ended December 31, 2019 Reported Results from Continuing Operations	$	82,214	$	61,100	$	3.72
Adjusting for unusual items:
Unfavorable COVID-19 impacts	(5,864)		(4,284)		(0.26)
Decreased customer consumption - primarily weather related	(4,305)		(3,145)		(0.19)
Interest expense associated with the early extinguishment of FPU mortgage bonds	(961)		(715)		(0.04)
Favorable income tax impact associated with the CARES Act	—		1,841		0.11
Gains from sales of assets	3,162		2,317		0.14
Deferral of COVID expenses under PSC orders	1,925		1,432		0.09
	(6,043)		(2,554)		(0.15)
Increased (Decreased) Gross Margins:
Hurricane Michael Settlement Margin Impact*	10,864		7,936		0.47
Eastern Shore and Peninsula Pipeline service expansions*	8,006		5,849		0.35
Margin from recent acquisitions*	5,304		3,875		0.23
Natural gas growth (excluding service expansions)	3,370		2,462		0.15
Increased retail propane margins per gallon	1,937		1,415		0.08
Increased demand for CNG services for Marlin Gas Services*	1,821		1,331		0.08
Aspire Energy rate increases	1,312		959		0.06
Florida GRIP*	1,239		905		0.05
Eastern Shore margin from capital improvements and non-service expansion projects*	1,033		755		0.05
	34,886		25,487		1.52
(Increased) Decreased Other Operating Expenses (Excluding Cost of Sales):
Depreciation and amortization associated with Hurricane Michael regulatory proceeding settlement	(7,133)		(5,210)		(0.31)
Depreciation, amortization and property tax costs due to new capital investments	(6,262)		(4,575)		(0.27)
Operating expenses from recent acquisitions	(3,269)		(2,388)		(0.14)
Insurance	(2,088)		(1,525)		(0.09)
Payroll, benefits and other employee-related expenses	716		523		0.03
	(18,036)		(13,175)		(0.78)
Interest charges(1)	(1,232)		(900)		(0.05)
Increased share count from 2020 equity offerings	—		—		(0.08)
Other income tax effects	—		(1,060)		(0.06)
Lower pension expense	1,777		1,298		0.08
Net Other changes	614		446		0.01
Year ended December 31, 2020 Reported Results from Continuing Operations	$	94,180	$	70,642	$	4.21

* See the Major Projects and Initiatives table.

(1) Interest charges includes amortization of a regulatory liability of $1.5 million related to the Hurricane Michael regulatory proceeding settlement.

Chesapeake Utilities Corporation 2020 Form 10-K Page 27

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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.

	Gross Margin for the Period
	Year Ended December 31,						Estimate for Fiscal
(in thousands)	2018		2019		2020		2021		2022
Pipeline Expansions:
Western Palm Beach County, Florida Expansion (1)	$	54	$	2,139	$	4,167	$	4,984	$	5,227
Del-Mar Energy Pathway (1) (2)	—		731		2,462		4,385		6,708
Auburndale	—		283		679		679		679
Callahan Intrastate Pipeline (2)	—		—		3,851		7,564		7,564
Guernsey Power Station	—		—		—		514		1,486
Total Pipeline Expansions	54		3,153		11,159		18,126		21,664
CNG Transportation	110		5,410		7,231		7,900		8,500
RNG Transportation	—		—		—		1,000		1,000
Acquisitions:
Boulden Propane	—		329		3,900		4,200		4,409
Elkton Gas	—		—		1,344		3,992		4,200
Western Natural Gas	—		—		389		1,800		1,854
Total Acquisitions	—		329		5,633		9,992		10,463
Regulatory Initiatives:
Florida GRIP	13,020		13,939		15,178		16,739		17,712
Hurricane Michael regulatory proceeding	—		—		10,864		11,014		11,014
Capital Cost Surcharge Programs	—		—		—		1,500		3,000
Total Regulatory Initiatives	13,020		13,939		26,042		29,253		31,726
Total	$	13,184	$	22,831	$	50,065	$	66,271	$	73,353

(1) Includes gross margin generated from interim services.

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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 28

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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 gross margin of $2.0 million during 2020 compared to 2019. We expect to complete the remainder of the project in phases through the second quarter of 2021, and estimate that the project will generate annual gross margin of $5.0 million in 2021 and $5.2 million in 2022.

Del-Mar Energy Pathway

In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021. The new facilities will: (i) ensure 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, and interim services in advance of this project generated additional gross margin $1.7 million for the year ended December 31, 2020. The estimated annual gross margin from this project including natural gas distribution service in Somerset County, Maryland, is approximately $4.4 million in 2021 and $6.7 million annually thereafter.

Auburndale

In August 2019, the Florida PSC approved Peninsula Pipeline's Transportation Service Agreement with the Florida Division of Chesapeake Utilities. Peninsula Pipeline purchased an existing pipeline owned by the Florida Division of Chesapeake Utilities and Calpine, and has completed the construction of pipeline facilities in Polk County, Florida. Peninsula Pipeline provides transportation service to the Florida Division of Chesapeake Utilities; these facilities increased both delivery capacity and downstream pressure as well as introduced a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. Peninsula Pipeline generated additional gross margin from this project of $0.4 million for the year ended December 31, 2020 compared to 2019 and expects to generate annual gross margin of $0.7 million in 2021 and beyond.

Callahan Intrastate Pipeline

In May 2018, Peninsula Pipeline announced a plan to construct a jointly owned intrastate transmission pipeline with Seacoast Gas Transmission in Nassau County, Florida. The 26-mile pipeline will serve growing demand in both Nassau and Duval Counties. This project was placed in service in June 2020, one month earlier than initially forecasted, and generated $3.9 million in additional gross margin for the year ended December 31, 2020. We expect to generate $7.6 million annually in gross margin in 2021 and beyond.

Guernsey Power Station

Guernsey Power Station and our 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 is expected to commence 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 gross margin of approximately $0.5 million in 2021 and $1.5 million in 2022 and beyond.

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, 2020, Marlin Gas Services generated additional gross margin of $1.8 million compared to the year ended December 31, 2019. We estimate that Marlin Gas Services will generate annual gross margin of approximately $7.9 million in 2021, and $8.5 million in 2022, 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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 29

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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. Aspire Energy will utilize its existing natural gas gathering assets to inject the RNG from this project to its system for distribution to end use customers. 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 the development of a project to create renewable natural gas. BDC and our affiliates are collaborating on this project in addition to several other project sites where organic waste can be converted into a potentially carbon-negative energy source. This project will provide us the opportunity to maintain the value of the green attributes of renewable natural gas as the gas is being distributed to natural gas distribution customers.

The renewable natural gas resource created from organic material at BDC's anaerobic digestion facilities in Delaware, will be processed for use by our Delmarva natural gas operations. Marlin Gas Services will transport the sustainable fuel from the BDC facility to an Eastern Shore interconnection, where it will be introduced to the distribution 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 renewable natural gas to our operations. As part of this partnership, we will transport the renewable natural gas 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 renewable natural gas 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 have disclosed that we expect to generate $1.0 million in 2021 in incremental margin from renewable natural gas transportation beginning in 2021. 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

Boulden Propane

In December 2019, Sharp acquired certain propane customers and operating assets of Boulden which provides propane distribution service to approximately 5,200 customers in Delaware, Maryland and Pennsylvania. The customers and assets acquired from Boulden have been assimilated into Sharp. The operations acquired from Boulden generated $3.6 million of incremental gross margin for the year ended December 31, 2020 compared to 2019. We estimate that this acquisition will generate additional gross margin of approximately $4.2 million in 2021, and $4.4 million in 2022, with the potential for additional growth in future years.

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. 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 $1.3 million in additional gross margin from Elkton Gas for the year ended December 31, 2020 and estimate that this acquisition will generate gross margin of approximately $4.0 million in 2021 and $4.2 million in 2022 and beyond.

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 acquisition was accounted for as a business combination within our Unregulated Energy Segment in the fourth quarter of 2020. We generated $0.4 million in additional gross margin from Western Natural Gas in 2020 and we estimate that this acquisition will generate gross margin of approximately $1.8 million in 2021.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 30

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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, we have invested $164.9 million of capital expenditures to replace 331 miles of qualifying distribution mains, including $21.0 million and $16.7 million of new pipes during 2020 and 2019, respectively. GRIP generated additional gross margin of $1.2 million for the year ended 2020 compared to 2019.

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 August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as regulatory assets for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs included a component of an overall return on capital additions and regulatory assets. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested to 10 years, and included costs related to Hurricane Dorian of approximately $1.2 million in this filing.

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. The approved rates, which were part of the settlement agreement in September 2020 that is described below, were retroactively applied effective January 1, 2020.

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. We 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 undepreciated plant. 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 year ended December 31, 2020:

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

Chesapeake Utilities Corporation 2020 Form 10-K Page 31

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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. Eastern Shore expects to produce gross margin of approximately $1.5 million in 2021 and $3.0 million in 2022 from relocation projects.

Other Major Factors Influencing Gross Margin

Weather and Consumption

Weather conditions accounted for decreased gross margin of $4.3 million in 2020 compared to 2019 and $5.8 million compared to Normal temperatures as defined below. The following table summarizes heating degree day ("HDD") and cooling degree day (“CDD”) variances from the 10-year average HDD/CDD ("Normal") for the year ended December 31, 2020 compared to 2019.

HDD and CDD Information

	For the Years Ended December 31,
	2020	2019	Variance	2019	2018	Variance
Delmarva
Actual HDD	3,716	4,089	(373)	4,089	4,251	(162)
10-Year Average HDD ("Normal")	4,294	4,379	(85)	4,379	4,374	5
Variance from Normal	(578)	(290)		(290)	(123)
Florida
Actual HDD	647	619	28	619	780	(161)
10-Year Average HDD ("Normal")	763	792	(29)	792	800	(8)
Variance from Normal	(116)	(173)		(173)	(20)
Ohio
Actual HDD	5,218	5,500	(282)	5,500	5,845	(345)
10-Year Average HDD ("Normal")	5,701	5,983	(282)	5,983	5,823	160
Variance from Normal	(483)	(483)		(483)	22
Florida
Actual CDD	2,775	3,200	(425)	3,200	3,105	95
10-Year Average CDD ("Normal")	2,982	2,939	43	2,939	2,889	50
Variance from Normal	(207)	261		261	216

Natural Gas Distribution Margin 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 $3.4 million of additional margin in 2020. The average number of residential customers served on the Delmarva Peninsula and Florida increased by approximately 5.3 percent and 4.1 percent, respectively, during 2020. On the Delmarva Peninsula, a larger percentage of the 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:

Chesapeake Utilities Corporation 2020 Form 10-K     Page 32

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	Gross Margin increase
	For the Year Ended December 31, 2020
(in thousands)	Delmarva Peninsula		Florida
Customer growth:
Residential	$	1,516	$	807
Commercial and industrial	380		667
Total customer growth	$	1,896	$	1,474

REGULATED ENERGY

					Increase						Increase
For the Year Ended December	2020		2019		(decrease)		2019		2018		(decrease)
(in thousands)
Revenue	$	352,746	$	343,006	$	9,740	$	343,006	$	345,281	$	(2,275)
Cost of sales	91,994		102,803		(10,809)		102,803		121,828		(19,025)
Gross margin	260,752		240,203		20,549		240,203		223,453		16,750
Operations & maintenance	104,379		102,099		2,280		102,099		97,741		4,358
Gain from a settlement	(130)		(130)		—		(130)		(130)		—
Depreciation & amortization	46,079		35,227		10,852		35,227		31,876		3,351
Other taxes	18,300		16,423		1,877		16,423		14,751		1,672
Other operating expenses	168,628		153,619		15,009		153,619		144,238		9,381
Operating Income	$	92,124	$	86,584	$	5,540	$	86,584	$	79,215	$	7,369

2020 compared to 2019

Operating income for the Regulated Energy segment for 2020 was $92.1 million, an increase of $5.5 million, or 6.4 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, operating income increased $9.7 million as a result of the Hurricane Michael regulatory proceeding settlement, higher gross margin 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 margin growth from GRIP. These increases were offset by lower customer consumption driven primarily by milder weather; higher depreciation, amortization and property taxes, including amortization of the regulatory asset associated with the Hurricane Michael regulatory proceeding settlement; new expenses associated with Elkton Gas; and higher other operating expenses.

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

(in thousands)
Margin contribution from Hurricane Michael regulatory proceeding settlement	$	10,864
Eastern Shore and Peninsula Pipeline service expansions	8,006
Natural gas distribution customer growth (excluding service expansions)	3,370
Margin contribution from Elkton Gas acquisition (completed July 2020)	1,344
Florida GRIP	1,239
Eastern Shore margin from capital relocation and non-service expansion projects	1,033
Unfavorable COVID-19 impacts on gross margin	(3,834)
Decreased customer consumption - primarily weather related	(1,340)
Other	(133)
Year-over-year increase in gross margin	$	20,549

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

Margin Contribution from Hurricane Michael Regulatory Proceeding Settlement

We generated $10.9 million in additional gross margin as a result of the settlement of the Hurricane Michael regulatory proceeding. Refer to Note 19, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Eastern Shore and Peninsula Pipeline Service Expansions

We generated additional gross margin of $6.3 million from Peninsula Pipeline's Western Palm Beach County, Auburndale and Callahan projects and $1.7 million in additional gross margin from Eastern Shore's Del-Mar Energy Pathway project.

Natural Gas Distribution Customer Growth

We generated additional gross margin of $3.4 million from natural gas customer growth. Gross margin increased by $1.5 million in Florida and $1.9 million on the Delmarva Peninsula in 2020 compared to 2019, due primarily to residential customer growth of 5.3 percent on the Delmarva Peninsula and 4.1 percent in Florida. On the Delmarva Peninsula, a larger percentage of the margin growth 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 of the margin growth occurred in the commercial and industrial sectors.

Margin Contribution from Elkton Gas

Gross margin increased by $1.3 million due to the margin generated by Elkton Gas which we acquired in July 2020.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $1.2 million in 2020 compared to 2019.

Eastern Shore Margin from Capital Relocation and Non-service Expansion Projects

We generated additional gross margin of $1.0 million from Eastern Shore's surcharge on capital spent on several governmental-mandated relocation and non-service expansion projects.

Unfavorable COVID-19 Impacts

Gross margin decreased by $3.8 million in 2020 compared to 2019, as a result of the lower customer consumption, which was caused by the slowing of economic activities in our service territories as a result of restrictions imposed to promote social distancing and slow down the spread of COVID-19.

Decreased Customer Consumption - Weather Related

Gross margin decreased by $1.3 million due to milder weather and lower other consumption on the Delmarva Peninsula and in Florida in 2020 compared to 2019. The weather on the Delmarva Peninsula was 9 percent warmer in 2020 compared to 2019.

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

(in thousands)
Hurricane Michael settlement agreement - depreciation and amortization impact	$	7,133
Depreciation, amortization and property tax costs due to new capital investments	5,551
Unfavorable COVID-19 impacts (higher operating expenses)	2,285
Insurance (non-health) expense - both insured and self-insured components	1,442
Operating expenses from the Elkton Gas acquisition	651
Deferral of net expense increases of COVID-19 under PSC orders	(1,925)
Other variances	(128)
Period-over-period increase in other operating expenses	$	15,009

2019 compared to 2018

The results for the Regulated Energy segment for the year ended December 31, 2019 compared to 2018 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, 2019, which is incorporated herein by reference.

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UNREGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2020		2019		(decrease)		2019		2018		(decrease)
(in thousands)
Revenue	$	152,526	$	154,150	$	(1,624)	$	154,150	$	161,904	$	(7,754)
Cost of sales	62,780		68,884		(6,104)		68,884		84,707		(15,823)
Gross margin	89,746		85,266		4,480		85,266		77,197		8,069
Operations & maintenance	53,839		52,028		1,811		52,028		48,689		3,339
Depreciation & amortization	11,988		10,130		1,858		10,130		8,263		1,867
Other taxes	3,255		3,170		85		3,170		3,120		50
Other operating expenses	69,082		65,328		3,754		65,328		60,072		5,256
Operating Income	$	20,664	$	19,938	$	726	$	19,938	$	17,125	$	2,813

2020 Compared to 2019

Operating income for the Unregulated Energy segment for 2020 was $20.7 million, an increase of $0.7 million compared to 2019. The increased operating income was due to an increase in gross margin of $4.5 million, which was partially offset by an increase of $3.8 million in other operating expenses. Excluding the estimated COVID-19 impacts of $1.7 million, operating income increased $2.4 million as a result of incremental gross margin from the acquisitions of the Boulden and Western Natural Gas propane assets, higher retail propane margins per gallon, increased demand for Marlin Gas Services' CNG transportation services and higher rates for Aspire Energy. These increases were partially offset by reduced gross margins from overall warmer temperatures, higher depreciation, amortization and property taxes, expenses associated with recent acquisitions, and increased insurance expense.

Gross Margin

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

(in thousands)	Margin Impact
Propane Operations
Boulden and Western Natural Gas acquisitions (completed December 2019 and October 2020)	$	3,960
Increased retail propane margins per gallon driven by favorable market conditions and supply management	1,937
Decreased customer consumption - primarily weather related	(2,448)
Marlin Gas Services
Increased demand for CNG services	1,821
Aspire Energy
Higher margins from negotiated rate increases	1,312
Decreased customer consumption - primarily weather related	(517)
Unfavorable COVID-19 impacts on gross margin	(1,457)
Other variances	(128)
Year-over-year increase in gross margin	$	4,480

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

Propane Operations

•Boulden and Western Natural Gas - We generated gross margin of $3.6 million from Boulden which was acquired by Sharp in December 2019 and $0.4 million from Western Natural Gas which was acquired by Sharp in October 2020.

•Increased Retail Propane Margins - Gross margin increased by $1.9 million, due to lower propane inventory costs and favorable market conditions. 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.

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•Decreased Customer Consumption Primarily Driven by Weather - Gross margin decreased by $2.4 million for the Mid-Atlantic propane operations as weather on the Delmarva Peninsula was 9 percent warmer in 2020 compared to 2019.

Marlin Gas Services

•Gross margin increased by $1.8 million, as compared to 2019 due to higher demand for CNG hold services.

Aspire Energy

•Increased Margin Driven by Changes in Rates - Gross margin increased by $1.3 million, due primarily to higher margins from negotiated rate increases.

•Decreased Customer Consumption Primarily Driven by Weather - Gross margin decreased by $0.5 million due to lower consumption as weather in Ohio was approximately 5 percent warmer in 2020 compared to 2019.

Unfavorable COVID-19 Impacts

•Gross margin decreased by $1.5 million as a result of lower customer consumption, which was caused by the slowing of economic activities in our service territories as a result of restrictions imposed to promote social distancing and to slow down the spread of COVID-19.

Other Operating Expenses

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

(in thousands)
Depreciation and amortization due to new capital investments	1,840
Operating expenses from Boulden and Western Natural Gas acquisitions	1,510
Insurance expense (non-health) - both insured and self-insured	645
Other variances	(241)
Period-over-period increase in other operating expenses	$	3,754

2019 compared to 2018

The results for the Unregulated Energy segment for the year ended December 31, 2019 compared to 2018 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, 2019, which is incorporated by reference.

Divestiture of PESCO

As discussed in Note 4, Acquisitions and Divestitures, 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.

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OTHER INCOME (EXPENSE), NET

Other income (expense), net was $3.2 million and $(1.8) million for 2020 and 2019, 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 increase was primarily due to gains from the sale of two properties and lower pension expense in 2020. The property sales were the result of consolidation of certain operations facilities.

INTEREST CHARGES

2020 Compared to 2019

Interest charges for 2020 decreased by $0.5 million, compared to the same period in 2019, attributable primarily to a decrease of $4.6 million in interest expense primarily on lower levels outstanding under our revolving credit facilities and lower interest rates on short-term borrowings, $1.5 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, and $0.5 million primarily due to higher capitalized interest associated with growth projects. This decrease was offset by an increase of $5.9 million in interest expense on long-term debt as a result of several long-term debt placements in 2019 and 2020 and $1.0 million in interest and fees associated with the early payoff of the 9.08% FPU secured first mortgage bonds.

INCOME TAXES

2020 Compared to 2019

Income tax expense from continuing operations was $23.5 million for 2020 compared to $21.1 million for 2019. Our effective income tax rate was 25.0 percent and 25.7 percent for the year ended December 31, 2020 and 2019, respectively. During the year ended December 31, 2020, we implemented certain provisions of the CARES Act that allowed us to carryback net operating losses from 2018 and 2019 into prior year periods where the federal income tax rate was higher. As a result, we recognized a $1.8 million reduction in tax expense for the twelve months ended December 31, 2020. Excluding this impact of the CARES Act, our effective tax rate for the year ended December 31, 2020 was 26.9 percent.

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 more closely align our capital structure with our target capital structure. 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 $195.9 million (including the purchase of certain propane assets of Western Natural Gas and certain natural gas assets of Elkton Gas) in 2020.

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The following table shows total capital expenditures for the year ended December 31, 2020 by segment and by business line:

	For the Year Ended December 31, 2020
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	85,257
Natural gas transmission	58,609
Electric distribution	3,234
Total Regulated Energy	147,100
Unregulated Energy:
Propane distribution	15,455
Energy transmission	19,398
Other unregulated energy	11,442
Total Unregulated Energy	46,295
Other:
Corporate and other businesses	2,480
Total Other	2,480
Total 2020 Capital Expenditures	$	195,875

In the table below, we have provided a preliminary range of our forecasted capital expenditures for 2021:

	Estimate for Fiscal 2021
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	79,000	$	85,000
Natural gas transmission	55,000		60,000
Electric distribution	9,000		13,000
Total Regulated Energy	143,000		158,000
Unregulated Energy:
Propane distribution	9,000		12,000
Energy transmission	14,000		15,000
Other unregulated energy	8,000		12,000
Total Unregulated Energy	31,000		39,000
Other:
Corporate and other businesses	1,000		3,000
Total Other	1,000		3,000
Total 2021 Forecasted Capital Expenditures	$	175,000	$	200,000

The 2021 budget, excluding acquisitions, includes capital expenditures associated with the following projects: Delmarva Natural Gas distribution's Somerset County expansion and the Bioenergy Devco RNG Project, Eastern Shore's Del-Mar Energy Pathway and the CleanBay RNG projects, Florida's Western Palm Beach County expansion and other potential pipeline projects, continued expenditures under the Florida GRIP, further expansions of our natural gas distribution and transmission systems, continued natural gas and electric system infrastructure improvement activities, facilities to support Marlin Gas Services' legacy growth and expansion into RNG and LNG transport, 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

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opportunities, availability of capital and other factors discussed in Item 1A. Risk Factors. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.

The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.

Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings. This commitment, along with adequate and timely rate relief for our regulated energy operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost, which will benefit our customers, creditors, employees and stockholders.

The following tables present our capitalization, excluding and including short-term borrowings, as of December 31, 2020 and 2019 follows:

	December 31, 2020				December 31, 2019
(in thousands)
Long-term debt, net of current maturities	$	508,499	42	%	$	440,168	44	%
Stockholders’ equity	697,085		58	%	561,577		56	%
Total capitalization, excluding short-term borrowings	$	1,205,584	100	%	$	1,001,745	100	%

	December 31, 2020				December 31, 2019
(in thousands)
Short-term debt	$	175,644	13	%	$	247,371	19	%
Long-term debt, including current maturities	522,099		37	%	485,768		38	%
Stockholders’ equity	697,085		50	%	561,577		43	%
Total capitalization, including short-term borrowings	$	1,394,828	100	%	$	1,294,716	100	%

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was 50 percent as of December 31, 2020. 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 the third and fourth quarter 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 our general funds. See Note 16, Stockholders’ Equity, in the consolidated financial statements for additional information on commissions and fees paid in connection with these issuances.

As of December 31, 2020, we had no restrictions on our cash balances. Chesapeake Utilities’ Senior Notes contain a restriction that limits the payment of dividends or other restricted payments in excess of certain pre-determined thresholds. As of December 31, 2020, $324.6 million of our consolidated net income were free of such restrictions.

Term Notes

In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. This note was paid in full in February 2020 utilizing our short-term borrowing facilities.

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 40.0 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.

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Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at December 31, 2020:

	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		—		—		150,000
NYL Shelf Agreement (3)	150,000		(140,000)		—		10,000
Total	$	670,000	$	(360,000)	$	—	$	310,000

(1) In April 2020, we amended the Prudential Shelf Agreement to increase the available borrowing capacity by $150.0 million. The Shelf Agreement expires in April 2023. In July 2020, we issued $50 million of Prudential Shelf Notes at the rate of 3.00 percent per annum.

(2) In May 2020, we amended an agreement with MetLife to provide a new $150 million MetLife Shelf Agreement for a three-year term ending May 2023.

(3) In August 2020 we issued $40 million of NYL Shelf Notes at the rate of 2.96 percent per annum. The NYL Shelf Agreement expires in November 2021.

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

At December 31, 2020 and 2019, our short-term borrowing totaled $175.6 million and $247.4 million, respectively, at weighted average interest rates of 1.28 percent and 2.62 percent, respectively. Included in the December 31, 2020 balance, is $60.0 million in short-term debt for which we have entered into interest rate swap agreements.

In September 2020, we entered into a new $375.0 million syndicated Revolver with six participating lenders. As a result of entering into the Revolver, in September 2020, we terminated and paid all outstanding balances under the previously existing bilateral lines of credit and the previous revolving credit facility.

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, 2020, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is 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 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 our total indebtedness to total capitalization ratio. As of December 31, 2020, our pricing under the Revolver included a commitment fee of 0.175 percent and an interest rate of 1.125 percent over LIBOR. Our available credit under the new Revolver at December 31, 2020 was $196.9 million. As of December 31, 2020, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. Although the 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 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 were settled 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. The fixed swap rates ranged between 0.2615 and 0.3875 percent for the period. In the fourth quarter of 2020, we entered into an additional interest rate swap with notional amounts totaling $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 at 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.

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We are authorized by our Board of Directors to borrow up to $375 million of short-term debt, as required.

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, 2020 and 2019 are as follows:

(in thousands)	2020			2019			2018
Average borrowings during the year	$	230,526		$	257,587		$	238,750
Weighted average interest rate for the year	1.50		%	3.11		%	2.93		%
Maximum month-end borrowings	$	284,914		$	302,379		$	290,103

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2020, 2019 and 2018:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Net cash provided by (used in):
Operating activities	$	158,916	$	102,964	$	117,362
Investing activities	(181,631)		(186,587)		(256,848)
Financing activities	19,229		84,519		139,961
Net (decrease) increase in cash and cash equivalents	(3,486)		896		475
Cash and cash equivalents—beginning of period	6,985		6,089		5,614
Cash and cash equivalents—end of period	$	3,499	$	6,985	$	6,089

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 2020 and 2019, net cash provided by operating activities was $158.9 million and $103.0 million, respectively, resulting in an increase in cash flows of $55.9 million. Significant operating activities generating the cash flows change were as follows:

•Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities increased cash flows by $23.0 million, due in part to the absence of PESCO, whose assets and contracts were sold in the fourth quarter of 2019, as well as the timing and receipt of customer receipts and vendor payments;

•Net income, adjusted for non-cash adjustments and reconciling activities, increased cash flows by $23.6 million, due primarily to higher net income, depreciation and amortization and gain on sale of assets;

•Net cash flows from income taxes receivable increased by $11.9 million due primarily to tax refunds resulting from implementation of the CARES Act in 2020 which allowed taxable losses to be carried back against prior year taxable income;

•Changes in net regulatory assets and liabilities increased cash flows by $2.8 million due primarily to the change in fuel costs collected through the various cost recovery mechanisms;

•Changes in net prepaid expenses and other current assets, customer deposits and refunds and other assets and liabilities, net increased cash flows by $1.1 million; offset by

•Net cash flows from changes in propane inventory, storage gas and other inventories which decreased by approximately $6.5 million.

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Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $181.6 million and $186.6 million during the year ended December 31, 2020 and 2019, respectively, resulting in an increase in cash flows of $5.0 million. Key investing activities contributing to the cash flow change included:

•Cash used to pay for capital expenditures was $165.5 million for the year ended December 31, 2020, compared to $184.7 million in December 31, 2019;

•Net cash of $22.2 million was primarily used to acquire certain propane operating assets of Elkton Gas and Western Natural Gas in 2020, compared to net cash of $24.0 million used to acquire operating assets of Boulden in 2019; and

•Cash received from sales of assets was $8.1 million for the year ended December 31, 2020 due primarily to sale of properties as a result of consolidation of certain operations facilities.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $19.2 million for the year ended December 31, 2020, compared to net cash of $84.5 million provided by financing activities during the prior year which resulted in a decrease in cash flows of $65.3 million, primarily due to the following:

•Increased cash flows of $61.0 million and $23.3 million, from new equity issued under the ATM and waiver component of the DRIP, respectively;

•Decreased cash flows from higher repayments of short-term borrowing of $25.7 million under our line of credit arrangements;

•Decreased cash flows of $109.8 million associated with less long-term debt issuances. For the year ended December 31, 2020, we received net proceeds of $89.8 million from the issuance of Prudential Shelf Notes in July 2020 and NYL Shelf Notes in August 2020. For the year ended December 31, 2019 we received $199.6 million in net cash proceeds from the issuance of Term Notes, Prudential Shelf Notes and Uncollateralized Senior Notes.

•Decreased cash flows of $11.7 million as a result of the repayment of more long-term debt;

•Increased cash flows of $0.3 million as a result of changes in cash overdrafts in 2020; and

•Cash dividend payments of $27.2 million in 2020 compared to $24.7 million for 2019.

CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2020:

	Payments Due by Period
Contractual Obligations	2021		2022-2023		2024-2025		After 2025		Total
(in thousands)
Long-term debt (1)	$	13,600	$	37,700	$	42,200	$	429,500	$	523,000
Operating leases (2)	2,027		3,907		3,052		4,419		13,405
Purchase obligations (3)
Transmission capacity	35,330		66,434		56,533		169,102		327,399
Storage capacity	2,044		2,618		—		—		4,662
Commodities	25,728		—		—		—		25,728
Electric supply	6,357		12,788		12,887		32,402		64,434
Unfunded benefits (4)	310		606		572		1,274		2,762
Funded benefits (5)	3,863		3,090		3,090		3,031		13,074
Total Contractual Obligations	$	89,259	$	127,143	$	118,334	$	639,728	$	974,464

(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 $18.5 million, $34.7 million, $31.5 million and $95.3 million, respectively, for the periods indicated above. Expected interest payments for all periods total $180.0 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 $15.9 million at December 31, 2020 for two qualified, defined benefit pension plans. The assets funding these plans are in a separate trust and are not considered assets of ours or included in our balance sheets. The Contractual Obligations table above includes $2.3 million, reflecting the payments we expect to make to the trust funds in 2021. Additional contributions may be required in future years based on the actual return earned

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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 $10.8 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, 2020 was $20.0 million. The aggregate amount guaranteed at December 31, 2020 was $5.7 million, with the guarantees expiring on various dates through September 2021.

As of December 31, 2020, we have issued letters of credit totaling approximately $4.8 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, and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. There have been no draws on these letters of credit as of December 31, 2020. 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.

CRITICAL ACCOUNTING POLICIES

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.

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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.

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 2020 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.

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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.

For 2020, actuarial assumptions include expected long-term rates of return on plan assets of 3.50 percent and 6.00 percent for Chesapeake Utilities' pension plan and FPU’s pension plan, respectively, and discount rates of 2.25 percent and 2.50 percent for Chesapeake Utilities' and FPU’s plans, respectively. The discount rate for each plan was determined by management considering 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 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 $0.2 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.

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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.

We can store up to approximately 8.3 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.

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

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2019 to December 31, 2020:

(in thousands)	Balance at December 31, 2019		Increase (Decrease) in Fair Market Value		Less Amounts Settled		Balance at December 31, 2020
Sharp	$	(1,844)	$	4,292	$	734	$	3,182
Total	$	(1,844)	$	4,292	$	734	$	3,182

There were no changes in the methods of valuations during the year ended December 31, 2020.

The following is a summary of fair market value of financial derivatives as of December 31, 2020, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2021		2022		2023		Total Fair Value
Price based on Mont Belvieu - Sharp	$	2,669	$	508	$	5	$	3,182
Total	$	2,669	$	508	$	5	$	3,182

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.

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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.

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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, 2020 and 2019, 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, 2020, 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, 2020, 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, 2020 and 2019, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2020, 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, 2020, 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

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

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

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the 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 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 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 - 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 $31.1 million of goodwill within the Unregulated Energy reportable segment as of December 31, 2020, 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 2020 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 (formerly Baker Tilly Virchow Krause, LLP)

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

Philadelphia, Pennsylvania

February 24, 2021

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Income

	For the Year Ended December 31,
	2020		2019		2018
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	352,746	$	343,006	$	345,281
Unregulated Energy	152,526		154,151		161,905
Other businesses and eliminations	(17,074)		(17,552)		(16,870)
Total operating revenues	488,198		479,605		490,316
Operating Expenses
Regulated Energy cost of sales	91,994		102,803		121,828
Unregulated Energy and other cost of sales	45,944		51,698		68,341
Operations	142,055		137,845		132,523
Maintenance	15,587		15,679		14,387
Gain from a settlement	(130)		(130)		(130)
Depreciation and amortization	58,117		45,424		40,220
Other taxes	21,908		20,001		18,303
Total operating expenses	375,475		373,320		395,472
Operating Income	112,723		106,285		94,844
Other income (expense), net	3,222		(1,847)		(607)
Interest charges	21,765		22,224		16,146
Income from Continuing Operations Before Income Taxes	94,180		82,214		78,091
Income Taxes on Continuing Operations	23,538		21,114		21,123
Income from Continuing Operations	70,642		61,100		56,968
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		(388)
Gain on sale of Discontinued Operations, Net of tax	170		5,402		—
Net Income	$	71,498	$	65,153	$	56,580
Weighted Average Common Shares Outstanding:
Basic	16,711,579		16,398,443		16,369,616
Diluted	16,770,735		16,448,486		16,419,870
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.23	$	3.73	$	3.48
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Basic Earnings Per Share of Common Stock	$	4.28	$	3.97	$	3.46
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	4.21	$	3.72	$	3.47
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Diluted Earnings Per Share of Common Stock	$	4.26	$	3.96	$	3.45

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

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Comprehensive Income

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Net Income	$	71,498	$	65,153	$	56,580
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(18), $(20) and $(22), respectively	(59)		(57)		(55)
Net gain (loss), net of tax of $(41), $368, and $(49), respectively	(154)		1,052		(108)
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $1,392, $(176) and $(555), respectively	3,643		(434)		(1,371)
Unrealized (loss) on interest rate swap cash flow hedges, net of tax of $(12) in 2020	(28)		—		—
Total Other Comprehensive Income (Loss)	3,402		561		(1,534)
Comprehensive Income	$	74,900	$	65,714	$	55,046

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

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Assets	2020		2019
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,577,576	$	1,441,473
Unregulated Energy	300,647		265,209
Other businesses and eliminations	30,769		39,850
Total property, plant and equipment	1,908,992		1,746,532
Less: Accumulated depreciation and amortization	(368,743)		(336,876)
Plus: Construction work in progress	60,929		54,141
Net property, plant and equipment	1,601,178		1,463,797
Current Assets
Cash and cash equivalents	3,499		6,985
Trade and other receivables	61,675		50,899
Less: Allowance for credit losses	(4,785)		(1,337)
Trade receivables, net	56,890		49,562
Accrued revenue	21,527		20,846
Propane inventory, at average cost	5,906		5,824
Other inventory, at average cost	5,539		6,067
Regulatory assets	10,786		5,144
Storage gas prepayments	2,455		3,541
Income taxes receivable	12,885		20,050
Prepaid expenses	13,239		13,928
Derivative assets, at fair value	3,269		—
Other current assets	436		2,879
Total current assets	136,431		134,826
Deferred Charges and Other Assets
Goodwill	38,731		32,668
Other intangible assets, net	8,292		8,129
Investments, at fair value	10,776		9,229
Operating lease right-of-use assets	11,194		11,563
Regulatory assets	113,806		73,407
Receivables and other deferred charges	12,079		49,579
Total deferred charges and other assets	194,878		184,575
Total Assets	$	1,932,487	$	1,783,198

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

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Chesapeake Utilities Corporation and Subsidiaries

Consolidated Balance Sheets

	As of December 31,
Capitalization and Liabilities	2020		2019
(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)	8,499		7,984
Additional paid-in capital	348,482		259,253
Retained earnings	342,969		300,607
Accumulated other comprehensive loss	(2,865)		(6,267)
Deferred compensation obligation	5,679		4,543
Treasury stock	(5,679)		(4,543)
Total stockholders’ equity	697,085		561,577
Long-term debt, net of current maturities	508,499		440,168
Total capitalization	1,205,584		1,001,745
Current Liabilities
Current portion of long-term debt	13,600		45,600
Short-term borrowing	175,644		247,371
Accounts payable	60,253		54,068
Customer deposits and refunds	33,302		30,939
Accrued interest	2,905		2,554
Dividends payable	7,683		6,644
Accrued compensation	13,994		16,236
Regulatory liabilities	6,284		5,991
Derivative liabilities, at fair value	127		1,844
Other accrued liabilities	15,240		12,077
Total current liabilities	329,032		423,324
Deferred Credits and Other Liabilities
Deferred income taxes	205,388		180,656
Regulatory liabilities	142,736		127,744
Environmental liabilities	4,299		6,468
Other pension and benefit costs	30,673		30,569
Operating lease - liabilities	9,872		9,896
Deferred investment tax credits and other liabilities	4,903		2,796
Total deferred credits and other liabilities	397,871		358,129
Environmental and other commitments and contingencies (Note 20 and 21)
Total Capitalization and Liabilities	$	1,932,487	$	1,783,198

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

Chesapeake Utilities Corporation 2020 Form 10-K Page 53

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Consolidated Statements of Cash Flows

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Operating Activities
Net Income	$	71,498	$	65,153	$	56,580
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	58,117		45,900		40,802
Depreciation and accretion included in operations expenses	9,599		8,752		8,535
Deferred income taxes, net	24,709		24,476		21,226
Gain on sale of discontinued operations	(200)		(7,344)		—
Realized gain (loss) on sale of assets/commodity contracts	(6,243)		(4,135)		5,497
Unrealized loss (gain) on investments/commodity contracts	(1,482)		(1,595)		429
Employee benefits and compensation	207		1,985		856
Share-based compensation	4,829		4,279		2,813
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(7,426)		36,489		(16,311)
Propane inventory, storage gas and other inventory	1,709		8,227		2,107
Regulatory assets/liabilities, net	(4,973)		(7,812)		2,250
Prepaid expenses and other current assets	2,424		11,115		(7,421)
Accounts payable and other accrued liabilities	4,941		(62,021)		35,907
Income taxes receivable (payable)	7,165		(4,750)		(522)
Customer deposits and refunds	2,238		(1,811)		(596)
Accrued compensation	(2,473)		2,120		708
Other assets and liabilities, net	(5,723)		(16,064)		(35,498)
Net cash provided by operating activities	158,916		102,964		117,362
Investing Activities
Property, plant and equipment expenditures	(165,511)		(184,727)		(240,351)
Proceeds from sale of assets	8,080		427		782
Acquisitions, net of cash acquired	(22,231)		(23,988)		(16,654)
Proceeds from the sale of discontinued operations	200		22,871		—
Environmental expenditures	(2,169)		(1,170)		(625)
Net cash used in investing activities	(181,631)		(186,587)		(256,848)
Financing Activities
Common stock dividends	(27,161)		(24,693)		(22,043)
Issuance of stock for Dividend Reinvestment Plan	22,627		(721)		(706)
Proceeds from issuance of common stock, net of expenses	60,980		—		—
Tax withholding payments related to net settled stock compensation	(977)		(692)		(1,210)
Change in cash overdrafts due to outstanding checks	(825)		(1,174)		(5,943)
Net borrowings (repayments) under line of credit agreements	(71,637)		(45,913)		49,432
Proceeds from issuance of long-term debt	89,822		199,648		154,819
Repayment of long-term debt and finance lease obligation	(53,600)		(41,936)		(34,388)
Net cash provided by financing activities	19,229		84,519		139,961
Net (Decrease) Increase in Cash and Cash Equivalents	(3,486)		896		475
Cash and Cash Equivalents — Beginning of Period	6,985		6,089		5,614
Cash and Cash Equivalents — End of Period	$	3,499	$	6,985	$	6,089

Supplemental Cash Flow Disclosures (see Note 7)

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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 54

Table of Contents

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, 2017	16,344,442	$	7,955	$	253,470	$	229,141	$	(4,272)	$	3,395	$	(3,395)	$	486,294
Net Income	—	—		—		56,580		—		—		—		56,580
Cumulative effect of the adoption of ASU 2014-09	—	—		—		(1,498)		—		—		—		(1,498)
Reclassification upon the adoption of ASU 2018-02	—	—		—		907		(907)		—		—		—
Other comprehensive loss	—	—		—		—		(1,534)		—		—		(1,534)
Dividends declared ($1.4350 per share)	—	—		—		(23,600)		—		—		—		(23,600)
Dividend reinvestment plan	—	—		(3)		—		—		—		—		(3)
Share-based compensation and tax benefit (3) (4)	34,103	16		2,184		—		—		—		—		2,200
Treasury stock activities(2)	—	—		—		—		—		459		(459)		—
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 income	—	—		—		—		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)		—
Balances 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

(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 105,087, 95,329 and 97,053 shares at December 31, 2020, 2019 and 2018, 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 2020, 2019 and 2018, we withheld 10,319, 7,635 and 16,918 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 2020 Form 10-K Page 55

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 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 and Divestitures for further information.

Effects of COVID-19

On March 13, 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 have continued to significantly impact economic conditions in the United States. We are considered an “essential business,” which allows us to continue our operational activities and construction projects while the social distancing restrictions remain in place. In response to the COVID-19 pandemic and related restrictions, we implemented our pandemic response plan, which includes having all employees who can work remotely do so in order to promote social distancing and providing personal protective equipment to field employees to reduce the spread of COVID-19.

Impacts from the restrictions imposed in our service territories and the implementation of our pandemic response plan, included reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including 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 the fourth quarter of 2020, we established regulatory assets, as currently authorized by the Delaware, Maryland and Florida PSCs, associated with the incremental expenses incurred by our natural gas and electric distribution businesses as a result of the pandemic. We are continuing to provide timely updates, monitor developments affecting our employees, customers, suppliers and stockholders, and take the necessary precautions to operate safely and comply with the CDC, Occupational Safety and Health Administration, state and local requirements. 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.

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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 56

Notes to the Consolidated Financial Statements

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, 2020 and 2019 is provided in the following table:

	As of December 31,
(in thousands)	2020		2019
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	782,329	$	705,095
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	667,538		608,727
Electric distribution	127,710		127,651
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	151,258		141,945
Natural gas transmission and supply – Ohio	87,962		73,658
Electricity and steam generation	36,521		35,436
Mobile CNG and pipeline solutions	24,905		14,014
Other	30,769		40,006
Total property, plant and equipment	1,908,992		1,746,532
Less: Accumulated depreciation and amortization	(368,743)		(336,876)
Plus: Construction work in progress	60,929		54,141
Net property, plant and equipment	$	1,601,178	$	1,463,797

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, 2020 and 2019, the non-refundable contributions totaled $2.9 million and $2.1 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, 2020, 2019 and 2018 AFUDC totaled $0.7 million, $0.7 million and $1.9 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

Chesapeake Utilities Corporation 2020 Form 10-K Page 57

Notes to the Consolidated Financial Statements

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 $26.4 million of assets at December 31, 2020, 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 $0.3 million at December 31, 2020.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2020 and 2019, 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 $1.7 million and $1.5 million at December 31, 2020 and 2019, 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, 2020, 2019 and 2018:

	2020	2019	2018
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.6%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.6%	2.7%
Natural gas transmission – Florida	2.3%	2.4%	2.3%
Electric distribution	2.9%	3.4%	3.4%

Chesapeake Utilities Corporation 2020 Form 10-K     Page 58

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, 2020, 2019 and 2018, we reported $9.6 million, $8.8 million and $8.5 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 2020 Form 10-K Page 59

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.

Cost of Sales

Cost of sales includes 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 cost of sales.

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, impacts from pandemics and general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.

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, 2020, 2019 or 2018.

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, 2020, 2019 and 2018 indicated no goodwill impairment. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 60

Notes to the Consolidated Financial Statements

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 of each of our plans 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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 61

Notes to the Consolidated Financial Statements

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

Financial Instruments - Credit Losses (ASC 326) - In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments, which changes how entities account for credit losses for most financial assets and certain other instruments, and subsequent guidance which served to clarify or amend the original standard. ASU 2016-13 and the related amendments require entities to estimate lifetime expected credit losses for trade receivables and to provide additional disclosure related to credit losses. We adopted ASU 2016-13 on January 1, 2020 and recorded an immaterial cumulative effect in retained earnings as of that date. As a result, prior period financial information has not been recast and continues to be reported under the accounting guidance that was effective during those periods.

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 analyzed 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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 62

Notes to the Consolidated Financial Statements

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 have 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, 2020, 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, 2019	$	1,337
Additions:
Provision for credit losses	3,827
Recoveries	613
Deductions:
Write offs	(992)
Balance at December 31, 2020	$	4,785

Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. We adopted ASU 2018-13 beginning January 1, 2020 and, since the changes only impacted disclosures, its adoption did not have a material impact on our results of operations or financial position.

Intangibles - Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 was effective beginning January 1, 2020. The amendments included in this ASU are to be applied prospectively, and its adoption did not have a material impact on our results of operations or financial position.

Chesapeake Utilities Corporation 2020 Form 10-K Page 63

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 years ended December 31:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	70,642	$	61,100	$	56,968
Income/(Loss) from Discontinued Operations	856		4,053		(388)
Net Income	$	71,498	$	65,153	$	56,580
Weighted average shares outstanding	16,711,579		16,398,443		16,369,616
Earnings Per Share from Continuing Operations	$	4.23	$	3.73	$	3.48
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Basic Earnings Per Share	$	4.28	$	3.97	$	3.46
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,711,579		16,398,443		16,369,616
Effect of dilutive securities — Share-based compensation	59,156		50,043		50,254
Adjusted denominator — Diluted	16,770,735		16,448,486		16,419,870
Earnings Per Share from Continuing Operations	$	4.21	$	3.72	$	3.47
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Diluted Earnings Per Share	$	4.26	$	3.96	$	3.45

4. ACQUISITIONS AND DIVESTITURES

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 recorded contingent consideration of $0.3 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2020. There are multiple strategic benefits to this acquisition including it: (i) expands our propane territory serviced in Florida and (ii) includes an established customer base with 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. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021.

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 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. Elkton Gas continues to operate out of its existing office with the same local personnel who are now also serving our existing franchised service territory in Cecil County.

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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 64

Notes to the Consolidated Financial Statements

deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021.

Acquisition of Boulden

In December 2019, Sharp acquired certain propane operating assets of Boulden, which provides propane distribution service to approximately 5,200 customers in Delaware, Maryland and Pennsylvania, for approximately $24.6 million, net of cash acquired. Additionally, the purchase price included $0.2 million of working capital. We recorded contingent consideration of $0.6 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for the purchase of the operating assets of Boulden as a business combination and integrated the business into our Sharp operation. There are multiple strategic benefits to this acquisition including it: (i) overlays with the Elkton Gas acquisition to establish an integrated energy delivery platform in Cecil County, Maryland; (ii) includes an established customer base with opportunities for future growth; and (iii) enables operational synergies, including supply, for the northern Delmarva Peninsula.

In connection with this acquisition, we recorded $8.3 million in property, plant and equipment, $5.1 million in intangible assets associated with customer relationships and non-compete agreements and $11.2 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition were finalized in the fourth quarter of 2020.

These acquisitions generated the following operating revenues and income:

	For the Year Ended				For the Year Ended
	December 31, 2020				December 31, 2019
	Operating Revenues		Operating Income		Operating Revenues		Operating Income
(in thousands)
Western Natural Gas	$	555	$	90	$	—	$	—
Elkton Gas	$	2,399	$	418	$	—	$	—
Boulden	$	5,717	$	1,854	$	550	$	239

Divestiture of PESCO

During the fourth quarter of 2019, we sold PESCO's assets and contracts in four separate transactions and exited the natural gas marketing business. In 2020 and 2019, we received a total of $23.1 million in cash consideration from the buyers, inclusive of working capital of $8.0 million and recognized total pre-tax gain of $7.5 million ($5.4 million after tax) in connection with these transactions. As a result of the sales agreements, we began to report PESCO as discontinued operations during the third quarter of 2019, excluded PESCO's performance from continuing operations for all periods presented and classified its assets and liabilities as held for sale where applicable.

Operating revenues and costs of sales from the previous reporting periods, which were previously eliminated in consolidation related to intercompany sales and purchases, have been grossed up and are now reflected as a component of operating revenues and costs of sales for the year ended December 31, 2019 and 2018. We recast these amounts because, upon completion of the sales transactions, we continued to provide and receive services from the buyers through the remainder of the contractual terms.

Chesapeake Utilities Corporation 2020 Form 10-K Page 65

Notes to the Consolidated Financial Statements

A summary of discontinued operations presented in the consolidated statements of income includes the following:

	For the Year Ended December 31,
(in thousands)	2020		2019		2018
Operating revenues(1)	$	26	$	161,289	$	258,713
Cost of sales(1)	—		157,646		252,111
Other operating expenses	230		5,221		6,825
Operating loss	(204)		(1,578)		(223)
Interest and other income (expense)	1,013		(297)		(294)
Earnings / (Loss) from Discontinued Operations before income taxes	809		(1,875)		(517)
Gain on sale of Discontinued Operations	200		7,344		—
Income tax (benefit) / expense	153		1,416		(129)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	856	$	4,053	$	(388)

(1) Included in operating revenues and cost of sales for the years ended December 31, 2019 and 2018, is $19.8 million, and $31.5 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity which continued with the buyers after the disposition of the assets of PESCO.

Since the disposition of the assets and contracts of PESCO was completed in the fourth quarter of 2019, there were no assets or liabilities classified as held for sale at December 31, 2020 and December 31, 2019.

We have elected not to separately disclose discontinued operations on the consolidated statements of cash flows. The following table summarizes significant statements of cash flows data related to the discontinued operations of PESCO:

	For the Year Ended December 31,
(in thousands)	2019		2018
Depreciation and amortization	$	477	$	582
Property, plant and equipment expenditures	$	—	$	115
Deferred income taxes	$	(125)	$	1,088
Realized / (loss) gain on commodity contracts	$	(2,161)	$	5,002

Our Delmarva Peninsula natural gas distribution operations had executed asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and expired on March 31, 2020. As a result of the sale of the assets of PESCO, effective October 1, 2019, these agreements were managed by New Jersey Resource Energy Services Company through the remainder of the contract term. In March 2020, our Delmarva Peninsula natural gas distribution operations entered into new 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. In addition to the asset management agreements, Eastern Shore had several firm transportation and capacity arrangements with PESCO, which were included in the assets sold to United Energy Trading, LLC. Eastern Shore will continue to fulfill these arrangements throughout the remainder of their contractual term. These agreements currently have expiration dates of November 30, 2021.

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, 2020, 2019 and 2018:

Chesapeake Utilities Corporation 2020 Form 10-K     Page 66

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 2020 Form 10-K Page 67

Notes to the Consolidated Financial Statements

	For the year 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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 68

Notes to the Consolidated Financial Statements

	For the year ended December 31, 2018
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	70,338	$	—	$	—	$	70,338
Florida natural gas division	25,341		—		—		25,341
FPU electric distribution	79,803		—		—		79,803
FPU natural gas distribution	81,118		—		—		81,118
Maryland natural gas division	24,172		—		—		24,172
Sandpiper natural gas/propane operations	22,088		—		—		22,088
Total energy distribution	302,860		—		—		302,860
Energy transmission
Aspire Energy	—		35,407		—		35,407
Aspire Energy Express	—		—		—		—
Eastern Shore	64,248		—		—		64,248
Peninsula Pipeline	11,927		—		—		11,927
Total energy transmission	76,175		35,407		—		111,582
Energy generation
Eight Flags	—		17,302		—		17,302
Propane operations
Propane delivery operations	—		125,560		—		125,560
Energy delivery services
Marlin Gas Services	—		121		—		121
Other and eliminations
Eliminations	(33,754)		(16,485)		(17,522)		(67,761)
Other	—		—		652		652
Total other and eliminations	(33,754)		(16,485)		(16,870)		(67,109)
Total operating revenues (1)	$	345,281	$	161,905	$	(16,870)	$	490,316

(1) Total operating revenues for the year ended December 31, 2018, include other revenue (revenues from sources other than contracts with customers) of $0.2 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 2020 Form 10-K Page 69

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.

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, 2020 and 2019 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2019	$	47,430	$	3,465	$	589
Balance at 12/31/2020	55,600		4,816		644
Increase (decrease)	$	8,170	$	1,351	$	55

Our trade receivables are included in accounts receivable 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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 70

Notes to the Consolidated Financial Statements

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 year ended December 31, 2020 and 2019, we recognized revenue of $1.3 million and $1.0 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, 2020 are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026 and thereafter
Eastern Shore and Peninsula Pipeline	$	34,978	$	27,155	$	21,748	$	19,587	$	18,736	$	174,774
Natural gas distribution operations	4,351		5,394		4,937		4,705		4,172		32,996
FPU electric distribution	566		566		566		566		275		825
Total revenue contracts with remaining performance obligations	$	39,895	$	33,115	$	27,251	$	24,858	$	23,183	$	208,595

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 operating 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. Effective in the third quarter of 2019, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations. See Note 4, Acquisitions and Divestitures for additional details of the divestiture of PESCO.

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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 71

Notes to the Consolidated Financial Statements

The following table presents information about our reportable segments.

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	350,853	$	340,857	$	343,313
Unregulated Energy	137,345		138,748		147,003
Total operating revenues, unaffiliated customers	$	488,198	$	479,605	$	490,316
Intersegment Revenues (1)
Regulated Energy	$	1,893	$	2,149	$	1,968
Unregulated Energy	15,181		15,403		14,902
Other businesses	528		529		652
Total intersegment revenues	$	17,602	$	18,081	$	17,522
Operating Income
Regulated Energy	$	92,124	$	86,584	$	79,215
Unregulated Energy	20,664		19,938		17,125
Other businesses and eliminations	(65)		(237)		(1,496)
Operating Income	112,723		106,285		94,844
Other income (expense), net	3,222		(1,847)		(607)
Interest charges	21,765		22,224		16,146
Income from Continuing Operations before Income Taxes	94,180		82,214		78,091
Income Taxes on Continuing Operations	23,538		21,114		21,123
Income from Continuing Operations	70,642		61,100		56,968
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		(388)
Gain on sale of Discontinued Operations, Net of tax	170		5,402		—
Net Income	$	71,498	$	65,153	$	56,580
Depreciation and Amortization
Regulated Energy	$	46,079	$	35,227	$	31,876
Unregulated Energy	11,988		10,130		8,263
Other businesses and eliminations	50		67		81
Total depreciation and amortization	$	58,117	$	45,424	$	40,220
Capital Expenditures
Regulated Energy	$	147,100	130,604		$	235,912
Unregulated Energy	46,295		60,034		38,585
Other businesses	2,480		8,348		8,364
Total capital expenditures	$	195,875	$	198,986	$	282,861

 

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

	As of December 31,
	2020		2019
Identifiable Assets
Regulated Energy segment	$	1,547,619	$	1,434,066
Unregulated Energy segment	347,665		296,810
Other businesses and eliminations	37,203		52,322
Total identifiable assets	$	1,932,487	$	1,783,198

Chesapeake Utilities Corporation 2020 Form 10-K     Page 72

Notes to the Consolidated Financial Statements

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2020, 2019 and 2018 were as follows:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Cash paid for interest	$	22,884	$	23,856	$	16,741
Cash (received) paid for income taxes, net of refunds	$	(8,135)	$	3,221	$	477

Non-cash investing and financing activities during the years ended December 31, 2020, 2019, and 2018 were as follows: 

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	23,625	$	13,470	$	39,402
Common stock issued for the Retirement Savings Plan	$	1,605	$	—	$	—
Common stock issued under the SICP	$	1,971	$	1,691	$	2,006
Capital lease obligation	$	—	$	—	$	1,310

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, 2020 and 2019, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

PESCO's Derivative Instruments

As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts and, therefore, we no longer have natural gas futures and contracts recorded in our consolidated financial statements.

Volume of Derivative Activity

As of December 31, 2020, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	17.6	Cash flows hedges	May 2023
Sharp	Propane (gallons)	0.4	Fair value hedges	February 2021

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 during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in December 2020 through May 2023) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap 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 $2.7 million of unrealized gain from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2021.

Chesapeake Utilities Corporation 2020 Form 10-K Page 73

Notes to the Consolidated Financial Statements

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.

We designated and accounted for 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. We expect to reclassify less than $0.1 million from accumulated other comprehensive income (loss) to earnings during the next 12-month period ended December 31, 2021.

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, with the balance related to the account is as follows:

(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
Sharp	Other Current Assets	$	—	$	2,317
Sharp	Other Current Liabilities	$	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, 2020 and 2019 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	3,255		—
Total Derivative Assets		$	3,269	$	—

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	64		1,844
Interest rate swap agreements	Derivative liabilities, at fair value	40		—
Total Derivative Liabilities		$	127	$	1,844

Chesapeake Utilities Corporation 2020 Form 10-K     Page 74

Notes to the Consolidated Financial Statements

 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)		2020		2019		2018
Derivatives not designated as hedging instruments
Propane swap agreements	Cost of sales	$	—	$	—	$	(13)
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	(12)		—		—
Put/Call option	Propane inventory	34		—		—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	2,428		1,520		(647)
Propane swap agreements	Other comprehensive income (loss)	5,035		(253)		(2,773)
Interest rate swap agreements	Interest expense	60		—		—
Interest rate swap agreements	Other comprehensive income (loss)	(40)		—		—
Natural gas swap contracts	Other comprehensive income (loss)	—		(63)		200
Natural gas futures contracts	Other comprehensive income (loss)	—		(294)		532
Total		$	7,505	$	910	$	(2,701)

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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 75

Notes to the Consolidated Financial Statements

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2020 and 2019, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2019	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	$	27	$	27	$	—	$	—
Investments—guaranteed income fund	803		—		—		803
Investments—mutual funds and other	8,399		8,399		—		—
Total investments	9,229		8,426		—		803
Derivative assets	—		—		—		—
Total assets	$	9,229	$	8,426	$	—	$	803
Liabilities:
Derivative liabilities	$	1,844	$	—	$	1,844	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Beginning Balance	$	803	$	686
Purchases and adjustments	261		131
Transfers/disbursements	1,065		(29)
Investment income	27		15
Ending Balance	$	2,156	$	803

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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 76

Notes to the Consolidated Financial Statements

At December 31, 2020 and 2019, 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, 2020, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $523.0 million, compared to the estimated fair value of $548.5 million. At December 31, 2019, long-term debt, which includes the current maturities but excludes finance lease obligations and debt issuance costs, had a carrying value of $486.6 million, compared to a fair value of $505.0 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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

10. INVESTMENTS

 The investment balances at December 31, 2020 and 2019, consisted of the following:

	As of December 31,
(in thousands)	2020		2019
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	10,755	$	9,202
Investments in equity securities	21		27
Total	$	10,776	$	9,229

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2020, 2019 and 2018, we recorded net unrealized gains of $1.5 million, $1.6 million, and net unrealized losses of $0.4 million, respectively in other income (expense) 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, 2020 and 2019 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2019	$	3,353	$	29,315	$	32,668
Additions (1)	4,264		1,799		6,063
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731

(1)Includes goodwill from the purchase of operating assets of Elkton Gas in the third quarter of 2020 and Western Natural Gas in October 2020.

The annual impairment testing for 2020 and 2019 indicated no impairment of goodwill.

Chesapeake Utilities Corporation 2020 Form 10-K Page 77

Notes to the Consolidated Financial Statements

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2020 and 2019 are as follows:

	As of December 31,
	2020				2019
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	10,680	$	4,269	$	9,391	$	3,463
Non-Compete agreements (1)	2,375		768		2,252		451
Patents	452		236		452		118
Other	270		212		270		204
Total	$	13,777	$	5,485	$	12,365	$	4,236

(1) The customer relationship and non-compete agreements amounts includes $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 amounts also include customer relationship and non-compete agreements amounts of $4.6 million and $0.5 million, respectively, recorded as a result of the purchase of the operating assets of Boulden in December 2019.

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 11 years. Amortization expense of intangible assets for the year ended December 31, 2020, 2019 and 2018 was $1.2 million, $0.8 million and $0.4 million, respectively. Amortization expense of intangible assets is expected to be $1.3 million for the year 2021, $1.0 million for the year 2022 and $0.9 million for the years 2023 through 2025.

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 operations and/or are required to file. Our state returns for tax years after 2015 are subject to examination. At December 31, 2020, 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 NOL 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 NOL in various states of $40.0 million and $54.7 million as of December 31, 2020 and 2019, respectively, almost all of which will expire in 2039. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.6 million and $5.5 million related to state NOL carry-forwards at December 31, 2020 and 2019, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized.

Tax Law Changes

In March 2020, the CARES Act was signed into law and included several significant changes to the Internal Revenue Code. The CARES Act includes certain tax relief provisions including the ability to carryback five years net operating losses arising in a tax year beginning in 2018, 2019, or 2020. This provision allows a taxpayer to recover taxes previously paid at a 35 percent federal income tax rate during tax years prior to 2018. In addition, the CARES Act removed the taxable income limitation to allow a tax NOL to fully offset taxable income for tax years beginning before January 1, 2021. Our income tax expense for the year ended December 31, 2020 included a tax benefit of $1.8 million attributable to the tax NOL carryback provided under the CARES Act for losses generated in 2018 and 2019 and then applied back to our 2013 and 2015 tax years in which we paid federal income taxes at a 35 percent tax rate.

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 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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 78

Notes to the Consolidated Financial Statements

The following tables provide: (a) the components of income tax expense in 2020, 2019, and 2018; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2020, 2019, and 2018 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2020 and 2019.

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Current Income Tax Expense
Federal	$	(2,777)	$	(2,252)	$	(361)
State	2,162		(491)		617
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	(662)		(2,790)		209
Deferred Income Tax Expense (1)
Property, plant and equipment	23,224		25,907		19,178
Deferred gas costs	(714)		79		(1,435)
Pensions and other employee benefits	(75)		(454)		454
FPU merger-related premium cost and deferred gain	156		(278)		(528)
Net operating loss carryforwards	5,107		(3,772)		(250)
Other	(3,498)		2,422		3,495
Total deferred income tax expense	24,200		23,904		20,914
Income Tax Expense from Continuing Operations	23,538		21,114		21,123
Income Tax Expense (benefit) from Discontinued Operations	153		1,416		(129)
Total Income Tax	$	23,691	$	22,530	$	20,994

(1) Includes $4.9 million, $4.7 million, and $3.5 million of deferred state income taxes for the years 2020, 2019 and 2018, respectively.

	For the Year Ended December 31,
	2020			2019			2018
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	19,778		$	17,264		$	16,400
State income taxes, net of federal benefit	5,051			5,093			4,071
ESOP dividend deduction	(218)			(173)			(158)
CARES Act Tax Benefit	(1,841)			—			—
Other	768			(1,070)			810
Total Income Tax Expense for Continuing Operations	$	23,538		$	21,114		$	21,123
Effective Income Tax Rate for Continuing Operations	24.99		%	25.65		%	27.13		%

(1) Federal income taxes were calculated at 21 percent for 2020, 2019, and 2018.

Chesapeake Utilities Corporation 2020 Form 10-K Page 79

Notes to the Consolidated Financial Statements

	As of December 31,
	2020		2019
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	199,287	$	173,466
Acquisition adjustment	6,618		6,969
Loss on reacquired debt	201		220
Deferred gas costs	509		1,223
Natural gas conversion costs	5,379		4,956
Storm reserve liability	7,073		10,316
Other	5,587		1,456
Total deferred income tax liabilities	224,654		198,606
Deferred income tax assets:
Pension and other employee benefits	4,636		3,818
Environmental costs	1,064		1,486
Net operating loss carryforwards	1,587		5,523
Self-insurance	—		146
Storm reserve liability	409		96
Accrued Expenses	6,153		2,064
Other	5,417		4,817
Total deferred income tax assets	19,266		17,950
Deferred Income Taxes Per Consolidated Balance Sheets	$	205,388	$	180,656

Chesapeake Utilities Corporation 2020 Form 10-K     Page 80

Notes to the Consolidated Financial Statements

13. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2020		2019
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	—	$	7,990
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	—		2,000
5.93% note, due October 31, 2023	9,000		12,000
5.68% note, due June 30, 2026	17,400		20,300
6.43% note, due May 2, 2028	5,600		6,300
3.73% note, due December 16, 2028	16,000		18,000
3.88% note, due May 15, 2029	45,000		50,000
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		—
2.96% note, due August 15, 2035	40,000		—
Term Note due February 28, 2020	—		30,000
Less: debt issuance costs	(901)		(822)
Total long-term debt	522,099		485,768
Less: current maturities	(13,600)		(45,600)
Total long-term debt, net of current maturities	$	508,499	$	440,168

Annual maturities

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

Year	2021		2022		2023		2024		2025		Thereafter		Total
(in thousands)
Payments	$	13,600	$	17,100	$	20,600	$	17,600	$	24,600	$	429,500	$	523,000

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our shelf agreements at December 31, 2020:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		—		150,000
NYL Shelf Agreement (3)	150,000		(140,000)		—		10,000
Total	$	670,000	$	(360,000)	$	—	$	310,000

Chesapeake Utilities Corporation 2020 Form 10-K Page 81

Notes to the Consolidated Financial Statements

(1) In April 2020, we amended the Prudential Shelf Agreement to increase the available borrowing capacity by $150.0 million. The Shelf Agreement expires in April 2023. In July 2020, we issued $50 million of Prudential Shelf Notes at the rate of 3.00 percent per annum.

(2) In May 2020, we amended an agreement with MetLife to provide a new $150 million MetLife Shelf Agreement for a three-year term ending May 2023.

(3) In August 2020 we issued $40 million of NYL Shelf Notes at the rate of 2.96 percent per annum. The NYL Shelf Agreement expires in November 2021.

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.

Term Notes

In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. This note was paid in full in February 2020 utilizing our short-term borrowing facilities.

Secured First Mortgage Bonds

In December 2020, we redeemed FPU’s 9.08 percent secured first mortgage bonds outstanding of $8.0 million, prior to their maturity, which included the outstanding principal balances, interest accrued, premium and fees. We used short-term borrowing to finance the redemption of these bonds. The difference between the carrying value of those bonds and the amount paid at redemption totaling $1.0 million was charged to expense. As a result of the redemption of these bonds, at December 31, 2020, the restriction that limited the payment of dividends by FPU is no longer applicable.

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, 2020, the cumulative consolidated net income base was $581.0 million, offset by restricted payments of $256.4 million, leaving $324.6 million of cumulative net income free of restrictions. As of December 31, 2020, we were in compliance with all of our debt covenants.

14. SHORT-TERM BORROWINGS

At December 31, 2020 and 2019, our short-term borrowings totaled $175.6 million and $247.4 million, respectively, at the weighted average interest rates of 1.28 percent and 2.62 percent, respectively. Included in the December 31, 2020 balance, is $60.0 million in short-term debt for which we have entered into interest rate swap agreements.

In September 2020, we entered into a new $375.0 million syndicated Revolver with six participating lenders. As a result of entering into the Revolver, in September 2020, we terminated and paid all outstanding balances under the previously existing bilateral lines of credit and the previous revolving credit facility.

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, 2020, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is 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 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 total indebtedness to total capitalization ratio. As of December 31, 2020, our pricing under the Revolver included a commitment fee of 0.175 percent and an interest rate of 1.125 percent over LIBOR. Our available credit under the new Revolver at December 31, 2020 was $196.9 million. As of December 31, 2020, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. Although the letters of credit are not included in the outstanding short-

Chesapeake Utilities Corporation 2020 Form 10-K     Page 82

Notes to the Consolidated Financial Statements

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 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. The fixed swap rates 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 amounts totaling $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.

We are authorized by our Board of Directors to borrow up to $375 million of short-term debt, as required.

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 the Mid-Atlantic, Mid-West and in Florida. 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, 2020, 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, 2020, 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	2020		2019
Operating lease cost (1)	Operations expense	$	2,029	$	2,577
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	—		650
Interest on lease liabilities	Interest expense	—		5
Net lease cost		$	2,029	$	3,232

(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, 2020 and 2019:

Chesapeake Utilities Corporation 2020 Form 10-K Page 83

Notes to the Consolidated Financial Statements

(in thousands)	Balance sheet classification	December 31, 2020		December 31, 2019
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,194	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,747	$	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,872		9,896
Total lease liabilities		$	11,619	$	11,601

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2020 and 2019:

	December 31, 2020		December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.70		8.88
Weighted-average discount rate
Operating leases	3.8	%	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, 2020 and 2019:

	Year Ended December 31,
(in thousands)	2020		2019
Operating cash flows from operating leases	$	1,956	$	2,230
Operating cash flows from finance leases	$	—	$	5
Financing cash flows from finance leases	$	—	$	650

The following table presents the future undiscounted maturities of our operating leases at December 31, 2020 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2021	$	2,027
2022	1,984
2023	1,923
2024	1,657
2025	1,395
Thereafter	4,419
Total lease payments	13,405
Less: Interest	1,786
Present value of lease liabilities	$	11,619

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

Chesapeake Utilities Corporation 2020 Form 10-K     Page 84

Notes to the Consolidated Financial Statements

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 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 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 loss for the years ended December 31, 2020 and 2019. 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, 2018	$	(5,928)	$	(785)	$	—	$	(6,713)
Other comprehensive income (loss) before reclassifications	(872)		2,161		—		1,289
Amounts reclassified from accumulated other comprehensive income (loss)	1,867		(2,595)		—		(728)
Net current-period other comprehensive income (loss)	995		(434)		—		561
Prior-year reclassification	—		(115)		—		(115)
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)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2020, 2019 and 2018. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.

Chesapeake Utilities Corporation 2020 Form 10-K Page 85

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
(in thousands)	2020		2019		2018
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(592)		(2,600)		(579)
Total before income taxes	(515)		(2,523)		(502)
Income tax benefit (4)	150		656		63
Net of tax	$	(365)	$	(1,867)	$	(439)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	2,428	$	1,520	$	(647)
Natural gas swaps (2)(3)	—		7		197
Natural gas futures (2)(3)	—		2,096		(2,010)
Total before income taxes	2,428		3,623		(2,460)
Income tax (expense) benefit (4)	(671)		(1,028)		701
Net of tax	$	1,757	$	2,595	$	(1,759)
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	60	$	—	$	—
Total before income taxes	60		—		—
Income tax expense	(16)		—		—
Net of tax	$	44	$	—	$	—
Total reclassifications for the period	$	1,436	$	728	$	(2,198)

(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

We sponsor three defined benefit pension plans: the Chesapeake Utilities Pension Plan ("Chesapeake Pension Plan"), the FPU Pension Plan and the Chesapeake SERP.

The Chesapeake Pension Plan, a qualified plan, was closed to new participants, effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation, effective January 1, 2005. Benefits under the Chesapeake Pension 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 Pension Plan was frozen were credited with two additional years of service. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result, during the fourth quarter of 2019, we purchased annuities for those retirees currently receiving monthly payments and offered lump-sum payments to terminated vested employees. Accordingly, the pension settlement expense associated with the de-risking strategy allocated to our Regulated Energy operations was recorded as regulatory assets or deferred pending regulatory approval authorizing recovery through rates. The remaining portion of the pension settlement expense totaling $0.7 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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 86

Notes to the Consolidated Financial Statements

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, 2020 and 2019, 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, 2020 and 2019 and the net periodic cost for the years ended December 31, 2020, 2019 and 2018 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2020			2019			2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,214		$	10,712		$	65,304		$	59,377		$	2,157		$	2,285
Interest cost	176			375			2,085			2,452			63			74
Actuarial loss	450			1,443			6,069			6,508			144			159
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Benefit obligation — end of year	6,146			6,214			70,366			65,304			2,212			2,157
Change in plan assets:
Fair value of plan assets — beginning of year	4,630			8,649			49,703			43,601			—			—
Actual return on plan assets	369			1,180			6,581			7,978			—			—
Employer contributions	304			1,117			2,774			1,157			152			361
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Fair value of plan assets — end of year	4,609			4,630			55,966			49,703			—			—
Reconciliation:
Funded status	(1,537)			(1,584)			(14,400)			(15,601)			(2,212)			(2,157)
Accrued pension cost	$	(1,537)		$	(1,584)		$	(14,400)		$	(15,601)		$	(2,212)		$	(2,157)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%	2.25		%	3.00		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.50		%	—		%	—		%

Chesapeake Utilities Corporation 2020 Form 10-K Page 87

Notes to the Consolidated Financial Statements

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2020			2019 (1)			2018			2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic pension cost:
Interest cost	$	176		$	375		$	384		$	2,085		$	2,452		$	2,339		$	63		$	74		$	83
Expected return on assets	(157)			(487)			(542)			(2,967)			(2,770)			(3,091)			—			—			—
Amortization of actuarial loss	243			391			343			552			505			404			20			85			101
Settlement expense	203			1,982			—			—			—			—			—			58			—
Net periodic pension cost	465			2,261			185			(330)			187			(348)			83			217			184
Amortization of pre-merger regulatory asset	—			—			—			—			543			761			—			—			—
Total periodic cost	$	465		$	2,261		$	185		$	(330)		$	730		$	413		$	83		$	217		$	184
Assumptions:
Discount rate	3.00		%	3.00		%	3.50		%	3.25		%	4.25		%	3.75		%	3.00		%	4.00		%	3.50		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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.

Included in the net periodic costs for the FPU Pension Plan for the years ended December 31, 2019 and 2018 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. At December 31, 2020 and 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. The changes in investment types for the Chesapeake Pension Plan at December 31, 2020 and 2019, compared to same period in 2018, are associated with the de-risking strategy executed during the fourth quarter of 2019. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2020, 2019 and 2018:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2020		2019		2018		2020		2019		2018
Asset Category
Equity securities	—	%	—	%	49	%	54	%	53	%	50	%
Debt securities	96	%	92	%	41	%	37	%	37	%	41	%
Other	4	%	8	%	10	%	9	%	10	%	9	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

The investment policy of both the Chesapeake Utilities and FPU Pension Plans 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 plans, earn a competitive return to increasingly fund a large portion of the plans’ 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 each plan.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 88

Notes to the Consolidated Financial Statements

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ 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	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
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, 2020 and 2019, 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, 2020								At December 31, 2019
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)	$	3,615	$	—	$	—	$	3,615	$	3,553	$	—	$	—	$	3,553
U.S. Mid Cap (1)	1,672		—		—		1,672		1,604		—		—		1,604
U.S. Small Cap (1)	891		—		—		891		726		—		—		726
International (2)	11,307		—		—		11,307		9,855		—		—		9,855
Alternative Strategies (3)	5,586		—		—		5,586		4,739		—		—		4,739
	23,071		—		—		23,071		20,477		—		—		20,477
Mutual Funds - Debt securities
Fixed income (4)	21,563		—		—		21,563		19,220		—		—		19,220
High Yield (4)	2,606		—		—		2,606		2,476		—		—		2,476
	24,169		—		—		24,169		21,696		—		—		21,696
Mutual Funds - Other
Commodities (5)	2,246		—		—		2,246		1,708		—		—		1,708
Real Estate (6)	1,954		—		—		1,954		2,288		—		—		2,288
Guaranteed deposit (7)	—		—		1,019		1,019		—		—		1,147		1,147
	4,200		—		1,019		5,219		3,996		—		1,147		5,143
Total Pension Plan Assets in fair value hierarchy	$	51,440	$	—	$	1,019	52,459		$	46,169	$	—	$	1,147	47,316
Investments measured at net asset value (8)							8,116								7,017
Total Pension Plan Assets							$	60,575							$	54,333

(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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 89

Notes to the Consolidated Financial Statements

At December 31, 2020 and 2019, 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, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Balance, beginning of year	$	1,147	$	627
Purchases	3,190		2,274
Transfers in	921		3,090
Disbursements	(4,290)		(4,907)
Investment income	51		63
Balance, end of year	$	1,019	$	1,147

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, 2020 and 2019:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,100		$	1,002		$	1,224		$	1,187
Interest cost	26			39			30			48
Plan participants contributions	166			149			37			38
Actuarial loss (gain)	(34)			73			(181)			47
Benefits paid	(225)			(163)			(101)			(96)
Benefit obligation — end of year	1,033			1,100			1,009			1,224
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	59			14			64			58
Plan participants contributions	166			149			37			38
Benefits paid	(225)			(163)			(101)			(96)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,033)			(1,100)			(1,009)			(1,224)
Accrued postretirement cost	$	(1,033)		$	(1,100)		$	(1,009)		$	(1,224)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%

Chesapeake Utilities Corporation 2020 Form 10-K     Page 90

Notes to the Consolidated Financial Statements

Net periodic postretirement benefit costs for 2020, 2019, and 2018 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	26		$	39		$	38		$	30		$	48		$	47
Amortization of actuarial loss	24			46			58			(19)			—			—
Amortization of prior service cost (credit)	(77)			(77)			(77)			—			—			—
Net periodic cost	(27)			8			19			11			48			47
Amortization of pre-merger regulatory asset	—			—			—			6			8			8
Total periodic cost	$	(27)		$	8		$	19		$	17		$	56		$	55
Assumptions
Discount rate	3.00		%	4.00		%	3.50		%	3.25		%	4.25		%	3.75		%

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, 2020:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(370)	$	—	$	(370)
Net loss (gain)	2,033		21,242		699		546		(194)		24,326
Total	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,033	$	4,036	$	699	$	176	$	(37)	$	6,907
Post-merger regulatory asset	—		17,206		—		—		(157)		17,049
Total unrecognized cost	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2020 is net of income tax benefits of $1.8 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, 2020, 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 2020, 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. Since Chesapeake Utilities' plans and FPU’s plans have different expected plan lives, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan and the de-risking strategy implemented in the fourth quarter of 2019 for Chesapeake's Plan, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake Utilities' and FPU’s plans. Since both pension plans are 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 2020 used to calculate the benefit obligation is 5.0 percent for medical and 6.0 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5.0 percent for both medical and prescription drugs for the FPU Medical Plan.

Chesapeake Utilities Corporation 2020 Form 10-K Page 91

Notes to the Consolidated Financial Statements

Estimated Future Benefit Payments

In 2021, we expect to contribute $0.3 million and $2.1 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, 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 2021.

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

	Chesapeake Pension Plan(1)		FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2021	$	384	$	3,409	$	151	$	68	$	67
2022	$	99	$	3,493	$	150	$	66	$	67
2023	$	981	$	3,559	$	148	$	61	$	66
2024	$	106	$	3,601	$	146	$	58	$	67
2025	$	1,007	$	3,680	$	158	$	55	$	67
Years 2026 through 2030	$	1,193	$	18,627	$	735	$	222	$	317

(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, 2020, 2019 and 2018, 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, $5.7 million, and $5.5 million for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, there were 813,230 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 designated by the Compensation Committee, 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 $10.8 million and $9.2 million at December 31, 2020 and 2019, 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 2020 Form 10-K     Page 92

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 $5.7 million and $4.5 million at December 31, 2020 and 2019, 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 415,412 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, 2020, 2019 and 2018:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Awards to non-employee directors	$	733	$	620	$	539
Awards to key employees	4,096		3,659		2,871
Total compensation expense	4,829		4,279		3,410
Less: tax benefit	(1,254)		(1,117)		(934)
Share-based compensation amounts included in net income	$	3,575	$	3,162	$	2,476

Stock Options

There were no stock options outstanding or issued during the years 2018 through 2020.

Non-employee Directors

Shares granted to non-employee directors are issued in advance of these directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2019, each of our non-employee directors received an annual retainer of 751 shares of common stock under the SICP for board service through the 2020 Annual Meeting of Stockholders; accordingly, 6,759 shares, with a weighted average fair value of $93.14 per share, were issued and vested in 2019. In May 2020, each of our non-employee directors received an annual retainer of 887 shares of common stock under the SICP for service as a director 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.

In January 2020, a newly appointed member of our Board of Directors received a pro-rated retainer of 254 shares of common stock under the SICP to serve as a non-employee director through the 2020 Annual Meeting of Stockholders. The shares awarded to the non-employee director immediately vested upon issuance in January 2020, had a weighted average fair value of $95.83 per share, and the expense was recognized over the remaining service period ending on the date of the 2020 Annual Meeting of Stockholders

At December 31, 2020, 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 on the date of 2021 Annual Meeting of Stockholders.

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.

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 2020 Form 10-K Page 93

Notes to the Consolidated Financial Statements

The table below presents the summary of the stock activity for awards to key employees:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2018	131,741	$	67.24
Granted (1)	88,048	92.74
Vested	(25,831)	67.08
Expired	(15,086)	69.28
Forfeited (2)	(21,055)	71.67
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

(1) Includes 43,032 shares that were granted to certain key employees in December 2019 associated with their promotion.

(2) In conjunction with the retirement of two key employees during 2019, these shares were forfeited for the remainder of the service periods associated with awards granted during their employment with the Company.

The intrinsic value of these awards was $20.2 million, $15.1 million and $10.7 million in 2020, 2019 and 2018, respectively. At December 31, 2020, there was $3.9 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2022.

In 2020, 2019 and 2018, 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,
	2020		2019		2018
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,319		7,635		16,918
Amounts remitted to tax authorities to satisfy obligations	$	977	$	692	$	1,210

Chesapeake Utilities Corporation 2020 Form 10-K     Page 94

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

CGS: In August 2019, we filed with the Delaware PSC an application seeking an order that will establish the regulatory accounting treatment and valuation methodology for the acquisition of propane CGS owned by our affiliate, Sharp and the conversion of the CGS to natural gas service. We proposed to acquire each CGS one at a time and to pay replacement cost for each CGS system. In addition, we requested authorization to pay for and capitalize the CGS residents’ behind-the-meter conversion costs. Our existing natural gas customers will be protected against subsidizing the acquisitions and conversions of the CGS systems because we will complete only those systems that meet our economic test. The application was reviewed by the Delaware PSC, who approved and issued a final order in June 2020.

Maryland

Approval of the Elkton Gas Acquisition: In December 2019, we entered into an agreement with South Jersey Industries, Inc. to acquire its subsidiary, Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Elkton Gas territory is contiguous to our franchised service territory in Cecil County, Maryland. On June 29, 2020, the Maryland PSC issued a final order approving the settlement agreement, therefore, enabling the transaction to move forward. In July 2020, the transaction closed and we acquired Elkton Gas as our wholly-owned subsidiary.

Application for Authority to Exercise a Franchise: In March 2020, we filed with the Maryland PSC an application seeking approval to exercise a franchise granted to us by the Board of County Commissioners of Somerset County, Maryland in December 2019. The application was approved in June 2020.

Florida

Hurricane Michael: In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane 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, after exerting extraordinary hurricane restoration efforts, restored service to those customers who were able to accept it. 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. Additionally, in 2019, amounts undergoing review by the Florida PSC for regulatory asset treatment were recorded as receivables and other deferred charges.

In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as regulatory assets for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested to 10 years, and included costs related to Hurricane Dorian of approximately $1.2 million in this filing.

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 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 and a regulatory asset for cost of removal and undepreciated plant. The new base rates and storm surcharge were effective on November 1, 2020.

Electric Depreciation Study: 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.

Chesapeake Utilities Corporation 2020 Form 10-K Page 95

Notes to the Consolidated Financial Statements

West Palm Beach Expansion Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with FPU. Peninsula Pipeline will construct 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 will provide transportation service to FPU, increasing reliability, system pressure as well as introducing diversity in fuel source for natural gas to serve the increased demand in these areas. The petition was approved by the Florida PSC at the August 6, 2019 Agenda. Interim services began in the fourth quarter of 2019. We expect to complete the remainder of the project in phases through the second quarter of 2021.

Callahan Pipeline, Nassau County: In the second quarter of 2020, Peninsula Pipeline and Seacoast Gas Transmission completed construction of a jointly owned 26-mile, 16-inch steel pipeline that interconnects to the Cypress Pipeline interstate system in western Nassau County in order to serve growing demand in both Nassau and Duval counties, Florida. The Callahan pipeline terminates into the existing Peninsula Pipeline, which serves Amelia Island and the Peoples Gas distribution system. The Callahan Pipeline has enhanced FPU’s ability to expand service into Nassau County and has enabled Peoples Gas to enhance its system pressure and the reliability of its service in Duval County.

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, which was applied for in September 2018 by Eastern Shore, approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include 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. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021.

Capital Cost Surcharge: In December 2019, the FERC approved Eastern Shore’s proposed 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. Eastern Shore expects to recover $0.5 million in capital cost surcharges on an annual basis. As government mandated relocations continue resulting in Eastern Shore undertaking capital expenditures, we will continue to utilize the surcharge to seek recovery of these costs in accordance with the settlement from Eastern Shore’s last general rate case.

Renewable Natural Gas Tariff: In October 2019, Eastern Shore filed an application with the FERC to include renewable natural gas (biogas) utilization and standards in its tariff. Eastern Shore had proposed changes to its gas quality specifications that would enable it to accommodate renewable natural gas at various receipt points on its system. Changes to the gas quality specifications would ensure interchangeability of renewable natural gas with the natural gas currently delivered to Eastern Shore. The tariffs became effective in November 2019.

Ohio

Aspire Energy Express: In October 2020, the Public Utilities Commission of Ohio approved the request by Aspire Energy Express for authority to operate as an intrastate pipeline company in Ohio and also approved the submitted tariff. Aspire Energy Express will utilize the pipeline to provide natural gas transportation service in Ohio, including delivery to the Guernsey Power Station and other potential customers elsewhere in Ohio. Aspire Energy Express has entered into agreements with the Guernsey Power Station to construct the pipeline and provide natural gas transportation service to the facility, which the Public Utilities Commission of Ohio approved in November 2020. Aspire Energy Express intends to own and operate the proposed intrastate pipeline facilities that will interconnect with the Rockies Express Pipeline and other potential points of receipt. The pipeline facilities that will be initially constructed will provide firm transportation service to the Guernsey Power Station. Aspire Energy Express will be subject to ongoing jurisdiction and supervision of the Public Utilities Commission of Ohio with respect to the gas pipeline safety standards and requirements.

COVID-19 Impact

We are monitoring the global outbreak of COVID-19 and taking steps to mitigate the potential risks posed by its spread. We provide an “essential service” to our customers, which means that it is paramount that we keep our employees who operate our business safe and informed. We have taken and are continuously monitoring and updating precautions and protocols to ensure the safety of our employees and customers. As an “essential business” we are allowed to continue operational activity and construction projects with appropriate safety precautions, personal protective equipment and social distancing restrictions in

Chesapeake Utilities Corporation 2020 Form 10-K     Page 96

Notes to the Consolidated Financial Statements

place. We have taken steps to assure our customers that disconnections for non-payment will be temporarily suspended. We are also working with our suppliers to understand the potential impacts to our supply chain; if material negative impacts are identified, we will work to mitigate them. This is a rapidly evolving situation, and could lead to extended disruption of economic activity in our markets. We will continue to monitor developments affecting our employees, customers, suppliers and shareholders, and will take additional precautions as warranted to comply with the CDC, state and local requirements and recommendations to protect our employees, customers and the communities we serve.

As a result of these measures, we are incurring costs associated with crisis management and the pandemic response including restrictions put in place by the state PSCs on utility disconnects for non-payment, technology costs incurred to expand work from home capabilities, additional sanitation and cleaning costs and costs of acquiring personal protective equipment as well as other expenses.

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 this period, 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.

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 creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs.

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish regulatory asset to record incremental expenses incurred due to COVID-19. This regulatory asset will allow us to seek recovery of these costs in our next base rate proceeding. On November 16, 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset, contending that the order should be a reversed or modified and to request a hearing on the protest. At this time, no hearing date has been established.

In the fourth quarter of 2020, we established regulatory assets based on the net incremental expense resulting from the pandemic for our natural gas distribution and electric businesses as currently authorized by the Delaware, Maryland and Florida PSCs.

Chesapeake Utilities Corporation 2020 Form 10-K Page 97

Notes to the Consolidated Financial Statements

The table below highlights the impact to our various regulated businesses as a result of the TCJA:

Summary TCJA Table

	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates were adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,728	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates were adjusted in March 2019.
Maryland Division (Maryland PSC)	$3,970	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates were adjusted in May 2018.
Sandpiper Energy (Maryland PSC)	$3,713	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018. Customer rates were adjusted in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,257	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$309	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Utilities Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit is provided to customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.
Elkton Gas (Maryland PSC)	$1,124	PSC approved amortization of ADIT in March 2018.	Previous owner implemented one-time bill credit (totaling less than $0.1 million) in May 2020. Customer rates were adjusted in April 2020.

Regulatory Assets and Liabilities

At December 31, 2020 and 2019, our regulated utility operations had 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 2020 Form 10-K     Page 98

Notes to the Consolidated Financial Statements

	As of December 31,
	2020		2019
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	2,078	$	5,144
Under-recovered GRIP revenue (2)	278		—
Deferred postretirement benefits (3)	17,716		16,311
Deferred conversion and development costs (1)	23,054		20,881
Environmental regulatory assets and expenditures (4)	1,743		2,241
Acquisition adjustment (5)	28,755		30,329
Loss on reacquired debt (6)	795		869
Deferred costs associated with COVID-19 (7)	1,925		—
Deferred storm costs (8)	44,320		—
Other	3,928		2,776
Total Regulatory Assets	$	124,592	$	78,551
Regulatory Liabilities
Self-insurance (9)	$	533	$	873
Over-recovered purchased fuel and conservation cost recovery (1)	4,422		2,724
Over-recovered GRIP revenue (2)	338		2,668
Storm reserve (9)	2,673		1,437
Accrued asset removal cost (10)	45,315		36,767
Deferred income taxes due to rate change (11)	90,845		89,191
Interest related to storm recovery (8)	3,353		—
Other	1,541		75
Total Regulatory Liabilities	$	149,020	$	133,735

(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 de-risking of the Chesapeake Pension Plan pursuant to an order from the FERC that allowed us to defer Eastern Shore's 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 2020 Form 10-K Page 99

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, 2020 and 2019, we had approximately $5.9 million and $8.0 million, respectively, in environmental liabilities, related to FPU’s 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, 2020 and 2019, we have recovered approximately $12.4 million and $11.9 million, respectively, leaving approximately $1.6 million and $2.1 million, respectively, in regulatory assets for future recovery 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.

The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:

MGP Site (Jurisdiction)	Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
West Palm Beach (Florida)	Remediation actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remediation actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2021.	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.
Sanford (Florida)	In March 2018, the United States Environmental Protection Agency ("EPA") approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be immaterial.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $0.4 million.
Seaford (Delaware)	Conducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction is being implemented, in accordance with the DNREC-approved Work Plan.	Between $0.2 million and $0.5 million.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 100

Notes to the Consolidated Financial Statements

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 on March 31, 2023.

In May 2019, FPU natural gas distribution operations and Eight Flags entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. Short-term agreements were entered for a term beginning July 2019 through October 2020 with long-term agreements executed for a 10-year term that commenced in November 2020.

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, 2020, 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	2021		2022-2023		2024-2025		Beyond 2025		Total
(in thousands)
Purchase Obligations	$	69,459	$	81,841	$	69,420	$	201,504	$	422,224

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, 2020 was $20.0 million. The aggregate amount guaranteed at December 31, 2020 was approximately $5.7 million with the guarantees expiring on various dates through September 2021.

As of December 31, 2020, we have issued letters of credit totaling approximately $4.8 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 and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. There have been no draws on these letters of credit as of December 31, 2020. 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 2020 Form 10-K Page 101

Notes to the Consolidated Financial Statements

22. 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	$	1.24
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	$	1.28
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.64	$	0.56	$	1.24
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	$	1.28
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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 102

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, 2020. 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, 2020.

CHANGE IN INTERNAL CONTROLS

In response to the COVID-19 pandemic and the current social distancing restrictions that have been established in our service territories, we have implemented our pandemic response plan, which includes having office staff work remotely to promote social distancing in efforts to reduce the spread of COVID-19. During the quarter ended December 31, 2020, the implementation of 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, 2020, 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, 2020. In addition, on May 19, 2020, 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, 2020.

Our independent registered public accounting firm, Baker Tilly US, LLP (formerly Baker Tilly Virchow Krause, LLP), has audited the effectiveness of our internal control over financial reporting as of December 31, 2020, as stated in its report which appears under Part II, Item 8. Financial Statements and Supplementary Data. 

Chesapeake Utilities Corporation 2020 Form 10-K Page 103

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, 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."

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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

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

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

(a)(3) The Exhibits below.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 104

• 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. †
•       Exhibit 4.6	Master Note Agreement dated March 2, 2017, among Chesapeake Utilities Corporation, as issuer, NYL Investors LLC, and other certain note holders that may become party thereto from time to time relating to the private placement of Chesapeake Utilities Corporation’s 3.48% Senior Notes due 2038 and Chesapeake Utilities Corporation’s 3.58% Senior Notes due 2038, and Chesapeake Utilities Corporation’s 2.96% Senior Notes due 2035 †

Chesapeake Utilities Corporation 2020 Form 10-K Page 105

• Exhibit 4.7	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*	Form of Performance Share Agreement, effective February 23, 2017 for the period 2017 to 2019, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Beth W. Cooper, Jeffry M. Householder, and James F. Moriarty, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the year ended June 30, 2017, File No. 001-11590.
•     Exhibit 10.9	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 10.10	Form of Performance Share Agreement, effective February 26, 2018 for the period 2018 to 2020, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Beth W. Cooper, Jeffry M. Householder and James F. Moriarty, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-11590.
•      Exhibit 10.11*	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..
•      Exhibit 10.12*	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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 106

•      Exhibit 10.13	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 10.14	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 10.15*	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 10.16	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 10.17*	Form of Performance Share Agreement, effective December 3, 2019 for the period 2019 to 2020, 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 10.25 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 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 10.19*	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 10.20*	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 10.21*	Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.29 to our Annual Report on Form 10-K for the year ended December 31, 2019, File No. 001-11590.
•      Exhibit 10.22*	Executive Employment Agreement dated May 6, 2020 between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
•      Exhibit 10.23*	Executive Employment Agreement dated May 6, 2020 between Chesapeake Utilities Corporation and James F. Moriarty, is incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.24*	Executive Employment Agreement dated December 24, 2019, between Chesapeake Utilities Corporation and Jeffry S. Sylvester, is filed herewith.

Chesapeake Utilities Corporation 2020 Form 10-K Page 107

• Exhibit 10.25*	Amendment to Executive Employment Agreement dated February 22, 2021, between Chesapeake Utilities Corporation and Beth W. Cooper is filed herewith.
• Exhibit 10.26*	Amendment to Executive Employment Agreement dated February 22, 2021, between Chesapeake Utilities Corporation and Jeffry M. Householder is filed herewith.
• Exhibit 10.27*	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 10.28	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 10.29	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 10.30	Revolving Line of Credit Note dated April 24, 2020 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is incorporated herein by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.31	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 10.32	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 10.33	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 10.34	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 10.35	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 10.36	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 21	Subsidiaries of the Registrant is filed herewith.
•       Exhibit 23.1	Consent of Independent Registered Public Accounting Firm is filed herewith.
•       Exhibit 31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
•       Exhibit 32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
•       Exhibit 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.

Chesapeake Utilities Corporation 2020 Form 10-K     Page 108

•       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 2020 Form 10-K Page 109

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 24, 2021

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 24, 2021	and Assistant Corporate Secretary
	(Principal Financial and Accounting Officer)
	February 24, 2021
/S/ JOHN R. SCHIMKAITIS	/S/ DENNIS S. HUDSON, III
John R. Schimkaitis	Dennis S. Hudson, III, Director
Chair of the Board and Director	February 24, 2021
February 24, 2021
/S/ EUGENE H. BAYARD, ESQ	/S/ LILA A. JABER
Eugene H. Bayard, Esq., Director	Lila A. Jaber, Director
February 24, 2021	February 24, 2021
/S/ THOMAS J. BRESNAN	/S/ PAUL L. MADDOCK, JR.
Thomas J. Bresnan, Director	Paul L. Maddock, Jr., Director
February 24, 2021	February 24, 2021
/S/ RONALD G. FORSYTHE, JR.	/S/ CALVERT A. MORGAN, JR.
Dr. Ronald G. Forsythe, Jr., Director	Calvert A. Morgan, Jr., Director
February 24, 2021	February 24, 2021
/S/ THOMAS P. HILL, JR.	/S/ DIANNA F. MORGAN
Thomas P. Hill, Jr., Director	Dianna F. Morgan, Director
February 24, 2021	February 24, 2021

Chesapeake Utilities Corporation 2020 Form 10-K     Page 110

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
2020	$	1,337	$	3,827	$	613	$	(992)	$	4,785
2019	$	1,058	$	1,392	$	278	$	(1,391)	$	1,337
2018	$	876	$	1,119	$	133	$	(1,070)	$	1,058

(1) Recoveries.

(2) Uncollectible accounts charged off.

Chesapeake Utilities Corporation 2020 Form 10-K Page 111

EX-4.7

Exhibit 4.7

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, 2021, 17,473,124 shares 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.

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.

Exhibit 4.7

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-10.24

Exhibit 10.24

EXECUTIVE EMPLOYMENT AGREEMENT

This Executive Employment Agreement (the "Agreement") dated this 4th day of December, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the "Company"), and Jeffrey S. Sylvester (the "Executive").

Recitals

WHEREAS, the Company is currently obtaining the benefit of Executive's services as a full-time executive employee in the capacity of Senior Vice President, Transmission and Distribution;

WHEREAS, the Company's Board of Directors (the "Board") has authorized the Company to provide for the Executive's continued employment pursuant to the terms of this Agreement as the Company’s Senior Vice President, Transmission and Distribution; and

WHEREAS, Executive is willing, in consideration of the covenants and consideration hereinafter provided, to continue to be employed by the Company in the capacity of Senior Vice President, Transmission and Distribution and to render services incident to such position during the term of this Agreement.

Agreement

In consideration of the mutual promises and covenants contained herein, the Company and Executive hereby agree as follows:

1.Employment. The Company agrees to employ Executive, and Executive agrees to accept employment, as an officer of the Company in the capacity of Senior Vice President, Transmission and Distribution, with such authority, duties and responsibilities as are customarily assigned to such position, including such reasonable duties and responsibilities as may be requested of the Executive by the Board of Directors and which are consistent with the By-laws of the Company as in effect from time to time including, but not limited to, responsibility for direction of the Transmission, Distribution, and Customer Care functions of the Company.

1.Term.

a.Term of Agreement. The term of this Agreement ("Term") shall be the Current Term (as defined in Paragraph 2(b)), and, if applicable, the Extended Term (as defined in Paragraph 2(c)).

a.Current Term. Subject to Paragraph 2(c), the Current Term of this Agreement shall extend for two (2) years commencing on December 4, 2019. If the Current Term of this Agreement expires without there having been a Change in Control (as hereinafter defined), this Agreement may be renewed for successive one (1) year terms, as of the day following such

Exhibit 10.24

expiration, by the Company through action of the Compensation Committee of the Board of Directors, unless, during the period beginning ninety (90) days prior and ending thirty (30) days prior to such day, either the Company or Executive shall have given notice to the other that this Agreement will not be renewed. If the Company determines to extend or renew this Agreement as provided under this Paragraph, the new Agreement shall be identical to this Agreement (except insofar as the Company and Executive may otherwise agree in writing) except that the date of the new Agreement shall be as of the day following the expiration of the Current Term of this Agreement or any renewal term.

a.Extended Term. Upon the occurrence of a Change in Control (as defined in Paragraph 2(d)), the Current Term shall end and the Term of this Agreement shall thereupon automatically be extended, commencing on the date of such Change in Control, for a period of two

(2) years ( the "Extended Term").

a.Change In Control. For the purposes of this Agreement, "Change in Control" shall mean a change in the control of the Company during the Term of this Agreement, which shall be deemed to have occurred upon the first of the following events:

i.any one person, or group of owners of another corporation who acting together through a merger, consolidation, purchase, acquisition of stock or the like (a "Group"), acquires ownership of stock of the Company (or a majority-controlled subsidiary of the Company) that, together with the stock held by such person or Group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company. However, if such person or Group is considered to own more than fifty percent (50%) of the total fair market value or total voting power of the stock of the corporation before this transfer of the Company's stock, the acquisition of additional stock by the same person or Group shall not be considered to cause a Change in Control of the Company; or

i.any one person or Group acquires (or has acquired during the twelve

(12) month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company (or a majority-controlled subsidiary of the Company) possessing thirty-five percent (35%) or more of the total voting power of the stock of the Company where such person or Group is not merely acquiring additional control of the Company; or

i.a majority of members of the Company's Board (other than the Board of a majority-controlled subsidiary of the Company) is replaced during any twelve

(12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Company's Board prior to the date of the appointment or election (the “Incumbent Board”), but excluding, for purposes of determining whether a majority of the Incumbent Board has endorsed any candidate for election to the Board, any individual whose initial assumption of office occurs as a result of

Exhibit 10.24

an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person or Group other than the Company’s Board; or

i.any one person or Group acquires (or has acquired during the twelve

a.month period ending on the date of the most recent acquisition by such person or Group) assets from the Company (or a majority-controlled subsidiary of the Company) that have a total gross fair market value equal to or more than forty percent (40%) of the total fair market value of all assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, gross fair market value means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets. A transfer of assets by the Company will not result in a Change in Control if the assets are transferred to:

i.a stockholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

i.an entity, fifty percent (50%) or more of the total value or voting power of which is owned, directly or indirectly, by the Company immediately after the transfer of assets;

i.a person or Group that owns, directly or indirectly, fifty percent (50%) or more of the total value or voting power of all the outstanding stock of the Company; or

i.an entity, at least fifty percent (50%) of the total value or voting power of which is owned directly or indirectly, by a person described in subparagraph (d)(i), above.

However, no Change in Control shall be deemed to have occurred with respect to the Executive by reason of (1) any event involving a transaction in which the Executive or a group of persons or entities with which the Executive acts in concert, acquires, directly or indirectly, more than thirty percent (30%) of the Common Stock of the business or assets of the Company; or (2) any event involving or arising out of a proceeding under Title 11 of the United States Code (or the provisions of any future United States bankruptcy law), or an assignment for the benefit of creditors or an insolvency proceeding under state or local law.

1.Time. Executive agrees to devote all reasonable full time and best efforts for the benefit of the Company and any subsidiary of the Company, and not to serve any other business enterprise or organization in any capacity during the Term of this Agreement without the prior written consent of the Company, which consent shall not be unreasonably withheld.

1.Office.

a.Current Term. During the Current Term, the Executive shall serve in the capacity as defined in Paragraph 1 and the parties agree that the Company shall elect the Executive to these offices, on an annual basis if necessary, during the Current Term of this Agreement.

Exhibit 10.24

a.Extended Term. During the Extended Term of this Agreement the Executive shall hold and perform an office with the responsibility, importance and scope within the Company at least equal to that of the office described and contemplated in Paragraph 1. Further, Executive's office shall be located in Dover, Delaware, and Executive shall not be required, without his written consent, to change his office location or to be absent therefrom on business for more than sixty (60) working days in any year.

1.Compensation and Benefits.

a.Base Compensation; Current Term. The Company shall compensate Executive for his services hereunder during the Current Term at a rate of $300,000 per annum, or such amount as the Board may from time to time determine ("Base Compensation"), payable in installments on the Company’s regular payroll dates for salaried executives. The Base Compensation rate shall be reviewed annually and may be increased or decreased, from time to time, provided, however, that Base Compensation shall only be decreased by the Board on a good faith basis and with reasonable justification for the same, and provided further, that in the event of a Change in Control, Base Compensation shall not at any time thereafter be decreased.

a.Base Compensation; Extended Term. During the Extended Term, the Company shall compensate Executive for his services hereunder at a rate per annum, payable in installments on the Company’s regular payroll dates for salaried executives, equal to his Base Compensation at the time the Extended Term commences, which may be increased, but not decreased, by such additional amounts as the Board may determine from time to time based, in part, on an annual review of the Executive's compensation and performance.

a.Incentive Plans. During the Term of this Agreement, Executive shall be entitled to participate in all bonus, incentive compensation and performance based compensation plans, and other similar policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive's participation shall be in accordance with the terms and provisions of such plans and programs. Participation shall include, but not be limited to:

i.Chesapeake Utilities Corporation Long-Term 2013 Stock and Incentive Compensation Plan. Executive shall be eligible for a performance incentive compensation award as determined on an annual basis by the Compensation Committee of the Board of Directors in its discretion and in

4

JSS

Initials

accordance with and subject to the terms of the Company’s 2013 Stock and Incentive Compensation Plan (the “Equity Plan”) during the Term of this Agreement. The Equity

Exhibit 10.24

Plan’s Target Bonus as a percent of base salary shall be reviewed annually and may be increased or decreased, from time to time, provided, however, that Target shall only be decreased by the Board on a good faith basis and with reasonable justification for the same, and provided further, that in the event of a Change in Control, Target shall not at any time thereafter be decreased.

i.Chesapeake Utilities Corporation Cash Bonus Incentive Plan. Executive shall be eligible for an annual cash bonus award with a target award amount equal to thirty five (35%) of Executive’s Base Compensation, as determined on an annual basis by the Compensation Committee of the Board in its discretion and in accordance with and subject to the terms of the Company’s Cash Bonus Incentive Plan during the Term of this Agreement.

a.Recovery of Compensation. The Executive acknowledges and agrees that all or any portion of an incentive award under the above described bonus and incentive compensation plans or any future arrangement established by the Company to provide incentive or bonus compensation, whether payable in cash, Company common stock or other property, (“Award”) is subject to an obligation of repayment by the Executive to the Company if the amount of the Award was calculated based upon the achievement of certain financial results (as reflected in the financial statement of the Company or otherwise) or other performance metrics that, in either case, were subsequently found to be materially inaccurate. The amount that shall be repaid by the Executive to the Company shall be based on the excess amount paid or awarded to the Executive under the Award as compared to the amount that would have been paid or awarded had the material inaccuracy not occurred. If the Compensation Committee of the Board of Directors determines that the Executive engaged in misconduct, malfeasance or gross negligence in the performance of his or her duties that either caused or significantly contributed to the material inaccuracy in financial statements or other performance metrics, there shall be no time limit on this right of recovery, which shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this Agreement. In all other circumstances, this right of recovery shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this agreement for a period not exceeding one year after the date of payment of each such Award. In addition, the Executive hereby agrees that, if he or she does not promptly repay the amount recoverable hereunder within thirty (30) days of a demand therefore, such amount may be withheld from compensation of any type not yet due and payable to the Executive, including, but not limited to, the cancellation of future Awards, as determined by the Compensation Committee in its sole discretion. In addition, the Compensation Committee is granted the discretionary authority to interpret and enforce this provision as it determines to be in the best interest of the Company and equitable to the parties. Notwithstanding anything herein, this provision shall not be the Company’s exclusive remedy with respect to such matters. In addition, the parties agree that the Company may unilaterally amend this provision at any time to comply with applicable law or securities exchange listing rules, as the same may be in

effect from time to time, during the Current Term or the Extended Term of this Agreement.

Exhibit 10.24

a.Retirement Plans. During the Term of this Agreement, Executive shall be entitled to participate in all profit-sharing, savings and retirement benefit plans, plans that are supplemental to any tax-qualified savings and retirement plans, and other similar policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive's participation shall be in accordance with the terms and provisions of such plans and programs.

a.Welfare Benefits. During the Term of this Agreement, Executive, and his family, as applicable, shall be entitled to participate in all insurance, medical, health and welfare, and similar plans and arrangements, as well as all vacation and other employee fringe benefit plans, perquisite plans, and other policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive’s participation shall be in accordance with the terms and provisions of such plans.

a.Other Benefits. During the Term of this Agreement, the Company shall furnish Executive with a suitable office, necessary administrative support and customary furniture and furnishings for such office. The Company further agrees that Executive shall have the use of a Company-owned or Company-leased and Company-maintained automobile, new every three (3) years, of a kind and model appropriate to his position with the Company.

a.Expenses. During the Term of this Agreement, the Company shall pay all necessary and reasonable business expenses incurred by Executive on behalf of the Company in the course of his employment hereunder, including, without limitation, expenses incurred in the conduct of the Company's business while away from his domicile and properly substantiated expenses for travel, meals, lodging, entertainment and related expenses that are for the benefit of the Company. All expense reimbursements shall comply with applicable rules or guidelines of the Company in effect at the time the expense is incurred.

If any reimbursements under this or any other provision of this Agreement are taxable to the Executive, such reimbursements shall be paid on or before the end of the calendar year following the calendar year in which the reimbursable expense was incurred, and the Company shall not be obligated to pay any such reimbursement amount for which Executive fails to submit an invoice or other documented reimbursement request at least 10 business days before the end of the calendar year next following the calendar year in which the expense was incurred. Such expenses shall be reimbursable only to the extent they were incurred during the term of the Agreement. In addition, the amount of such reimbursements that the Company is obligated to pay in any given calendar year shall not affect the amount the Company is obligated to pay in any other calendar year. In addition, Executive may not liquidate or exchange the right to reimbursement of such

expenses for any other benefits.

Exhibit 10.24

a.Nothing in this Agreement shall preclude the Company from amending or terminating any employee benefit plan or practice, but, it being the intent of the parties that the Executive shall continue to be entitled during the Extended Term to compensation, benefits, reimbursements and perquisites as set forth in Paragraphs 5(a) through 5(c) and 5(e) through 5(h) at least equal to those attached to his position on the date of this Agreement, and nothing in this Agreement shall operate as, or be construed to authorize, a reduction during the Extended Term without Executive's written consent in the level of such compensation, benefits, reimbursements or perquisites as in effect on the date of a Change in Control. If and to the extent that such compensation, benefits, reimbursements or perquisites are not payable or provided to Executive under any such plan or practice by reason of an amendment thereto or termination thereof during the Extended Term, the Company shall nevertheless pay or provide such compensation, benefits, reimbursements or perquisites to Executive, either directly or through alternative arrangements.

1.Termination.

a.Payment Upon Termination During Current Term. In the event that the Company terminates this Agreement during the Current Term, or elects not to renew this Agreement at the end of the Current Term, for any reason other than Cause, as defined below, or the Executive’s death, the Company shall continue to pay to Executive (or in the event of his death following such termination, his legal representative), as a severance benefit his Base Compensation under Paragraph 5(a), at the rate in effect immediately prior to the date of such termination ("Termination Date"), on the regular payroll dates occurring during the period of one (1) year following the Termination Date. In addition, and notwithstanding the foregoing provisions of this Paragraph 6(a), to the extent required in order to comply with Section 409A of the Internal Revenue Code of 1986, as amended (the "Code"), Termination Date shall be determined based on the date the Executive has a “separation from service” within the meaning of Code Section 409A and regulations thereunder, using the default rule under such regulations (“Separation from Service”), and cash amounts that would otherwise be payable under this Paragraph 6(a) during the six-month period immediately following the Termination Date shall instead be paid, with interest on any delayed payment at the applicable federal rate under Code Section 7872(f)(2)(A), on the first business day after the date that is six (6) months following the Executive’s Separation from Service if necessary to comply with Code Section 409A. Each payment to be made under this Paragraph 6(a) shall be considered a separate payment. Payment of the severance benefit under this Paragraph is subject to the Executive’s compliance with the covenants of Paragraph 9 and the execution and delivery (and non- revocation) of a release of claims (the “Release”) against the Company and its officers, directors, employees and affiliates, which Release must be delivered to the Company not later than 45 days after the Termination Date. If the Executive fails to comply with any of the covenants of Paragraph 9 or fails to deliver the Release within 45 days after the Termination Date, or if the Executive revokes such Release within 7 days after its delivery to the Company, payment of the severance benefits shall cease and any unpaid amounts shall be forfeited. Payment commencement shall not be delayed, however, pending delivery of the Release.

Exhibit 10.24

a.Termination for Cause. This Agreement and Executive's employment hereunder may be terminated by the Company at any time for Cause. In the event of termination for Cause, the Executive shall not be entitled to any severance benefits under this Agreement. Termination of the Executive's employment shall be deemed to have been "for Cause" only if it shall have been the result of:

i.Executive’s conviction of a felony under the laws of the United States or a state in which Executive works or resides, or a guilty or no contest plea by the Executive with respect thereto;

i.a willful or deliberate act or acts of dishonesty by Executive resulting or intended to result directly or indirectly in material gain to or personal enrichment of Executive at the Company's expense;

i.a deliberate and intentional refusal by Executive (except by reason of incapacity due to illness or accident) to comply with the provisions of Paragraph 1, provided that such breach shall have resulted in demonstrably material injury to the Company and the Executive shall have failed to remedy such breach within thirty

(30) days after notice from the Secretary of the Company demanding that the Executive remedy such breach; or

i.conduct by Executive that is materially injurious to the Company if such conduct was undertaken without good faith and the reasonable belief that such conduct was in the best interest of the Company.

a.Payment Upon Termination During Extended Term. In the event of a Termination Without Cause, as defined below, during the Extended Term, the Company shall pay to Executive (or, in the event of his death following the termination, his legal representative) in cash, on the first business day that falls on or after the sixtieth (60th) day after the date of such termination (the "Extended Termination Date") the sum of all accrued but unpaid salary, bonus, vacation pay, expense reimbursements and any other amounts due, plus the following:

i.an amount equal to the product of multiplying the monthly rate of Base Compensation to which Executive was entitled under Paragraph 5(a) on the day immediately prior to the Extended Termination Date by Twenty-four (24) months ("Covered Period");

i.an amount equal to the aggregate of the Company's contributions to the Company's savings plan (including, but not limited to, the Chesapeake Utilities Corporation Retirement Savings Plan, and any related excess benefit plans) in respect of Executive that were not vested on the day immediately prior to the Extended

Termination Date but that would have been vested at the end of the Covered Period if Executive had remained employed by the Company for the duration of that period; and

Exhibit 10.24

i.an amount equal to the product of multiplying the average of the annual aggregate benefits awarded to the Executive under all annual bonus program(s) of the Company in which the Executive was a participant in each of the three (3) calendar years immediately preceding the calendar year in which the Extended Termination Date occurs by two (2) years.

Payment of the severance benefit under this Paragraph is subject to the Executive’s compliance with the covenants of Paragraph 9 and the execution and delivery (and non-revocation) of a release of claims (the “Release”) against the Company and its officers, directors, employees and affiliates, which Release must be delivered to the Company not later than 45 days after the Termination Date. If the Executive fails to comply with any of the covenants of Paragraph 9 or fails to deliver the Release within 45 days after the Termination Date, or if the Executive revokes such Release within

7 days after its delivery to the Company, payment of the severance benefits shall cease (if commenced) or shall not be made, and any unpaid amounts shall be forfeited.

In addition, the Company shall continue to provide medical, prescription drug, vision, dental and other Company welfare benefits to the Executive and his eligible dependents during the Covered Period as if the Executive remained an active employee of the Company (but, with respect to any such benefits provided through insurance, only if and to the extent it is permissible to extend such benefits to a former employee of the Company under the terms of the applicable plan and insurance contracts). Executive further acknowledges that the cost of the coverage afforded to Executive and his eligible dependents under self-funded medical expense reimbursement plans of the Company during the Covered Period shall be treated as additional taxable income to the Executive to the extent necessary to avoid a violation of the nondiscrimination provisions of Section 105(h) of the Code. Should the continuation of any medical or similar coverages be through fully insured plans, and should such continuation violate the nondiscrimination requirements for such plans under the Patient Protection and Affordable Care Act of 2010, then the Executive shall receive additional cash severance benefits rather than continued coverage under such plans of the Company in an amount based on the premium cost of such coverage that the Company would otherwise pay under this paragraph. In addition, the applicable period of health benefit continuation under Code Section 4980B shall begin at the end of the Covered Period.

To the extent required in order to comply with Code Section 409A, cash amounts that would otherwise be payable under this Paragraph 6(c) during the six-month period immediately following the Extended Termination Date (and which are not eligible for the exception applicable to payments due to involuntary separation under Treas. Reg. Section 1.409A-1(b)(9)(iii)) shall instead be paid, with interest on any delayed payment at the applicable federal rate under Code Section 7872(f)(2)(A), on the first business day after the date that is six (6) months following the Executive's Separation from Service. Further, any taxable welfare benefits provided to Executive pursuant to this Paragraph 6(c) that are not "disability pay" or "death benefits" within the meaning of Treas.

Reg. Section 1.409A-1(a)(5) (collectively, the "Applicable Benefits") shall be subject to the following requirements in order to comply with Code Section 409A. The amount of any Applicable Benefits provided during one taxable year shall not affect the amount of the

Exhibit 10.24

Applicable Benefits provided in any other taxable year, except that with respect to any Applicable Benefits that consist of the reimbursement of expenses referred to in Code Section 105(b), a limitation may be imposed on the amount of such reimbursements over some or all of the Covered Period, as described in Treas. Reg. Section 1.409A-3(i)(1)iv(B). To the extent that any Applicable Benefits consist of the reimbursement of eligible expenses, such reimbursement must be made on or before the last day of the calendar year following the calendar year in which the expense was incurred. No Applicable Benefits may be liquidated or exchanged for another benefit. During the period of six (6) months immediately following Executive's Separation from Service, Executive shall be obligated to pay the Company the full cost for any Applicable Benefits that do not constitute health benefits of the type required to be provided under the health continuation coverage requirements of Code Section 4980B, and the Company shall reimburse Executive for any such payments on the first business day that is more than six (6) months after Executive's Separation from Service, together with interest on such amount from the date of Separation from Service through the date of payment at the applicable federal rate under Code Section 7872(f)(2)(A).

a.Termination Without Cause. For purposes of Paragraph 6(c) above, "Termination Without Cause" shall mean a Separation from Service of the Executive that is either a:

i.Termination by the Company of Executive's employment without Cause (as "Cause" is defined in Paragraph 6(b) above); or

i.Termination by Executive of his employment following the occurrence of any of the following events:

1.failure to elect or re-elect Executive to, or removal of Executive from, the office or offices set forth in Paragraph 1, or failure to nominate Executive for election to the Board if Executive shall have been a member of the Board immediately prior to a Change in Control of the Company;

1.a significant change in the nature or scope of his authorities, powers, functions, duties or responsibilities attached to the positions contemplated in Paragraph 1, or a reduction in his compensation or in the benefits available to the Executive and his family, as provided in Paragraph 5, which change or reduction is not remedied within thirty (30) days after notice to the Company by the Executive;

1.any other breach by the Company of any material provision of this Agreement (including, without limitation, relocation of the Executive in material violation of Paragraph 4(b)), which breach is not remedied within

thirty (30) days after notice to the Company by Executive; or

1.the consolidation or merger of the Company or transfer of all or a significant portion of its assets unless a successor or successors (by merger, consolidation or otherwise) to which all or a significant portion of its assets has been transferred shall have assumed all duties and obligations of the Company under this Agreement.

Exhibit 10.24

In order to effect a Termination Without Cause in any event set forth in this Paragraph 6(d)(ii), Executive must elect to terminate his employment under this Agreement upon not less than forty (40) days and not more than ninety (90) days' written notice to the Board, attention of the Chief Executive Officer, given, except in the case of a continuing breach, within three (3) calendar months after: (1) failure to be so elected, reelected, or nominated, or such removal, (2) expiration of the 30-day cure period with respect to such event, or (3) the closing date of such consolidation, merger or transfer of assets.

An election by Executive to terminate his employment under the provisions of this Paragraph shall not be deemed a voluntary termination of employment by Executive for the purpose of this Agreement or any plan or practice of the Company. Further, the death of the Executive during the Extended Term but prior to a Termination Without Cause, as defined, shall not constitute Cause or be deemed to be a Termination Without Cause.

a.Resignation of All Other Positions. Upon termination of the Executive’s employment hereunder for any reason, the Executive shall be deemed to have resigned from all positions that the Executive holds as an officer or member of the Board of Directors of the Company or any affiliates unless otherwise determined by the Board.

1.Maximum Payment Upon Termination.

a.Determination. 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 Executive 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 Paragraph 6(c) of this Agreement or otherwise, then the Executive’s benefits under this Agreement shall be reduced by the amount necessary so that the Executive’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 determination concerning the application of the reduction shall be made by a nationally-recognized firm of independent accountants (together with legal counsel of its choosing) selected by the Company after consultation with the Executive (which may be the Company’s independent auditors), whose determination shall be conclusive and binding on all parties. Any fees and

expenses of such independent accountants and counsel (including counsel for the Executive) shall be borne by the Company.

a.Notices. If it is determined that the benefits under this Agreement must be reduced under this Paragraph, within 10 days of the date of such determination, the Company will apprise the Executive of the amount of the reduction ("Notice of Reduction"). Within 10 days of receiving that information, the Executive may specify how (and against which benefit or payment source) the reduction is to be applied ("Notice of Application"). The Company will be required to implement these directions within 10 days of receiving the Notice of Application. If the Company has not received a Notice of Application from the

Exhibit 10.24

Executive within 10 days of the date of the Notice of Reduction, the Company will apply this Paragraph proportionately based on the amounts otherwise payable under Paragraph 6(c). If the Company receives a Notice of Application that does not fully implement the requirements of this Paragraph, the Company will apply this Paragraph proportionately on the basis of the reductions specified in the Notice of Application first, then to any remaining reduction based on the amounts otherwise payable under Paragraph 6(c).

Notwithstanding the foregoing, if the exercise of discretion reserved to the Executive in determining the Notice of Application would violate Code Section 409A, then such discretion shall be eliminated and the amounts payable under Paragraph 6(c) shall be reduced proportionately.

1.Mitigation. Executive shall not be required to mitigate the amount of any payment provided for in this Agreement either by seeking other employment or otherwise. The amount of any payment provided for herein shall not be reduced by any remuneration that Executive may earn from employment with another employer or otherwise following his Termination Date or Extended Termination Date, as applicable.

1.Covenants.

a.Introduction. The parties acknowledge that the provisions and covenants contained in this Paragraph 9 are ancillary and material to this Agreement and that the limitations contained herein are reasonable in geographic and temporal scope and do not impose a greater restriction or restraint than is necessary to protect the goodwill and other legitimate business interests of the Company. The parties also acknowledge and agree that the provisions of this Paragraph 9 do not adversely affect Executive’s ability to earn a living in any capacity that does not violate the covenants contained herein. The parties further acknowledge and agree that the provisions of Paragraph 19 below are accurate and necessary because (i) Delaware is the headquarters state of the Company, which has operations in multiple states and a compelling interest in having its employees treated uniformly, (ii) the use of Delaware law provides certainty to the parties in any covenant litigation in the United States, and (iii) enforcement of the provisions of this Paragraph 9 would not violate any fundamental public policy of Delaware or any other jurisdiction.

a.Confidential Information. Executive shall hold in a fiduciary capacity for the benefit of the Company, all secret or confidential information, knowledge or data relating to the

Company and its businesses (including, but not limited to, any proprietary and not publicly available information concerning any processes, methods, trade secrets, costs, names of users or purchasers of the Company’s products or services, business methods, financial affairs, operating procedures or programs or methods of promotion and sale) that Executive has obtained or obtains during Executive’s employment by the Company and that is not public knowledge (other than as a result of Executive’s violation of this Paragraph 9(b)) ("Confidential Information"). For purposes of this Paragraph 9(b), information shall not be deemed to be publicly available merely because it is embraced by general disclosures or because individual features or combinations thereof are publicly available. Executive shall not communicate, divulge or disseminate

Exhibit 10.24

Confidential Information at any time during or after Executive’s employment with the Company except:

i.to employees or agents of the Company that need the Confidential Information to perform their duties on behalf of the Company;

i.in the performance of Executive’s duties to the Company;

i.as a necessary (and only to the extent necessary) part of any undertaking by Executive to enforce Executive’s rights under this Agreement; or

i.as otherwise required by law or legal process.

All confidential records, files, memoranda, reports, customer lists, drawings, plans, documents and the like that Executive uses, prepares or comes into contact with during the course of Executive’s employment shall remain the sole property of the Company and shall be turned over to the Company upon termination of Executive’s employment.

a.Non-solicitation of Company Employees. Executive shall not, at any time during the Restricted Period (as defined below), without the prior written consent of the Company, engage in the following conduct (a "Solicitation"):

i.directly or indirectly, contact, solicit, recruit or employ (whether as an employee, officer, director, agent, consultant or independent contractor) any person who was or is at any time during the previous six months an employee, representative, officer or director of the Company; or

i.take any action to encourage or induce any employee, representative, officer or director of the Company to cease his or her relationship with the Company for any reason. A "Solicitation" does not include any recruitment of employees for the Company.

The "Restricted Period" means the period including Executive's employment with the Company and one (1) year following the Termination Date or Extended Termination Date, as applicable, and, if the Executive has given a notice pursuant to Paragraph 6(d)(ii), for a period of fifteen (15) months

following the giving of such notice.

a.Non-solicitation of Third Parties. During the Restricted Period, the Executive shall not (either directly or indirectly or as an officer, agent, employee, partner or director of any other company or entity) solicit, service, recruit, induce, influence, or accept on behalf of any competitor of the Company the business of:

i.any customer of the Company at the time of Executive's employment or Termination Date or Extended Termination Date, as applicable; or

Exhibit 10.24

i.any potential customer of the Company which Executive knew to be an identified, prospective purchaser of services or products of the Company.

a.Non-competition. During the Restricted Period, Executive shall not, directly or indirectly, accept employment with, act as a consultant to, or otherwise perform services that are substantially the same or similar to those for which Executive was compensated by the Company (such comparison to be based on job-related functions and responsibilities and not job title) for any business that directly competes with any portion of the Company. This restriction applies to any parent, division, affiliate, newly formed or purchased business(es) and/or successor of a business that competes with the Company. Further, during the Restricted Period, Executive shall not assist any individual or entity other than the Company in acquiring any entity with respect to which a proposal to acquire such entity was presented to the Board during the one (1) year period beginning prior to Executive's Termination Date, Extended Termination Date or notice given by Executive pursuant to Paragraph 6(d)(ii), as applicable.

a.Post-Termination Cooperation. Executive agrees that during and after employment with the Company and without additional compensation (other than reimbursement for reasonable associated expenses) to cooperate with the Company in the following areas:

i.Cooperation with the Company. Executive agrees to:

1.be reasonably available to answer questions for the Company's officers regarding any matter, project, initiative or effort for which Executive was responsible while employed by the Company; and

1.cooperate with the Company during the course of all third-party proceedings arising out of the Company's business about which Executive has knowledge or information.

For purposes of this Agreement, "proceeding" includes internal investigations, administrative investigations or proceedings and lawsuits (including pre-trial discovery and trial testimony) and "cooperation" includes (1) Executive being reasonably available for interviews, meetings, depositions, hearings and/or

trials without the need for a subpoena or assurances by the Company, (2) providing any and all documents in Executive's possession that relate to the proceeding, and

(3) providing assistance in locating any and all relevant notes and/or documents.

i.Cooperation with Third Parties. Unless compelled to do so by lawfully-served subpoena or court order, Executive agrees not to communicate with, or give statements or testimony to, any attorney representing an interest opposed to the Company's interest ("Opposing Attorney"), Opposing Attorney's representative (including a private investigator) or current or former employee relating to any matter (including pending or threatened lawsuits or administrative investigations) about which Executive has knowledge or information as a result of employment

Exhibit 10.24

with the Company. Executive also agrees to notify the Company immediately after being contacted by a third party or receiving a subpoena or court order to appear and testify with respect to any matter that may include a claim opposed to the Company's interest. However, this Paragraph 9(f)(ii) shall not apply to any effort undertaken by Executive to enforce Executive's rights under this Agreement, but only to the extent necessary for that purpose.

i.Cooperation with the Media. Executive agrees not to communicate with, or give statements to, any member of the media (including print, television, electronic or radio media) relating to any matter (including pending or threatened lawsuits or administrative investigations) about which Executive has knowledge or information as a result of employment with the Company. Executive also agrees to notify the Company immediately after being contacted by any member of the media with respect to any matter affected by this Paragraph.

a.Non-Disparagement. Executive and Company shall at all times refrain from taking actions or making statements, written or verbal, that:

i.denigrate, disparage or defame the goodwill or reputation of Executive or the Company, as the case may be, or any of its trustees, officers, security holders, partners, agents or former or current employees and directors, or

i.are intended to, or may be reasonably expected to, adversely affect the morale of the employees of the Company.

Executive further agrees not to make any negative statements to third parties relating to Executive's employment or any aspect of the business of the Company and not to make any statements to third parties about the circumstances of the termination of Executive's employment, or about the Company or its trustees, directors, officers, security holders, partners, agents or former or current employees and directors, except as may be required by a court or governmental body.

a.Enforcement. The Executive acknowledges and agrees that: (i) the purpose

of the foregoing covenants, including, without limitation, the nonsolicitation and noncompetition covenants of Paragraphs 9(d) and (e), is to protect the goodwill, trade secrets and other Confidential Information of the Company; (ii) because of the nature of the business in which the Company is engaged and because of the nature of the Confidential Information to which the Executive has access, the Company would suffer irreparable harm and it would be impractical and excessively difficult to determine the actual damages of the Company in the event the Executive breached any of the covenants of this Paragraph 9; and (iii) remedies at law (such as monetary damages) for any breach of the Executive's obligations under this Paragraph 9 would be inadequate. The Executive therefore agrees and consents that if the Executive commits any breach of a covenant under this Paragraph 9, or threatens to commit any such breach, the Company shall have the right (in addition to, and not in lieu of, any other right or remedy that may be available to it, including but not limited to the right to terminate and forfeit as yet unpaid severance benefits under Paragraphs 6(a) and 6(c) of this Agreement) to temporary and

Exhibit 10.24

permanent injunctive relief from a court of competent jurisdiction, without posting any bond or other security and without the necessity of proof of actual damage, and that the arbitration provisions of Paragraph 14 shall not apply.

a.Notice of Immunity under the Economic Espionage Act of 1996, as amended by the Defend Trade Secrets Act of 2016 (“DTSA”). Notwithstanding any other provision of this Agreement, the Executive will not be held criminally or civilly liable under any federal or state trade secret law for any disclosure of a trade secret that:

i.is made in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and that is disclosed solely for the purpose of reporting or investigating a suspected violation of law; or

i.is made in a complaint or other document filed under seal in a lawsuit or other proceeding.

If the Executive files a lawsuit for retaliation by the Company for reporting a suspected violation of law, the Executive may disclose the Company’s trade secrets to the Executive’s attorney and use the trade secret information in the court proceeding if the Executive:

a.files any document containing trade secrets under seal; and

a.does not disclose trade secrets, except pursuant to court order.

a.Security and Access. The Executive agrees and covenants to comply with all Company security policies and procedures as in force from time to time including without limitation those regarding computer equipment, telephone and voicemail systems, facilities access, key cards, access codes, intranet and internet, social media, computer systems and networks, e-mail systems, software, data security, encryption, firewalls, passwords and any and all other Company facilities, IT resources and communication technologies (“Facilities and Information Technology Resources”), and not to access or use any Facilities and Information Technology Resources except

as authorized by the Company. The Executive also agrees not to access or use any Facilities and Information Technology Resources in any manner after the termination of the Executive’s employment by the Company, whether such termination is voluntary or involuntary, without the Company’s consent.

a.Stock Ownership Requirements. During the Term, the Executive shall be expected to maintain ownership of Company common stock in accordance with guidelines established by the Board as in effect from time to time.

1.Indemnification. The Company shall indemnify Executive to the fullest extent permitted by applicable Delaware law (as may be amended from time to time), including the advance of expenses permitted herein. In the event that the Executive is made a party or threatened to be made a party to any action, suit, or proceeding, whether civil, criminal,

Exhibit 10.24

administrative, or investigative (a “Proceeding”), other than any Proceeding initiated by the Executive or the Company related to any contest or dispute between the Executive and the Company or any of its affiliates with respect to this Agreement or the Executive’s employment hereunder, by reason of the fact that the Executive is or was a director or officer of the Company, or any affiliate of the Company, or is or was serving at the request of the Company as a director, officer, member, employee, or agent of another corporation or a partnership, joint venture, trust, or other enterprise, the Executive shall be indemnified and held harmless by the Company to the maximum extent permitted under applicable law and the Company’s bylaws from and against any liabilities, costs, claims, and expenses, including all costs and expenses incurred in defense of any Proceeding (including attorneys’ fees). Costs and expenses incurred by the Executive in defense of such Proceeding (including attorneys’ fees) shall be paid by the Company in advance of the final disposition of such litigation upon receipt by the Company of: (i) written request for payment; (ii) appropriate documentation evidencing the incurrence, amount, and nature of the costs and expenses for which payment is being sought; and

a.an undertaking adequate under applicable law made by or on behalf of the Executive to repay the amounts so paid if it shall ultimately be determined that the Executive is not entitled to be indemnified by the Company under this Agreement. Notwithstanding the foregoing, nothing in this Paragraph shall impose on the Company any obligation to indemnify the Executive from any tax, excise tax or similar penalty, including but not limited to any excise tax under Code Section 409A or 4999, imposed on the Executive with respect to any compensation, deferred compensation, severance or other benefits provided to Executive by Company under this Agreement or otherwise, without regard to whether the Company bears any culpability with respect to the imposition of such tax or not

1.Performance. The failure of either party to this Agreement to insist upon strict performance of any provision of this Agreement shall not constitute a waiver of its rights subsequently to insist upon strict performance of such provision or any other provision of this Agreement.

2.Non-Assignability. Neither party shall have the right to assign this Agreement or any rights or obligations hereunder without the consent of the other party.

1.Invalidity. If any provisions of this Agreement shall be found to be invalid

by any court of competent jurisdiction, such finding shall not affect the remaining provisions of this Agreement, all of which shall remain in full force and effect.

1.Arbitration and Legal Fees. In the event of any dispute regarding a refusal or failure by the Company to make payments or provide benefits hereunder for any reason, Executive shall have the right, in addition to all other rights and remedies provided by law, to arbitration of such dispute under the rules of the American Arbitration Association, which right shall be invoked by serving upon the Company a notice to arbitrate, stating the place of arbitration, within ninety

(90) days of receipt of notice in any form (including, without limitation, failure by the Company to respond to a notice from Executive within thirty (30) days) that the Company is withholding or proposes to withhold any payments or the provision of any benefits the Executive, in good faith, believes are called for hereunder. In the event of any such dispute,

Exhibit 10.24

whether or not Executive exercises his right to arbitration, if it shall ultimately be determined that the Company's refusal or failure to make payments or provide benefits hereunder was wrongful or otherwise inconsistent with the terms of this Agreement, the Company shall indemnify and hold harmless Executive from and against any and all expenses incurred in connection with such determination, including reasonable legal and other fees and expenses. Accordingly, the Company agrees to pay within 30 days following the Company’s receipt of an invoice from the Executive all legal fees and expenses which the Executive may reasonably incur as a result of any contest by either party of the validity or enforceability of, or liability under, any provision of this Agreement, plus, in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code, if the Executive prevails on any material claim made by him and disputed by the Company (or its successors and assigns) under the terms of this Agreement. Such payments shall be made in accordance with the provisions of Paragraph 20 in order to comply with Section 409A of the Code.

1.Survival of Certain Provisions. Notwithstanding any other provision of this Agreement, the termination of this Agreement for any reason shall not result in the termination of the rights and obligations of the parties under the provisions of Sections 5(d), 6, 7, 9, 10, 14 and 16 hereof, which shall survive any such termination. The right of recovery provisions of Section 5(d) shall cease to apply during the Extended Term and shall be automatically terminated upon a Change in Control of the Company (as defined in Paragraph 2(d)) except with respect to any right of recovery that has been asserted prior to such Change in Control.

1.Successors. This Agreement shall be binding upon and inure to the benefit of the Executive (and his personal representative), the Company and any successor organization or organizations that shall succeed to substantially all of the business and property of the Company and assume the Company’s obligations hereunder, whether by means of merger, consolidation, acquisition of substantially all of the assets of the Company, or operation of law. The Company shall require any successor organization or organizations to agree to assume the obligations of this Agreement.

2.Set-off. The Company shall have no right of set-off or counterclaim in respect of any claim, debt or obligation against any payments or benefits provided for in this Agreement except as otherwise provided herein.

1.Amendments. No Amendment to this Agreement shall be effective unless in writing and signed by both the Company and Executive. Notwithstanding the foregoing, if any compensation or benefits provided by this Agreement may result in the application of Code Section 409A, the Company shall, in consultation with the Executive, modify the Agreement in the least restrictive manner necessary in order to exclude such compensation from the definition of "deferred compensation" within the meaning of Code Section 409A or in order to comply with the provisions of Code Section 409A, other applicable provisions of the Code and/or any rules, regulations or other regulatory guidance issued under such statutory provisions, and without any diminution in the value of the payments to the Executive.

Exhibit 10.24

1.Governing Law. This Agreement shall be interpreted and enforced in accordance with the laws of the State of Delaware. The parties hereto irrevocably agree to submit to the jurisdiction and venue of the courts of the State of Delaware in any action or proceeding brought with respect to or in connection with this Agreement except for an action described in Paragraph 14.

1.Code Section 409A. Notwithstanding any provision of Paragraph 10 or 14 of this Agreement to the contrary, any legal fees and expenses to be paid by the Company pursuant to Paragraph 10 or 14 shall be subject to the following requirements in order to comply with Code Section 409A. Such legal fees and expenses shall be paid by the Company only to the extent incurred during the Term of the Agreement or for a period of ten (10) years after the Executive's Separation from Service. The Company shall pay such legal fees and expenses no later than the end of the calendar year next following the calendar year in which such fees and expenses were incurred, and the Company shall not be obligated to pay any such fees and expenses for which the Executive fails to submit an invoice at least ten (10) business days before the end of the calendar year next following the calendar year in which such fees and expenses were incurred. The amount of such legal fees and expenses that the Company is obligated to pay in any given calendar year shall not affect the legal fees and expenses that the Company is obligated to pay in any other calendar year, and the Executive's right to have the Company pay such legal fees and expenses may not be liquidated or exchanged for any other benefit.

1.Notices. Unless otherwise stated herein, all notices hereunder shall be in writing and shall be deemed to be given when personally delivered or mailed by United States registered or certified mail, postage prepaid, to, if to the Company, 909 Silver Lake Boulevard, Dover, Delaware 19904, and, if to Executive, the last address therefore shown on the records of the Company. Either the Company or Executive may, by notice to the other, designate an address other than the foregoing for the receipt of subsequent notices.

1.Withholding. The Company may withhold from any amounts payable to Executive hereunder all federal, state, city or other taxes that the Company may reasonably deter- mine are required to be withheld pursuant to any applicable law or regulation.

1.Nature of Payments Upon Termination. All payments to Executive pursuant to Paragraph 6 of this Agreement shall be considered as liquidated damages or, in the case of certain payments pursuant to Paragraph 6(c), as severance payments in consideration of Executive's past services to the Company, and no such payment shall be regarded as a penalty to the Company.

1.Prior Agreement. The parties acknowledge and agree that the terms of this Agreement constitute the entire agreement of the parties with respect to the subject matter and supersede all prior agreements and amendments with respect thereto, including, without limitation, the Prior Agreement.

1.Acknowledgment. The parties hereto each acknowledge that each has read this Agreement and understands the same and that each enters into this Agreement freely and voluntarily.

Exhibit 10.24

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL] By:

Jeffry M. Householder

Title: Chief Executive Officer

ATTEST:

Louis J. Anatrella

EXECUTIVE:

Chief Human Resources Officer

Jeffrey S. Sylvester

S I G N AT U R E CE RT IFIC AT E

Reference Number

84BBE2F0-3453-4FFB-850B-172072AEE28F

Transaction Type

Signature Request

Sent At

02/26/2020 08:25 EST

Executed At

03/02/2020 08:39 EST

Identity Method

email

Distribution Method

email

Signed Checksum

Document Name

5 - Executive Employment Agreement - Sylvester 12-4-19

Filename

5_-_executive_employment_agreement_-_sylvester_12-4-19.pdf

Pages

20 pages

Content Type

application/pdf

File Size

100 KB

Original Checksum

Exhibit 10.24

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Disabled

Document Passcode

Disabled

SIG N E R S

Name

Lou Anatrella

Email

lanatrella@chpk.com

Components

1

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signed

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168.149.161.43

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281

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Signed At

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Name

Jeff Householder

Email

jhouseholder@chpk.com

Components

1

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signed

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174.227.0.204

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Identity Authenticated At

02/26/2020 16:44 EST

Signed At

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Exhibit 10.24

Name

Jeff Sylvester

Email

jssylvester@chpk.com

Components

20

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signed

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IP Address

162.212.91.7

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Signed At

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A UD ITS

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Exhibit 10.24

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02/26/202008:25ESTDebby Frye (dfrye@chpk.com) created document '5_-_executive_employment_agreement_-_sylvester_12-4-19.pdf' on Internet Explorer via Windows from168.149.161.43.EXECUTIVE EMPLOYMENT AGREEMENT

This Executive Employment Agreement (the "Agreement") dated this 4th day of December, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the "Company"), and Jeffrey S. Sylvester (the "Executive").

Recitals

WHEREAS, the Company is currently obtaining the benefit of Executive's services as a full-time executive employee in the capacity of Senior Vice President, Transmission and Distribution;

WHEREAS, the Company's Board of Directors (the "Board") has authorized the Company to provide for the Executive's continued employment pursuant to the terms of this Agreement as the Company’s Senior Vice President, Transmission and Distribution; and

Exhibit 10.24

WHEREAS, Executive is willing, in consideration of the covenants and consideration hereinafter provided, to continue to be employed by the Company in the capacity of Senior Vice President, Transmission and Distribution and to render services incident to such position during the term of this Agreement.

Agreement

In consideration of the mutual promises and covenants contained herein, the Company and Executive hereby agree as follows:

1.Employment. The Company agrees to employ Executive, and Executive agrees to accept employment, as an officer of the Company in the capacity of Senior Vice President, Transmission and Distribution, with such authority, duties and responsibilities as are customarily assigned to such position, including such reasonable duties and responsibilities as may be requested of the Executive by the Board of Directors and which are consistent with the By-laws of the Company as in effect from time to time including, but not limited to, responsibility for direction of the Transmission, Distribution, and Customer Care functions of the Company.

1.Term.

a.Term of Agreement. The term of this Agreement ("Term") shall be the Current Term (as defined in Paragraph 2(b)), and, if applicable, the Extended Term (as defined in Paragraph 2(c)).

a.Current Term. Subject to Paragraph 2(c), the Current Term of this Agreement shall extend for two (2) years commencing on December 4, 2019. If the Current Term of this Agreement expires without there having been a Change in Control (as hereinafter defined), this Agreement may be renewed for successive one (1) year terms, as of the day following such

expiration, by the Company through action of the Compensation Committee of the Board of Directors, unless, during the period beginning ninety (90) days prior and ending thirty (30) days prior to such day, either the Company or Executive shall have given notice to the other that this Agreement will not be renewed. If the Company determines to extend or renew this Agreement as provided under this Paragraph, the new Agreement shall be identical to this Agreement (except insofar as the Company and Executive may otherwise agree in writing) except that the date of the new Agreement shall be as of the day following the expiration of the Current Term of this Agreement or any renewal term.

a.Extended Term. Upon the occurrence of a Change in Control (as defined in Paragraph 2(d)), the Current Term shall end and the Term of this Agreement shall thereupon automatically be extended, commencing on the date of such Change in Control, for a period of two

(2) years ( the "Extended Term").

Exhibit 10.24

a.Change In Control. For the purposes of this Agreement, "Change in Control" shall mean a change in the control of the Company during the Term of this Agreement, which shall be deemed to have occurred upon the first of the following events:

i.any one person, or group of owners of another corporation who acting together through a merger, consolidation, purchase, acquisition of stock or the like (a "Group"), acquires ownership of stock of the Company (or a majority-controlled subsidiary of the Company) that, together with the stock held by such person or Group, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the stock of the Company. However, if such person or Group is considered to own more than fifty percent (50%) of the total fair market value or total voting power of the stock of the corporation before this transfer of the Company's stock, the acquisition of additional stock by the same person or Group shall not be considered to cause a Change in Control of the Company; or

i.any one person or Group acquires (or has acquired during the twelve

(12) month period ending on the date of the most recent acquisition by such person or persons) ownership of stock of the Company (or a majority-controlled subsidiary of the Company) possessing thirty-five percent (35%) or more of the total voting power of the stock of the Company where such person or Group is not merely acquiring additional control of the Company; or

i.a majority of members of the Company's Board (other than the Board of a majority-controlled subsidiary of the Company) is replaced during any twelve

(12) month period by directors whose appointment or election is not endorsed by a majority of the members of the Company's Board prior to the date of the appointment or election (the “Incumbent Board”), but excluding, for purposes of determining whether a majority of the Incumbent Board has endorsed any candidate for election to the Board, any individual whose initial assumption of office occurs as a result of

an actual or threatened election contest with respect to the election or removal of directors or other actual or threatened solicitation of proxies or consents by or on behalf of a person or Group other than the Company’s Board; or

i.any one person or Group acquires (or has acquired during the twelve

a.month period ending on the date of the most recent acquisition by such person or Group) assets from the Company (or a majority-controlled subsidiary of the Company) that have a total gross fair market value equal to or more than forty percent (40%) of the total fair market value of all assets of the Company immediately prior to such acquisition or acquisitions. For this purpose, gross fair market value means the value of the assets of the Company, or the value of the assets being disposed of, determined without regard to any liabilities associated with such assets. A transfer of assets by the Company will not result in a Change in Control if the assets are transferred to:

i.a stockholder of the Company (immediately before the asset transfer) in exchange for or with respect to its stock;

Exhibit 10.24

i.an entity, fifty percent (50%) or more of the total value or voting power of which is owned, directly or indirectly, by the Company immediately after the transfer of assets;

i.a person or Group that owns, directly or indirectly, fifty percent (50%) or more of the total value or voting power of all the outstanding stock of the Company; or

i.an entity, at least fifty percent (50%) of the total value or voting power of which is owned directly or indirectly, by a person described in subparagraph (d)(i), above.

However, no Change in Control shall be deemed to have occurred with respect to the Executive by reason of (1) any event involving a transaction in which the Executive or a group of persons or entities with which the Executive acts in concert, acquires, directly or indirectly, more than thirty percent (30%) of the Common Stock of the business or assets of the Company; or (2) any event involving or arising out of a proceeding under Title 11 of the United States Code (or the provisions of any future United States bankruptcy law), or an assignment for the benefit of creditors or an insolvency proceeding under state or local law.

1.Time. Executive agrees to devote all reasonable full time and best efforts for the benefit of the Company and any subsidiary of the Company, and not to serve any other business enterprise or organization in any capacity during the Term of this Agreement without the prior written consent of the Company, which consent shall not be unreasonably withheld.

1.Office.

a.Current Term. During the Current Term, the Executive shall serve in the capacity as defined in Paragraph 1 and the parties agree that the Company shall elect the Executive to these offices, on an annual basis if necessary, during the Current Term of this Agreement.

a.Extended Term. During the Extended Term of this Agreement the Executive shall hold and perform an office with the responsibility, importance and scope within the Company at least equal to that of the office described and contemplated in Paragraph 1. Further, Executive's office shall be located in Dover, Delaware, and Executive shall not be required, without his written consent, to change his office location or to be absent therefrom on business for more than sixty (60) working days in any year.

1.Compensation and Benefits.

a.Base Compensation; Current Term. The Company shall compensate Executive for his services hereunder during the Current Term at a rate of $300,000 per annum, or such amount as the Board may from time to time determine ("Base Compensation"), payable in installments on the Company’s regular payroll dates for salaried executives. The Base Compensation rate shall be reviewed annually and may be increased or decreased, from time to time, provided, however, that Base Compensation shall only be decreased by the Board on a good faith basis and with reasonable justification for the same, and provided further, that in the event of a Change in Control, Base Compensation shall not at any time thereafter be decreased.

Exhibit 10.24

a.Base Compensation; Extended Term. During the Extended Term, the Company shall compensate Executive for his services hereunder at a rate per annum, payable in installments on the Company’s regular payroll dates for salaried executives, equal to his Base Compensation at the time the Extended Term commences, which may be increased, but not decreased, by such additional amounts as the Board may determine from time to time based, in part, on an annual review of the Executive's compensation and performance.

a.Incentive Plans. During the Term of this Agreement, Executive shall be entitled to participate in all bonus, incentive compensation and performance based compensation plans, and other similar policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive's participation shall be in accordance with the terms and provisions of such plans and programs. Participation shall include, but not be limited to:

i.Chesapeake Utilities Corporation Long-Term 2013 Stock and Incentive Compensation Plan. Executive shall be eligible for a performance incentive compensation award as determined on an annual basis by the Compensation Committee of the Board of Directors in its discretion and in

4

JSS

Initials

accordance with and subject to the terms of the Company’s 2013 Stock and Incentive Compensation Plan (the “Equity Plan”) during the Term of this Agreement. The Equity Plan’s Target Bonus as a percent of base salary shall be reviewed annually and may be increased or decreased, from time to time, provided, however, that Target shall only be decreased by the Board on a good faith basis and with reasonable justification for the same, and provided further, that in the event of a Change in Control, Target shall not at any time thereafter be decreased.

i.Chesapeake Utilities Corporation Cash Bonus Incentive Plan. Executive shall be eligible for an annual cash bonus award with a target award amount equal to thirty five (35%) of Executive’s Base Compensation, as determined on an annual basis by the Compensation Committee of the Board in its discretion and in accordance with and subject to the terms of the Company’s Cash Bonus Incentive Plan during the Term of this Agreement.

a.Recovery of Compensation. The Executive acknowledges and agrees that all or any portion of an incentive award under the above described bonus and incentive compensation plans or any future arrangement established by the Company to provide incentive or bonus compensation, whether payable in cash, Company common stock or other property, (“Award”) is subject to an obligation of repayment by the Executive to the Company if the amount of the Award was calculated based upon the achievement of

Exhibit 10.24

certain financial results (as reflected in the financial statement of the Company or otherwise) or other performance metrics that, in either case, were subsequently found to be materially inaccurate. The amount that shall be repaid by the Executive to the Company shall be based on the excess amount paid or awarded to the Executive under the Award as compared to the amount that would have been paid or awarded had the material inaccuracy not occurred. If the Compensation Committee of the Board of Directors determines that the Executive engaged in misconduct, malfeasance or gross negligence in the performance of his or her duties that either caused or significantly contributed to the material inaccuracy in financial statements or other performance metrics, there shall be no time limit on this right of recovery, which shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this Agreement. In all other circumstances, this right of recovery shall apply to all future Awards as well as to any and all pre-existing Awards that have not yet been determined and paid as of the date of this agreement for a period not exceeding one year after the date of payment of each such Award. In addition, the Executive hereby agrees that, if he or she does not promptly repay the amount recoverable hereunder within thirty (30) days of a demand therefore, such amount may be withheld from compensation of any type not yet due and payable to the Executive, including, but not limited to, the cancellation of future Awards, as determined by the Compensation Committee in its sole discretion. In addition, the Compensation Committee is granted the discretionary authority to interpret and enforce this provision as it determines to be in the best interest of the Company and equitable to the parties. Notwithstanding anything herein, this provision shall not be the Company’s exclusive remedy with respect to such matters. In addition, the parties agree that the Company may unilaterally amend this provision at any time to comply with applicable law or securities exchange listing rules, as the same may be in

effect from time to time, during the Current Term or the Extended Term of this Agreement.

a.Retirement Plans. During the Term of this Agreement, Executive shall be entitled to participate in all profit-sharing, savings and retirement benefit plans, plans that are supplemental to any tax-qualified savings and retirement plans, and other similar policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive's participation shall be in accordance with the terms and provisions of such plans and programs.

a.Welfare Benefits. During the Term of this Agreement, Executive, and his family, as applicable, shall be entitled to participate in all insurance, medical, health and welfare, and similar plans and arrangements, as well as all vacation and other employee fringe benefit plans, perquisite plans, and other policies, practices, programs and arrangements of the Company, now in effect or as hereafter amended or established, on a basis that is commensurate with his position and no less favorable than those generally applicable or made available to other executives of the Company. The Executive’s participation shall be in accordance with the terms and provisions of such plans.

Exhibit 10.24

a.Other Benefits. During the Term of this Agreement, the Company shall furnish Executive with a suitable office, necessary administrative support and customary furniture and furnishings for such office. The Company further agrees that Executive shall have the use of a Company-owned or Company-leased and Company-maintained automobile, new every three (3) years, of a kind and model appropriate to his position with the Company.

a.Expenses. During the Term of this Agreement, the Company shall pay all necessary and reasonable business expenses incurred by Executive on behalf of the Company in the course of his employment hereunder, including, without limitation, expenses incurred in the conduct of the Company's business while away from his domicile and properly substantiated expenses for travel, meals, lodging, entertainment and related expenses that are for the benefit of the Company. All expense reimbursements shall comply with applicable rules or guidelines of the Company in effect at the time the expense is incurred.

If any reimbursements under this or any other provision of this Agreement are taxable to the Executive, such reimbursements shall be paid on or before the end of the calendar year following the calendar year in which the reimbursable expense was incurred, and the Company shall not be obligated to pay any such reimbursement amount for which Executive fails to submit an invoice or other documented reimbursement request at least 10 business days before the end of the calendar year next following the calendar year in which the expense was incurred. Such expenses shall be reimbursable only to the extent they were incurred during the term of the Agreement. In addition, the amount of such reimbursements that the Company is obligated to pay in any given calendar year shall not affect the amount the Company is obligated to pay in any other calendar year. In addition, Executive may not liquidate or exchange the right to reimbursement of such

expenses for any other benefits.

a.Nothing in this Agreement shall preclude the Company from amending or terminating any employee benefit plan or practice, but, it being the intent of the parties that the Executive shall continue to be entitled during the Extended Term to compensation, benefits, reimbursements and perquisites as set forth in Paragraphs 5(a) through 5(c) and 5(e) through 5(h) at least equal to those attached to his position on the date of this Agreement, and nothing in this Agreement shall operate as, or be construed to authorize, a reduction during the Extended Term without Executive's written consent in the level of such compensation, benefits, reimbursements or perquisites as in effect on the date of a Change in Control. If and to the extent that such compensation, benefits, reimbursements or perquisites are not payable or provided to Executive under any such plan or practice by reason of an amendment thereto or termination thereof during the Extended Term, the Company shall nevertheless pay or provide such compensation, benefits, reimbursements or perquisites to Executive, either directly or through alternative arrangements.

1.Termination.

a.Payment Upon Termination During Current Term. In the event that the Company terminates this Agreement during the Current Term, or elects not to renew this

Exhibit 10.24

Agreement at the end of the Current Term, for any reason other than Cause, as defined below, or the Executive’s death, the Company shall continue to pay to Executive (or in the event of his death following such termination, his legal representative), as a severance benefit his Base Compensation under Paragraph 5(a), at the rate in effect immediately prior to the date of such termination ("Termination Date"), on the regular payroll dates occurring during the period of one (1) year following the Termination Date. In addition, and notwithstanding the foregoing provisions of this Paragraph 6(a), to the extent required in order to comply with Section 409A of the Internal Revenue Code of 1986, as amended (the "Code"), Termination Date shall be determined based on the date the Executive has a “separation from service” within the meaning of Code Section 409A and regulations thereunder, using the default rule under such regulations (“Separation from Service”), and cash amounts that would otherwise be payable under this Paragraph 6(a) during the six-month period immediately following the Termination Date shall instead be paid, with interest on any delayed payment at the applicable federal rate under Code Section 7872(f)(2)(A), on the first business day after the date that is six (6) months following the Executive’s Separation from Service if necessary to comply with Code Section 409A. Each payment to be made under this Paragraph 6(a) shall be considered a separate payment. Payment of the severance benefit under this Paragraph is subject to the Executive’s compliance with the covenants of Paragraph 9 and the execution and delivery (and non- revocation) of a release of claims (the “Release”) against the Company and its officers, directors, employees and affiliates, which Release must be delivered to the Company not later than 45 days after the Termination Date. If the Executive fails to comply with any of the covenants of Paragraph 9 or fails to deliver the Release within 45 days after the Termination Date, or if the Executive revokes such Release within 7 days after its delivery to the Company, payment of the severance benefits shall cease and any unpaid amounts shall be forfeited. Payment commencement shall not be delayed, however, pending delivery of the Release.

a.Termination for Cause. This Agreement and Executive's employment hereunder may be terminated by the Company at any time for Cause. In the event of termination for Cause, the Executive shall not be entitled to any severance benefits under this Agreement. Termination of the Executive's employment shall be deemed to have been "for Cause" only if it shall have been the result of:

i.Executive’s conviction of a felony under the laws of the United States or a state in which Executive works or resides, or a guilty or no contest plea by the Executive with respect thereto;

i.a willful or deliberate act or acts of dishonesty by Executive resulting or intended to result directly or indirectly in material gain to or personal enrichment of Executive at the Company's expense;

i.a deliberate and intentional refusal by Executive (except by reason of incapacity due to illness or accident) to comply with the provisions of Paragraph 1, provided that such breach shall have resulted in demonstrably material injury to the Company and the Executive shall have failed to remedy such breach within thirty

Exhibit 10.24

(30) days after notice from the Secretary of the Company demanding that the Executive remedy such breach; or

i.conduct by Executive that is materially injurious to the Company if such conduct was undertaken without good faith and the reasonable belief that such conduct was in the best interest of the Company.

a.Payment Upon Termination During Extended Term. In the event of a Termination Without Cause, as defined below, during the Extended Term, the Company shall pay to Executive (or, in the event of his death following the termination, his legal representative) in cash, on the first business day that falls on or after the sixtieth (60th) day after the date of such termination (the "Extended Termination Date") the sum of all accrued but unpaid salary, bonus, vacation pay, expense reimbursements and any other amounts due, plus the following:

i.an amount equal to the product of multiplying the monthly rate of Base Compensation to which Executive was entitled under Paragraph 5(a) on the day immediately prior to the Extended Termination Date by Twenty-four (24) months ("Covered Period");

i.an amount equal to the aggregate of the Company's contributions to the Company's savings plan (including, but not limited to, the Chesapeake Utilities Corporation Retirement Savings Plan, and any related excess benefit plans) in respect of Executive that were not vested on the day immediately prior to the Extended

Termination Date but that would have been vested at the end of the Covered Period if Executive had remained employed by the Company for the duration of that period; and

i.an amount equal to the product of multiplying the average of the annual aggregate benefits awarded to the Executive under all annual bonus program(s) of the Company in which the Executive was a participant in each of the three (3) calendar years immediately preceding the calendar year in which the Extended Termination Date occurs by two (2) years.

Payment of the severance benefit under this Paragraph is subject to the Executive’s compliance with the covenants of Paragraph 9 and the execution and delivery (and non-revocation) of a release of claims (the “Release”) against the Company and its officers, directors, employees and affiliates, which Release must be delivered to the Company not later than 45 days after the Termination Date. If the Executive fails to comply with any of the covenants of Paragraph 9 or fails to deliver the Release within 45 days after the Termination Date, or if the Executive revokes such Release within

7 days after its delivery to the Company, payment of the severance benefits shall cease (if commenced) or shall not be made, and any unpaid amounts shall be forfeited.

In addition, the Company shall continue to provide medical, prescription drug, vision, dental and other Company welfare benefits to the Executive and his eligible dependents during

Exhibit 10.24

the Covered Period as if the Executive remained an active employee of the Company (but, with respect to any such benefits provided through insurance, only if and to the extent it is permissible to extend such benefits to a former employee of the Company under the terms of the applicable plan and insurance contracts). Executive further acknowledges that the cost of the coverage afforded to Executive and his eligible dependents under self-funded medical expense reimbursement plans of the Company during the Covered Period shall be treated as additional taxable income to the Executive to the extent necessary to avoid a violation of the nondiscrimination provisions of Section 105(h) of the Code. Should the continuation of any medical or similar coverages be through fully insured plans, and should such continuation violate the nondiscrimination requirements for such plans under the Patient Protection and Affordable Care Act of 2010, then the Executive shall receive additional cash severance benefits rather than continued coverage under such plans of the Company in an amount based on the premium cost of such coverage that the Company would otherwise pay under this paragraph. In addition, the applicable period of health benefit continuation under Code Section 4980B shall begin at the end of the Covered Period.

To the extent required in order to comply with Code Section 409A, cash amounts that would otherwise be payable under this Paragraph 6(c) during the six-month period immediately following the Extended Termination Date (and which are not eligible for the exception applicable to payments due to involuntary separation under Treas. Reg. Section 1.409A-1(b)(9)(iii)) shall instead be paid, with interest on any delayed payment at the applicable federal rate under Code Section 7872(f)(2)(A), on the first business day after the date that is six (6) months following the Executive's Separation from Service. Further, any taxable welfare benefits provided to Executive pursuant to this Paragraph 6(c) that are not "disability pay" or "death benefits" within the meaning of Treas.

Reg. Section 1.409A-1(a)(5) (collectively, the "Applicable Benefits") shall be subject to the following requirements in order to comply with Code Section 409A. The amount of any Applicable Benefits provided during one taxable year shall not affect the amount of the Applicable Benefits provided in any other taxable year, except that with respect to any Applicable Benefits that consist of the reimbursement of expenses referred to in Code Section 105(b), a limitation may be imposed on the amount of such reimbursements over some or all of the Covered Period, as described in Treas. Reg. Section 1.409A-3(i)(1)iv(B). To the extent that any Applicable Benefits consist of the reimbursement of eligible expenses, such reimbursement must be made on or before the last day of the calendar year following the calendar year in which the expense was incurred. No Applicable Benefits may be liquidated or exchanged for another benefit. During the period of six (6) months immediately following Executive's Separation from Service, Executive shall be obligated to pay the Company the full cost for any Applicable Benefits that do not constitute health benefits of the type required to be provided under the health continuation coverage requirements of Code Section 4980B, and the Company shall reimburse Executive for any such payments on the first business day that is more than six (6) months after Executive's Separation from Service, together with interest on such amount from the date of Separation from Service through the date of payment at the applicable federal rate under Code Section 7872(f)(2)(A).

a.Termination Without Cause. For purposes of Paragraph 6(c) above, "Termination Without Cause" shall mean a Separation from Service of the Executive that is either a:

Exhibit 10.24

i.Termination by the Company of Executive's employment without Cause (as "Cause" is defined in Paragraph 6(b) above); or

i.Termination by Executive of his employment following the occurrence of any of the following events:

1.failure to elect or re-elect Executive to, or removal of Executive from, the office or offices set forth in Paragraph 1, or failure to nominate Executive for election to the Board if Executive shall have been a member of the Board immediately prior to a Change in Control of the Company;

1.a significant change in the nature or scope of his authorities, powers, functions, duties or responsibilities attached to the positions contemplated in Paragraph 1, or a reduction in his compensation or in the benefits available to the Executive and his family, as provided in Paragraph 5, which change or reduction is not remedied within thirty (30) days after notice to the Company by the Executive;

1.any other breach by the Company of any material provision of this Agreement (including, without limitation, relocation of the Executive in material violation of Paragraph 4(b)), which breach is not remedied within

thirty (30) days after notice to the Company by Executive; or

1.the consolidation or merger of the Company or transfer of all or a significant portion of its assets unless a successor or successors (by merger, consolidation or otherwise) to which all or a significant portion of its assets has been transferred shall have assumed all duties and obligations of the Company under this Agreement.

In order to effect a Termination Without Cause in any event set forth in this Paragraph 6(d)(ii), Executive must elect to terminate his employment under this Agreement upon not less than forty (40) days and not more than ninety (90) days' written notice to the Board, attention of the Chief Executive Officer, given, except in the case of a continuing breach, within three (3) calendar months after: (1) failure to be so elected, reelected, or nominated, or such removal, (2) expiration of the 30-day cure period with respect to such event, or (3) the closing date of such consolidation, merger or transfer of assets.

An election by Executive to terminate his employment under the provisions of this Paragraph shall not be deemed a voluntary termination of employment by Executive for the purpose of this Agreement or any plan or practice of the Company. Further, the death of the Executive during the Extended Term but prior to a Termination Without Cause, as defined, shall not constitute Cause or be deemed to be a Termination Without Cause.

a.Resignation of All Other Positions. Upon termination of the Executive’s employment hereunder for any reason, the Executive shall be deemed to have resigned from all

Exhibit 10.24

positions that the Executive holds as an officer or member of the Board of Directors of the Company or any affiliates unless otherwise determined by the Board.

1.Maximum Payment Upon Termination.

a.Determination. 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 Executive 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 Paragraph 6(c) of this Agreement or otherwise, then the Executive’s benefits under this Agreement shall be reduced by the amount necessary so that the Executive’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 determination concerning the application of the reduction shall be made by a nationally-recognized firm of independent accountants (together with legal counsel of its choosing) selected by the Company after consultation with the Executive (which may be the Company’s independent auditors), whose determination shall be conclusive and binding on all parties. Any fees and

expenses of such independent accountants and counsel (including counsel for the Executive) shall be borne by the Company.

a.Notices. If it is determined that the benefits under this Agreement must be reduced under this Paragraph, within 10 days of the date of such determination, the Company will apprise the Executive of the amount of the reduction ("Notice of Reduction"). Within 10 days of receiving that information, the Executive may specify how (and against which benefit or payment source) the reduction is to be applied ("Notice of Application"). The Company will be required to implement these directions within 10 days of receiving the Notice of Application. If the Company has not received a Notice of Application from the Executive within 10 days of the date of the Notice of Reduction, the Company will apply this Paragraph proportionately based on the amounts otherwise payable under Paragraph 6(c). If the Company receives a Notice of Application that does not fully implement the requirements of this Paragraph, the Company will apply this Paragraph proportionately on the basis of the reductions specified in the Notice of Application first, then to any remaining reduction based on the amounts otherwise payable under Paragraph 6(c).

Notwithstanding the foregoing, if the exercise of discretion reserved to the Executive in determining the Notice of Application would violate Code Section 409A, then such discretion shall be eliminated and the amounts payable under Paragraph 6(c) shall be reduced proportionately.

1.Mitigation. Executive shall not be required to mitigate the amount of any payment provided for in this Agreement either by seeking other employment or otherwise. The amount of any payment provided for herein shall not be reduced by any remuneration that Executive may earn from employment with another employer or otherwise following his Termination Date or Extended Termination Date, as applicable.

Exhibit 10.24

1.Covenants.

a.Introduction. The parties acknowledge that the provisions and covenants contained in this Paragraph 9 are ancillary and material to this Agreement and that the limitations contained herein are reasonable in geographic and temporal scope and do not impose a greater restriction or restraint than is necessary to protect the goodwill and other legitimate business interests of the Company. The parties also acknowledge and agree that the provisions of this Paragraph 9 do not adversely affect Executive’s ability to earn a living in any capacity that does not violate the covenants contained herein. The parties further acknowledge and agree that the provisions of Paragraph 19 below are accurate and necessary because (i) Delaware is the headquarters state of the Company, which has operations in multiple states and a compelling interest in having its employees treated uniformly, (ii) the use of Delaware law provides certainty to the parties in any covenant litigation in the United States, and (iii) enforcement of the provisions of this Paragraph 9 would not violate any fundamental public policy of Delaware or any other jurisdiction.

a.Confidential Information. Executive shall hold in a fiduciary capacity for the benefit of the Company, all secret or confidential information, knowledge or data relating to the

Company and its businesses (including, but not limited to, any proprietary and not publicly available information concerning any processes, methods, trade secrets, costs, names of users or purchasers of the Company’s products or services, business methods, financial affairs, operating procedures or programs or methods of promotion and sale) that Executive has obtained or obtains during Executive’s employment by the Company and that is not public knowledge (other than as a result of Executive’s violation of this Paragraph 9(b)) ("Confidential Information"). For purposes of this Paragraph 9(b), information shall not be deemed to be publicly available merely because it is embraced by general disclosures or because individual features or combinations thereof are publicly available. Executive shall not communicate, divulge or disseminate Confidential Information at any time during or after Executive’s employment with the Company except:

i.to employees or agents of the Company that need the Confidential Information to perform their duties on behalf of the Company;

i.in the performance of Executive’s duties to the Company;

i.as a necessary (and only to the extent necessary) part of any undertaking by Executive to enforce Executive’s rights under this Agreement; or

i.as otherwise required by law or legal process.

All confidential records, files, memoranda, reports, customer lists, drawings, plans, documents and the like that Executive uses, prepares or comes into contact with during the course of Executive’s employment shall remain the sole property of the Company and shall be turned over to the Company upon termination of Executive’s employment.

Exhibit 10.24

a.Non-solicitation of Company Employees. Executive shall not, at any time during the Restricted Period (as defined below), without the prior written consent of the Company, engage in the following conduct (a "Solicitation"):

i.directly or indirectly, contact, solicit, recruit or employ (whether as an employee, officer, director, agent, consultant or independent contractor) any person who was or is at any time during the previous six months an employee, representative, officer or director of the Company; or

i.take any action to encourage or induce any employee, representative, officer or director of the Company to cease his or her relationship with the Company for any reason. A "Solicitation" does not include any recruitment of employees for the Company.

The "Restricted Period" means the period including Executive's employment with the Company and one (1) year following the Termination Date or Extended Termination Date, as applicable, and, if the Executive has given a notice pursuant to Paragraph 6(d)(ii), for a period of fifteen (15) months

following the giving of such notice.

a.Non-solicitation of Third Parties. During the Restricted Period, the Executive shall not (either directly or indirectly or as an officer, agent, employee, partner or director of any other company or entity) solicit, service, recruit, induce, influence, or accept on behalf of any competitor of the Company the business of:

i.any customer of the Company at the time of Executive's employment or Termination Date or Extended Termination Date, as applicable; or

i.any potential customer of the Company which Executive knew to be an identified, prospective purchaser of services or products of the Company.

a.Non-competition. During the Restricted Period, Executive shall not, directly or indirectly, accept employment with, act as a consultant to, or otherwise perform services that are substantially the same or similar to those for which Executive was compensated by the Company (such comparison to be based on job-related functions and responsibilities and not job title) for any business that directly competes with any portion of the Company. This restriction applies to any parent, division, affiliate, newly formed or purchased business(es) and/or successor of a business that competes with the Company. Further, during the Restricted Period, Executive shall not assist any individual or entity other than the Company in acquiring any entity with respect to which a proposal to acquire such entity was presented to the Board during the one (1) year period beginning prior to Executive's Termination Date, Extended Termination Date or notice given by Executive pursuant to Paragraph 6(d)(ii), as applicable.

Exhibit 10.24

a.Post-Termination Cooperation. Executive agrees that during and after employment with the Company and without additional compensation (other than reimbursement for reasonable associated expenses) to cooperate with the Company in the following areas:

i.Cooperation with the Company. Executive agrees to:

1.be reasonably available to answer questions for the Company's officers regarding any matter, project, initiative or effort for which Executive was responsible while employed by the Company; and

1.cooperate with the Company during the course of all third-party proceedings arising out of the Company's business about which Executive has knowledge or information.

For purposes of this Agreement, "proceeding" includes internal investigations, administrative investigations or proceedings and lawsuits (including pre-trial discovery and trial testimony) and "cooperation" includes (1) Executive being reasonably available for interviews, meetings, depositions, hearings and/or

trials without the need for a subpoena or assurances by the Company, (2) providing any and all documents in Executive's possession that relate to the proceeding, and

(3) providing assistance in locating any and all relevant notes and/or documents.

i.Cooperation with Third Parties. Unless compelled to do so by lawfully-served subpoena or court order, Executive agrees not to communicate with, or give statements or testimony to, any attorney representing an interest opposed to the Company's interest ("Opposing Attorney"), Opposing Attorney's representative (including a private investigator) or current or former employee relating to any matter (including pending or threatened lawsuits or administrative investigations) about which Executive has knowledge or information as a result of employment with the Company. Executive also agrees to notify the Company immediately after being contacted by a third party or receiving a subpoena or court order to appear and testify with respect to any matter that may include a claim opposed to the Company's interest. However, this Paragraph 9(f)(ii) shall not apply to any effort undertaken by Executive to enforce Executive's rights under this Agreement, but only to the extent necessary for that purpose.

i.Cooperation with the Media. Executive agrees not to communicate with, or give statements to, any member of the media (including print, television, electronic or radio media) relating to any matter (including pending or threatened lawsuits or administrative investigations) about which Executive has knowledge or information as a result of employment with the Company. Executive also agrees to notify the Company immediately after being contacted by any member of the media with respect to any matter affected by this Paragraph.

Exhibit 10.24

a.Non-Disparagement. Executive and Company shall at all times refrain from taking actions or making statements, written or verbal, that:

i.denigrate, disparage or defame the goodwill or reputation of Executive or the Company, as the case may be, or any of its trustees, officers, security holders, partners, agents or former or current employees and directors, or

i.are intended to, or may be reasonably expected to, adversely affect the morale of the employees of the Company.

Executive further agrees not to make any negative statements to third parties relating to Executive's employment or any aspect of the business of the Company and not to make any statements to third parties about the circumstances of the termination of Executive's employment, or about the Company or its trustees, directors, officers, security holders, partners, agents or former or current employees and directors, except as may be required by a court or governmental body.

a.Enforcement. The Executive acknowledges and agrees that: (i) the purpose

of the foregoing covenants, including, without limitation, the nonsolicitation and noncompetition covenants of Paragraphs 9(d) and (e), is to protect the goodwill, trade secrets and other Confidential Information of the Company; (ii) because of the nature of the business in which the Company is engaged and because of the nature of the Confidential Information to which the Executive has access, the Company would suffer irreparable harm and it would be impractical and excessively difficult to determine the actual damages of the Company in the event the Executive breached any of the covenants of this Paragraph 9; and (iii) remedies at law (such as monetary damages) for any breach of the Executive's obligations under this Paragraph 9 would be inadequate. The Executive therefore agrees and consents that if the Executive commits any breach of a covenant under this Paragraph 9, or threatens to commit any such breach, the Company shall have the right (in addition to, and not in lieu of, any other right or remedy that may be available to it, including but not limited to the right to terminate and forfeit as yet unpaid severance benefits under Paragraphs 6(a) and 6(c) of this Agreement) to temporary and permanent injunctive relief from a court of competent jurisdiction, without posting any bond or other security and without the necessity of proof of actual damage, and that the arbitration provisions of Paragraph 14 shall not apply.

a.Notice of Immunity under the Economic Espionage Act of 1996, as amended by the Defend Trade Secrets Act of 2016 (“DTSA”). Notwithstanding any other provision of this Agreement, the Executive will not be held criminally or civilly liable under any federal or state trade secret law for any disclosure of a trade secret that:

i.is made in confidence to a federal, state, or local government official, either directly or indirectly, or to an attorney; and that is disclosed solely for the purpose of reporting or investigating a suspected violation of law; or

i.is made in a complaint or other document filed under seal in a lawsuit or other proceeding.

Exhibit 10.24

If the Executive files a lawsuit for retaliation by the Company for reporting a suspected violation of law, the Executive may disclose the Company’s trade secrets to the Executive’s attorney and use the trade secret information in the court proceeding if the Executive:

a.files any document containing trade secrets under seal; and

a.does not disclose trade secrets, except pursuant to court order.

a.Security and Access. The Executive agrees and covenants to comply with all Company security policies and procedures as in force from time to time including without limitation those regarding computer equipment, telephone and voicemail systems, facilities access, key cards, access codes, intranet and internet, social media, computer systems and networks, e-mail systems, software, data security, encryption, firewalls, passwords and any and all other Company facilities, IT resources and communication technologies (“Facilities and Information Technology Resources”), and not to access or use any Facilities and Information Technology Resources except

as authorized by the Company. The Executive also agrees not to access or use any Facilities and Information Technology Resources in any manner after the termination of the Executive’s employment by the Company, whether such termination is voluntary or involuntary, without the Company’s consent.

a.Stock Ownership Requirements. During the Term, the Executive shall be expected to maintain ownership of Company common stock in accordance with guidelines established by the Board as in effect from time to time.

1.Indemnification. The Company shall indemnify Executive to the fullest extent permitted by applicable Delaware law (as may be amended from time to time), including the advance of expenses permitted herein. In the event that the Executive is made a party or threatened to be made a party to any action, suit, or proceeding, whether civil, criminal, administrative, or investigative (a “Proceeding”), other than any Proceeding initiated by the Executive or the Company related to any contest or dispute between the Executive and the Company or any of its affiliates with respect to this Agreement or the Executive’s employment hereunder, by reason of the fact that the Executive is or was a director or officer of the Company, or any affiliate of the Company, or is or was serving at the request of the Company as a director, officer, member, employee, or agent of another corporation or a partnership, joint venture, trust, or other enterprise, the Executive shall be indemnified and held harmless by the Company to the maximum extent permitted under applicable law and the Company’s bylaws from and against any liabilities, costs, claims, and expenses, including all costs and expenses incurred in defense of any Proceeding (including attorneys’ fees). Costs and expenses incurred by the Executive in defense of such Proceeding (including attorneys’ fees) shall be paid by the Company in advance of the final disposition of such litigation upon receipt by the Company of: (i) written request for payment; (ii) appropriate documentation evidencing the incurrence, amount, and nature of the costs and expenses for which payment is being sought; and

Exhibit 10.24

a.an undertaking adequate under applicable law made by or on behalf of the Executive to repay the amounts so paid if it shall ultimately be determined that the Executive is not entitled to be indemnified by the Company under this Agreement. Notwithstanding the foregoing, nothing in this Paragraph shall impose on the Company any obligation to indemnify the Executive from any tax, excise tax or similar penalty, including but not limited to any excise tax under Code Section 409A or 4999, imposed on the Executive with respect to any compensation, deferred compensation, severance or other benefits provided to Executive by Company under this Agreement or otherwise, without regard to whether the Company bears any culpability with respect to the imposition of such tax or not

1.Performance. The failure of either party to this Agreement to insist upon strict performance of any provision of this Agreement shall not constitute a waiver of its rights subsequently to insist upon strict performance of such provision or any other provision of this Agreement.

2.Non-Assignability. Neither party shall have the right to assign this Agreement or any rights or obligations hereunder without the consent of the other party.

1.Invalidity. If any provisions of this Agreement shall be found to be invalid

by any court of competent jurisdiction, such finding shall not affect the remaining provisions of this Agreement, all of which shall remain in full force and effect.

1.Arbitration and Legal Fees. In the event of any dispute regarding a refusal or failure by the Company to make payments or provide benefits hereunder for any reason, Executive shall have the right, in addition to all other rights and remedies provided by law, to arbitration of such dispute under the rules of the American Arbitration Association, which right shall be invoked by serving upon the Company a notice to arbitrate, stating the place of arbitration, within ninety

(90) days of receipt of notice in any form (including, without limitation, failure by the Company to respond to a notice from Executive within thirty (30) days) that the Company is withholding or proposes to withhold any payments or the provision of any benefits the Executive, in good faith, believes are called for hereunder. In the event of any such dispute, whether or not Executive exercises his right to arbitration, if it shall ultimately be determined that the Company's refusal or failure to make payments or provide benefits hereunder was wrongful or otherwise inconsistent with the terms of this Agreement, the Company shall indemnify and hold harmless Executive from and against any and all expenses incurred in connection with such determination, including reasonable legal and other fees and expenses. Accordingly, the Company agrees to pay within 30 days following the Company’s receipt of an invoice from the Executive all legal fees and expenses which the Executive may reasonably incur as a result of any contest by either party of the validity or enforceability of, or liability under, any provision of this Agreement, plus, in each case interest on any delayed payment at the applicable Federal rate provided for in Section 7872(f)(2)(A) of the Code, if the Executive prevails on any material claim made by him and disputed by the Company (or its successors and assigns) under the terms of this Agreement. Such payments shall be made in accordance with the provisions of Paragraph 20 in order to comply with Section 409A of the Code.

Exhibit 10.24

1.Survival of Certain Provisions. Notwithstanding any other provision of this Agreement, the termination of this Agreement for any reason shall not result in the termination of the rights and obligations of the parties under the provisions of Sections 5(d), 6, 7, 9, 10, 14 and 16 hereof, which shall survive any such termination. The right of recovery provisions of Section 5(d) shall cease to apply during the Extended Term and shall be automatically terminated upon a Change in Control of the Company (as defined in Paragraph 2(d)) except with respect to any right of recovery that has been asserted prior to such Change in Control.

1.Successors. This Agreement shall be binding upon and inure to the benefit of the Executive (and his personal representative), the Company and any successor organization or organizations that shall succeed to substantially all of the business and property of the Company and assume the Company’s obligations hereunder, whether by means of merger, consolidation, acquisition of substantially all of the assets of the Company, or operation of law. The Company shall require any successor organization or organizations to agree to assume the obligations of this Agreement.

2.Set-off. The Company shall have no right of set-off or counterclaim in respect of any claim, debt or obligation against any payments or benefits provided for in this Agreement except as otherwise provided herein.

1.Amendments. No Amendment to this Agreement shall be effective unless in writing and signed by both the Company and Executive. Notwithstanding the foregoing, if any compensation or benefits provided by this Agreement may result in the application of Code Section 409A, the Company shall, in consultation with the Executive, modify the Agreement in the least restrictive manner necessary in order to exclude such compensation from the definition of "deferred compensation" within the meaning of Code Section 409A or in order to comply with the provisions of Code Section 409A, other applicable provisions of the Code and/or any rules, regulations or other regulatory guidance issued under such statutory provisions, and without any diminution in the value of the payments to the Executive.

1.Governing Law. This Agreement shall be interpreted and enforced in accordance with the laws of the State of Delaware. The parties hereto irrevocably agree to submit to the jurisdiction and venue of the courts of the State of Delaware in any action or proceeding brought with respect to or in connection with this Agreement except for an action described in Paragraph 14.

1.Code Section 409A. Notwithstanding any provision of Paragraph 10 or 14 of this Agreement to the contrary, any legal fees and expenses to be paid by the Company pursuant to Paragraph 10 or 14 shall be subject to the following requirements in order to comply with Code Section 409A. Such legal fees and expenses shall be paid by the Company only to the extent incurred during the Term of the Agreement or for a period of ten (10) years after the Executive's Separation from Service. The Company shall pay such legal fees and expenses no later than the end of the calendar year next following the calendar year in which such fees and expenses were incurred, and the Company shall not be obligated to pay any such fees and expenses for which the Executive fails to submit an

Exhibit 10.24

invoice at least ten (10) business days before the end of the calendar year next following the calendar year in which such fees and expenses were incurred. The amount of such legal fees and expenses that the Company is obligated to pay in any given calendar year shall not affect the legal fees and expenses that the Company is obligated to pay in any other calendar year, and the Executive's right to have the Company pay such legal fees and expenses may not be liquidated or exchanged for any other benefit.

1.Notices. Unless otherwise stated herein, all notices hereunder shall be in writing and shall be deemed to be given when personally delivered or mailed by United States registered or certified mail, postage prepaid, to, if to the Company, 909 Silver Lake Boulevard, Dover, Delaware 19904, and, if to Executive, the last address therefore shown on the records of the Company. Either the Company or Executive may, by notice to the other, designate an address other than the foregoing for the receipt of subsequent notices.

1.Withholding. The Company may withhold from any amounts payable to Executive hereunder all federal, state, city or other taxes that the Company may reasonably deter- mine are required to be withheld pursuant to any applicable law or regulation.

1.Nature of Payments Upon Termination. All payments to Executive pursuant to Paragraph 6 of this Agreement shall be considered as liquidated damages or, in the case of certain payments pursuant to Paragraph 6(c), as severance payments in consideration of Executive's past services to the Company, and no such payment shall be regarded as a penalty to the Company.

1.Prior Agreement. The parties acknowledge and agree that the terms of this Agreement constitute the entire agreement of the parties with respect to the subject matter and supersede all prior agreements and amendments with respect thereto, including, without limitation, the Prior Agreement.

1.Acknowledgment. The parties hereto each acknowledge that each has read this Agreement and understands the same and that each enters into this Agreement freely and voluntarily.

IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL] By:

Jeffry M. Householder

Title: Chief Executive Officer

ATTEST:

Exhibit 10.24

Louis J. Anatrella

EXECUTIVE:

Chief Human Resources Officer

Jeffrey S. Sylvester

S I G N AT U R E CE RT IFIC AT E

Reference Number

84BBE2F0-3453-4FFB-850B-172072AEE28F

Transaction Type

Signature Request

Sent At

02/26/2020 08:25 EST

Executed At

03/02/2020 08:39 EST

Identity Method

email

Distribution Method

email

Signed Checksum

Document Name

5 - Executive Employment Agreement - Sylvester 12-4-19

Filename

5_-_executive_employment_agreement_-_sylvester_12-4-19.pdf

Pages

20 pages

Content Type

application/pdf

File Size

100 KB

Original Checksum

Signer Sequencing

Disabled

Document Passcode

Disabled

SIG N E R S

Name

Lou Anatrella

Email

lanatrella@chpk.com

Components

1

Status

signed

Multi-factor Digital Fingerprint Checksum

Exhibit 10.24

IP Address

168.149.161.43

Device

Internet Explorer via Windows

Drawn Signature

Signature Reference ID

3304D14E

Signature Biometric Count

281

Viewed At

03/02/2020 08:38 EST

Identity Authenticated At

03/02/2020 08:39 EST

Signed At

03/02/2020 08:39 EST

Name

Jeff Householder

Email

jhouseholder@chpk.com

Components

1

Status

signed

Multi-factor Digital Fingerprint Checksum

IP Address

174.227.0.204

Device

Mobile Safari via iOS

Drawn Signature

Signature Reference ID

D5BDEE6A

Signature Biometric Count

188

Viewed At

02/26/2020 16:43 EST

Identity Authenticated At

02/26/2020 16:44 EST

Signed At

02/26/2020 16:44 EST

Name

Jeff Sylvester

Email

jssylvester@chpk.com

Components

20

Status

signed

Multi-factor Digital Fingerprint Checksum

IP Address

162.212.91.7

Device

Mobile Safari via iOS

Drawn Signature

Exhibit 10.24

Signature Reference ID

96AFF91D

Signature Biometric Count

239

Viewed At

02/26/2020 09:20 EST

Identity Authenticated At

02/26/2020 09:23 EST

Signed At

02/26/2020 09:23 EST

A UD ITS

03/02/202008:39EST Lou Anatrella (lanatrella@chpk.com) signed the document on Internet Explorer via Windows from 168.149.161.43. 03/02/202008:39EST Lou Anatrella (lanatrella@chpk.com) authenticated via email on Internet Explorer via Windows from 168.149.161.43. 03/02/202008:38EST Lou Anatrella (lanatrella@chpk.com) viewed the document on Internet Explorer via Windows from 168.149.161.43. 03/02/202008:38EST Lou Anatrella (lanatrella@chpk.com) viewed the document on Internet Explorer via Windows from 34.232.127.140. 03/01/202018:00EST Lou Anatrella (lanatrella@chpk.com) was emailed areminder.

02/26/202016:44ESTJeff Householder (jhouseholder@chpk.com) signed the document on Mobile Safari via iOS from 174.227.0.204. 02/26/202016:44ESTJeff Householder (jhouseholder@chpk.com) authenticated via email on Mobile Safari via iOS from 174.227.0.204. 02/26/202016:43ESTJeff Householder (jhouseholder@chpk.com) viewed the document on Mobile Safari via iOS from52.44.93.197.

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02/26/202009:23ESTJeff Sylvester (jssylvester@chpk.com) authenticated via email on Mobile Safari via iOS from 162.212.91.7. 02/26/202009:20ESTJeff Sylvester (jssylvester@chpk.com) viewed the document on Mobile Safari via iOS from 34.232.127.140. 02/26/202009:19ESTJeffSylvester(jssylvester@chpk.com)viewedthedocumentonMobileSafarivia iOS from52.44.93.197.

02/26/202009:19ESTJeff Sylvester (jssylvester@chpk.com) viewed the documentonMobileSafarivia iOS from162.212.91.7. 02/26/202008:31ESTJeff Sylvester (jssylvester@chpk.com) viewed the document on Internet

Exhibit 10.24

Explorer via Windows from 37.120.150.163. 02/26/202008:31ESTJeff Sylvester (jssylvester@chpk.com) viewed the document on Mobile Safari via iOS from34.231.157.157.

02/26/202008:31ESTJeff Sylvester (jssylvester@chpk.com) viewed the document on Mobile Safari via iOS from 52.44.93.197. 02/26/202008:31ESTJeff Sylvester (jssylvester@chpk.com) viewed the document on Mobile Safari via iOS from 162.212.91.7. 02/26/202008:25ESTJeff Sylvester (jssylvester@chpk.com) was emailed a link to sign.

02/26/202008:25ESTJeff Householder (jhouseholder@chpk.com) was emailed a link to sign. 02/26/202008:25EST Lou Anatrella (lanatrella@chpk.com) was emailed a link to sign.

02/26/202008:25ESTDebby Frye (dfrye@chpk.com) created document '5_-_executive_employment_agreement_-_sylvester_12-4-19.pdf' on Internet Explorer via Windows from168.149.161.43.

EX-10.25

Exhibit 10.25

EX-10.26

Exhibit 10.26

EX-10.27

Exhibit 10.27

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 10.27

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 10.27

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 10.27

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 10.27

(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 10.27

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 10.27

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-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 24, 2021, 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, 2020.

/s/ Baker Tilly US, LLP (formerly Baker Tilly Virchow Krause, LLP)

Philadelphia, Pennsylvania

February 24, 2021

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, 2020 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 24, 2021

/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, 2020 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 24, 2021

/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, 2020, 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 24, 2021

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, 2020, 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 24, 2021

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, 2020	Feb. 18, 2021	Jun. 30, 2020
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2020
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			$ 1.3
Entity Common Stock, Shares Outstanding		17,473,124
Documents Incorporated by Reference	Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2021 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	2020
Document Fiscal Period Focus	FY
Amendment Flag	false
ICFR Auditor Attestation Flag	true

XML

Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues
Regulated Energy	$ 352,746	$ 343,006	$ 345,281
Unregulated Energy	152,526	154,151	161,905
Other	(17,074)	(17,552)	(16,870)
Total operating revenues	488,198	479,605	490,316
Operating Expenses
Regulated Energy cost of sales	91,994	102,803	121,828
Unregulated Energy and other cost of sales	45,944	51,698	68,341
Operations	142,055	137,845	132,523
Maintenance	15,587	15,679	14,387
Gain from a settlement	(130)	(130)	(130)
Depreciation and amortization	58,117	45,424	40,220
Other taxes	21,908	20,001	18,303
Total operating expenses	375,475	373,320	395,472
Operating Income	112,723	106,285	94,844
Other income (expense), net	3,222	(1,847)	(607)
Interest charges	21,765	22,224	16,146
Income from Continuing Operations Before Income Taxes	94,180	82,214	78,091
Income Taxes on Continuing Operations	23,538	21,114	21,123
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	70,642	61,100	56,968
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	686	(1,349)	(388)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	170	5,402
Net Income (Loss) Attributable to Parent	$ 71,498	$ 65,153	$ 56,580
Weighted Average Common Shares Outstanding:
Basic (in shares)	16,711,579	16,398,443	16,369,616
Diluted (in shares)	16,770,735	16,448,486	16,419,870
Basic Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share	$ 4.23	$ 3.73	$ 3.48
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0.05	0.24	(0.02)
Basic (in usd per share)	4.28	3.97	3.46
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share	4.21	3.72	3.47
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0.05	0.24
Diluted (in usd per share)	$ 4.26	$ 3.96	$ 3.45

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Net Income	$ 71,498	$ 65,153	$ 56,580
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(18), $(20) and $(22), respectively	(59)	(57)	(55)
Net gain (loss), net of tax of $(41), $368, and $(49), respectively	(154)	1,052	(108)
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $1,392, $(176) and $(555), respectively	3,643	(434)	(1,371)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent	(28)
Total Other Comprehensive Income (Loss)	3,402	561	(1,534)
Comprehensive Income	$ 74,900	$ 65,714	$ 55,046

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ (18,000)	$ (20,148)	$ (22,000)
Tax expense recognized on the net gain (loss)	(41,000)	368,387	(49,000)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	1,392,000	$ (176,000)	$ (555,000)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	$ (12,000)

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Activities
Net Income	$ 71,498	$ 65,153	$ 56,580
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	58,117	45,900	40,802
Depreciation and accretion included in operations expenses	9,599	8,752	8,535
Deferred income taxes, net	24,709	24,476	21,226
Gain on sale of discontinued operations	(200)	(7,344)
Realized gain (loss) on sale of assets/commodity contracts	(6,243)	(4,135)	5,497
Unrealized loss (gain) on investments/commodity contracts	(1,482)	(1,595)	429
Employee benefits and compensation	207	1,985	856
Share-based compensation	4,829	4,279	2,813
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(7,426)	36,489	(16,311)
Propane inventory, storage gas and other inventory	1,709	8,227	2,107
Regulatory assets/liabilities, net	(4,973)	(7,812)	2,250
Prepaid expenses and other current assets	2,424	11,115	(7,421)
Accounts payable and other accrued liabilities	4,941	(62,021)	35,907
Income taxes receivable (payable)	7,165	(4,750)	(522)
Customer deposits and refunds	2,238	(1,811)	(596)
Accrued compensation	(2,473)	2,120	708
Other assets and liabilities, net	(5,723)	(16,064)	(35,498)
Net cash provided by operating activities	158,916	102,964	117,362
Investing Activities
Property, plant and equipment expenditures	(165,511)	(184,727)	(240,351)
Proceeds from sale of assets	8,080	427	782
Acquisitions, net of cash acquired	(22,231)	(23,988)	(16,654)
Proceeds from the sale of discontinued operations	200	22,871
Environmental expenditures	(2,169)	(1,170)	(625)
Net cash used in investing activities	(181,631)	(186,587)	(256,848)
Financing Activities
Common stock dividends	(27,161)	(24,693)	(22,043)
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan	22,627
Payments for Repurchase of Common Stock		(721)	(706)
Proceeds from issuance of common stock, net of expenses	60,980	0	0
Payment, Tax Withholding, Share-based Payment Arrangement	(977)	(692)	(1,210)
Change in cash overdrafts due to outstanding checks	(825)	(1,174)	(5,943)
Net borrowings (repayments) under line of credit agreements	(71,637)	(45,913)	49,432
Proceeds from issuance of long-term debt	89,822	199,648	154,819
Repayment of long-term debt and finance lease obligation	(53,600)	(41,936)	(34,388)
Net cash provided by financing activities	19,229	84,519	139,961
Net (Decrease) Increase in Cash and Cash Equivalents	(3,486)	896	475
Cash and Cash Equivalents — Beginning of Period	6,985	6,089	5,614
Cash and Cash Equivalents — End of Period	$ 3,499	$ 6,985	$ 6,089

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment
Regulated Energy	$ 1,577,576	$ 1,441,473
Unregulated Energy	300,647	265,209
Other businesses and eliminations	30,769	39,850
Total property, plant and equipment	1,908,992	1,746,532
Accumulated depreciation	368,743	336,876
Construction Work in Progress	60,929	54,141
Net property, plant and equipment	1,601,178	1,463,797
Current Assets
Cash and cash equivalents	3,499	6,985
Accounts Receivable, before Allowance for Credit Loss, Current	61,675	50,899
Allowance for uncollectible accounts	4,785	1,337
Trade receivables, net	56,890	49,562
Accrued Revenue	21,527	20,846
Propane inventory, at average cost	5,906	5,824
Other inventory, at average cost	5,539	6,067
Regulatory assets	10,786	5,144
Storage gas prepayments	2,455	3,541
Income taxes receivable	12,885	20,050
Prepaid expenses	13,239	13,928
Derivative assets, at fair value	3,269	0
Other current assets	436	2,879
Total current assets	136,431	134,826
Deferred Charges and Other Assets
Goodwill	38,731	32,668
Other intangible assets, net	8,292	8,129
Investments, Fair Value Disclosure	10,776	9,229
Operating Lease, Right-of-Use Asset	11,194	11,563
Regulatory assets	113,806	73,407
Receivables and other deferred charges	12,079	49,579
Total deferred charges and other assets	194,878	184,575
Total Assets	1,932,487	1,783,198
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)	8,499	7,984
Additional paid-in capital	348,482	259,253
Retained earnings	342,969	300,607
Accumulated other comprehensive loss	(2,865)	(6,267)
Deferred compensation obligation	5,679	4,543
Treasury Stock, Value	(5,679)	(4,543)
Total stockholders’ equity	697,085	561,577
Long-term debt, net of current maturities	508,499	440,168
Total capitalization	1,205,584	1,001,745
Current Liabilities
Current portion of long-term debt	13,600	45,600
Short-term borrowing	175,644	247,371
Accounts payable	60,253	54,068
Customer deposits and refunds	33,302	30,939
Accrued interest	2,905	2,554
Dividends payable	7,683	6,644
Accrued compensation	13,994	16,236
Regulatory liabilities	6,284	5,991
Derivative liabilities, at fair value	127	1,844
Other accrued liabilities	15,240	12,077
Total current liabilities	329,032	423,324
Deferred Credits and Other Liabilities
Deferred income taxes	205,388	180,656
Regulatory liabilities	142,736	127,744
Environmental liabilities	4,299	6,468
Other pension and benefit costs	30,673	30,569
Operating Lease, Liability, Noncurrent	9,872	9,896
Deferred investment tax credits and other liabilities	4,903	2,796
Total deferred credits and other liabilities	397,871	358,129
Commitments and Contingencies
Total Capitalization and Liabilities	$ 1,932,487	$ 1,783,198

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 4,785	$ 1,337
Common stock, par value	$ 0.4867	$ 0.4867
Common stock, shares authorized	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands		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]			16,344,442
Stockholders' Equity Attributable to Parent		$ 486,294	[2]	$ 7,955	$ 253,470		$ 229,141	$ (4,272)	$ 3,395	$ (3,395)
Net Income		56,580					56,580
Other comprehensive loss		(1,534)						(1,534)
Dividends		(23,600)					(23,600)
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)		$ 0	(3)
Share-based compensation, shares				34,103
Share-based compensation		2,200	[3],[4]	$ 16	2,184
Treasury stock activities		0							459	(459)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect							907	(907)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, QuantificationPrincipleEffectOfAdoptionQuantification		(1,498)					(1,498)
Shares, Issued	[1],[2]			16,378,545
Stockholders' Equity Attributable to Parent		518,439	[2]	$ 7,971	255,651		261,530	(6,713)	3,854	(3,854)
Net Income		65,153					65,153
Other comprehensive loss		561						561
Dividends		(26,191)					(26,191)
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		(3)			(3)
Share-based compensation, shares	[3],[4]			25,231
Share-based compensation		3,618	[3],[4]	$ 13	3,605	[3],[4]
Treasury stock activities									689	(689)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(115)					115	(115)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan				$ 0
Shares, Issued	[1],[2]			16,403,776
Stockholders' Equity Attributable to Parent		561,577		$ 7,984	259,253		300,607	(6,267)	4,543	(4,543)
Net Income		71,498
Other comprehensive loss		3,402						3,402
Dividends		(29,106)					(29,106)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan		85,851		$ 498	85,353
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				1,023,609
Share-based compensation, shares	[3],[4]			34,456
Share-based compensation		3,893	[3],[4]	$ 17	3,876
Treasury stock activities									1,136	(1,136)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, QuantificationPrincipleEffectOfAdoptionQuantification		(30)					(30)
Shares, Issued	[1],[2]			17,461,841
Stockholders' Equity Attributable to Parent		$ 697,085		$ 8,499	$ 348,482		$ 342,969	$ (2,865)	$ 5,679	$ (5,679)

[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 105,087, 95,329 and 97,053 shares at December 31, 2020, 2019 and 2018, 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 2020, 2019 and 2018, we withheld 10,319, 7,635 and 16,918 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, 2020	Dec. 31, 2019	Dec. 31, 2018
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	105,087	95,329	97,053
Dividends Declared	$ 1.7250	$ 1.5850	$ 1.4350
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	10,319	7,635	16,918

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2020

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 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 and Divestitures for further information.

Covid-19 Effects

Effects of COVID-19

On March 13, 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 have continued to significantly impact economic conditions in the United States. We are considered an “essential business,” which allows us to continue our operational activities and construction projects while the social distancing restrictions remain in place. In response to the COVID-19 pandemic and related restrictions, we implemented our pandemic response plan, which includes having all employees who can work remotely do so in order to promote social distancing and providing personal protective equipment to field employees to reduce the spread of COVID-19.

Impacts from the restrictions imposed in our service territories and the implementation of our pandemic response plan, included reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including 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 the fourth quarter of 2020, we established regulatory assets, as currently authorized by the Delaware, Maryland and Florida PSCs, associated with the incremental expenses incurred by our natural gas and electric distribution businesses as a result of the pandemic. We are continuing to provide timely updates, monitor developments affecting our employees, customers, suppliers and stockholders, and take the necessary precautions to operate safely and comply with the CDC, Occupational Safety and Health Administration, state and local requirements. 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, 2020

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, 2020 and 2019 is provided in the following table:

	As of December 31,
(in thousands)	2020		2019
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	782,329	$	705,095
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	667,538		608,727
Electric distribution	127,710		127,651
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	151,258		141,945
Natural gas transmission and supply – Ohio	87,962		73,658
Electricity and steam generation	36,521		35,436
Mobile CNG and pipeline solutions	24,905		14,014
Other	30,769		40,006
Total property, plant and equipment	1,908,992		1,746,532
Less: Accumulated depreciation and amortization	(368,743)		(336,876)
Plus: Construction work in progress	60,929		54,141
Net property, plant and equipment	$	1,601,178	$	1,463,797

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, 2020 and 2019, the non-refundable contributions totaled $2.9 million and $2.1 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, 2020, 2019 and 2018 AFUDC totaled $0.7 million, $0.7 million and $1.9 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 $26.4 million of assets at December 31, 2020, 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 $0.3 million at December 31, 2020.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2020 and 2019, 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 $1.7 million and $1.5 million at December 31, 2020 and 2019, 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, 2020, 2019 and 2018:

	2020	2019	2018
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.6%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.6%	2.7%
Natural gas transmission – Florida	2.3%	2.4%	2.3%
Electric distribution	2.9%	3.4%	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, 2020, 2019 and 2018, we reported $9.6 million, $8.8 million and $8.5 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.

Cost of Sales

Cost of sales includes 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 cost of sales.

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, impacts from pandemics and general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.

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, 2020, 2019 or 2018.

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, 2020, 2019 and 2018 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 of each of our plans 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

Financial Instruments - Credit Losses (ASC 326) - In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments, which changes how entities account for credit losses for most financial assets and certain other instruments, and subsequent guidance which served to clarify or amend the original standard. ASU 2016-13 and the related amendments require entities to estimate lifetime expected credit losses for trade receivables and to provide additional disclosure related to credit losses. We adopted ASU 2016-13 on January 1, 2020 and recorded an immaterial cumulative effect in retained earnings as of that date. As a result, prior period financial information has not been recast and continues to be reported under the accounting guidance that was effective during those periods.

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 analyzed 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 have 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, 2020, 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, 2019	$	1,337
Additions:
Provision for credit losses	3,827
Recoveries	613
Deductions:
Write offs	(992)
Balance at December 31, 2020	$	4,785

Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. We adopted ASU 2018-13 beginning January 1, 2020 and, since the changes only impacted disclosures, its adoption did not have a material impact on our results of operations or financial position.

Intangibles - Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 was effective beginning January 1, 2020. The amendments included in this ASU are to be applied prospectively, and its adoption did not have a material impact on our results of operations or financial position.

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Earnings Per Share

12 Months Ended

Dec. 31, 2020

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 years ended December 31:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	70,642	$	61,100	$	56,968
Income/(Loss) from Discontinued Operations	856		4,053		(388)
Net Income	$	71,498	$	65,153	$	56,580
Weighted average shares outstanding	16,711,579		16,398,443		16,369,616
Earnings Per Share from Continuing Operations	$	4.23	$	3.73	$	3.48
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Basic Earnings Per Share	$	4.28	$	3.97	$	3.46
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,711,579		16,398,443		16,369,616
Effect of dilutive securities — Share-based compensation	59,156		50,043		50,254
Adjusted denominator — Diluted	16,770,735		16,448,486		16,419,870
Earnings Per Share from Continuing Operations	$	4.21	$	3.72	$	3.47
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Diluted Earnings Per Share	$	4.26	$	3.96	$	3.45

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Acquisitions

12 Months Ended

Dec. 31, 2020

Business Combinations [Abstract]

Acquisitions

ACQUISITIONS AND DIVESTITURES

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 recorded contingent consideration of $0.3 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2020. There are multiple strategic benefits to this acquisition including it: (i) expands our propane territory serviced in Florida and (ii) includes an established customer base with 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. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021.

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 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. Elkton Gas continues to operate out of its existing office with the same local personnel who are now also serving our existing franchised service territory in Cecil County.

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. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021.

Acquisition of Boulden

In December 2019, Sharp acquired certain propane operating assets of Boulden, which provides propane distribution service to approximately 5,200 customers in Delaware, Maryland and Pennsylvania, for approximately $24.6 million, net of cash acquired. Additionally, the purchase price included $0.2 million of working capital. We recorded contingent consideration of $0.6 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for the purchase of the operating assets of Boulden as a business combination and integrated the business into our Sharp operation. There are multiple strategic benefits to this acquisition including it: (i) overlays with the Elkton Gas acquisition to establish an integrated energy delivery platform in Cecil County, Maryland; (ii) includes an established customer base with opportunities for future growth; and (iii) enables operational synergies, including supply, for the northern Delmarva Peninsula.

In connection with this acquisition, we recorded $8.3 million in property, plant and equipment, $5.1 million in intangible assets associated with customer relationships and non-compete agreements and $11.2 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition were finalized in the fourth quarter of 2020.

These acquisitions generated the following operating revenues and income:

	For the Year Ended				For the Year Ended
	December 31, 2020				December 31, 2019
	Operating Revenues		Operating Income		Operating Revenues		Operating Income
(in thousands)
Western Natural Gas	$	555	$	90	$	—	$	—
Elkton Gas	$	2,399	$	418	$	—	$	—
Boulden	$	5,717	$	1,854	$	550	$	239

Divestiture of PESCO

During the fourth quarter of 2019, we sold PESCO's assets and contracts in four separate transactions and exited the natural gas marketing business. In 2020 and 2019, we received a total of $23.1 million in cash consideration from the buyers, inclusive of working capital of $8.0 million and recognized total pre-tax gain of $7.5 million ($5.4 million after tax) in connection with these transactions. As a result of the sales agreements, we began to report PESCO as discontinued operations during the third quarter of 2019, excluded PESCO's performance from continuing operations for all periods presented and classified its assets and liabilities as held for sale where applicable.

Operating revenues and costs of sales from the previous reporting periods, which were previously eliminated in consolidation related to intercompany sales and purchases, have been grossed up and are now reflected as a component of operating revenues and costs of sales for the year ended December 31, 2019 and 2018. We recast these amounts because, upon completion of the sales transactions, we continued to provide and receive services from the buyers through the remainder of the contractual terms.

A summary of discontinued operations presented in the consolidated statements of income includes the following:

	For the Year Ended December 31,
(in thousands)	2020		2019		2018
Operating revenues(1)	$	26	$	161,289	$	258,713
Cost of sales(1)	—		157,646		252,111
Other operating expenses	230		5,221		6,825
Operating loss	(204)		(1,578)		(223)
Interest and other income (expense)	1,013		(297)		(294)
Earnings / (Loss) from Discontinued Operations before income taxes	809		(1,875)		(517)
Gain on sale of Discontinued Operations	200		7,344		—
Income tax (benefit) / expense	153		1,416		(129)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	856	$	4,053	$	(388)

(1) Included in operating revenues and cost of sales for the years ended December 31, 2019 and 2018, is $19.8 million, and $31.5 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity which continued with the buyers after the disposition of the assets of PESCO.

Since the disposition of the assets and contracts of PESCO was completed in the fourth quarter of 2019, there were no assets or liabilities classified as held for sale at December 31, 2020 and December 31, 2019.

We have elected not to separately disclose discontinued operations on the consolidated statements of cash flows. The following table summarizes significant statements of cash flows data related to the discontinued operations of PESCO:

	For the Year Ended December 31,
(in thousands)	2019		2018
Depreciation and amortization	$	477	$	582
Property, plant and equipment expenditures	$	—	$	115
Deferred income taxes	$	(125)	$	1,088
Realized / (loss) gain on commodity contracts	$	(2,161)	$	5,002

Our Delmarva Peninsula natural gas distribution operations had executed asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and expired on March 31, 2020. As a result of the sale of the assets of PESCO, effective October 1, 2019, these agreements were managed by New Jersey Resource Energy Services Company through the remainder of the contract term. In March 2020, our Delmarva Peninsula natural gas distribution operations entered into new 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. In addition to the asset management agreements, Eastern Shore had several firm transportation and capacity arrangements with PESCO, which were included in the assets sold to United Energy Trading, LLC. Eastern Shore will continue to fulfill these arrangements throughout the remainder of their contractual term. These agreements currently have expiration dates of November 30, 2021.

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018:

	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 year 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.

	For the year ended December 31, 2018
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	70,338	$	—	$	—	$	70,338
Florida natural gas division	25,341		—		—		25,341
FPU electric distribution	79,803		—		—		79,803
FPU natural gas distribution	81,118		—		—		81,118
Maryland natural gas division	24,172		—		—		24,172
Sandpiper natural gas/propane operations	22,088		—		—		22,088
Total energy distribution	302,860		—		—		302,860
Energy transmission
Aspire Energy	—		35,407		—		35,407
Aspire Energy Express	—		—		—		—
Eastern Shore	64,248		—		—		64,248
Peninsula Pipeline	11,927		—		—		11,927
Total energy transmission	76,175		35,407		—		111,582
Energy generation
Eight Flags	—		17,302		—		17,302
Propane operations
Propane delivery operations	—		125,560		—		125,560
Energy delivery services
Marlin Gas Services	—		121		—		121
Other and eliminations
Eliminations	(33,754)		(16,485)		(17,522)		(67,761)
Other	—		—		652		652
Total other and eliminations	(33,754)		(16,485)		(16,870)		(67,109)
Total operating revenues (1)	$	345,281	$	161,905	$	(16,870)	$	490,316

(1) Total operating revenues for the year ended December 31, 2018, include other revenue (revenues from sources other than contracts with customers) of $0.2 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.

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, 2020 and 2019 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2019	$	47,430	$	3,465	$	589
Balance at 12/31/2020	55,600		4,816		644
Increase (decrease)	$	8,170	$	1,351	$	55

Our trade receivables are included in accounts receivable 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 year ended December 31, 2020 and 2019, we recognized revenue of $1.3 million and $1.0 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, 2020 are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026 and thereafter
Eastern Shore and Peninsula Pipeline	$	34,978	$	27,155	$	21,748	$	19,587	$	18,736	$	174,774
Natural gas distribution operations	4,351		5,394		4,937		4,705		4,172		32,996
FPU electric distribution	566		566		566		566		275		825
Total revenue contracts with remaining performance obligations	$	39,895	$	33,115	$	27,251	$	24,858	$	23,183	$	208,595

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, 2020

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 operating 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. Effective in the third quarter of 2019, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations. See Note 4, Acquisitions and Divestitures for additional details of the divestiture of PESCO.

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,
	2020		2019		2018
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	350,853	$	340,857	$	343,313
Unregulated Energy	137,345		138,748		147,003
Total operating revenues, unaffiliated customers	$	488,198	$	479,605	$	490,316
Intersegment Revenues (1)
Regulated Energy	$	1,893	$	2,149	$	1,968
Unregulated Energy	15,181		15,403		14,902
Other businesses	528		529		652
Total intersegment revenues	$	17,602	$	18,081	$	17,522
Operating Income
Regulated Energy	$	92,124	$	86,584	$	79,215
Unregulated Energy	20,664		19,938		17,125
Other businesses and eliminations	(65)		(237)		(1,496)
Operating Income	112,723		106,285		94,844
Other income (expense), net	3,222		(1,847)		(607)
Interest charges	21,765		22,224		16,146
Income from Continuing Operations before Income Taxes	94,180		82,214		78,091
Income Taxes on Continuing Operations	23,538		21,114		21,123
Income from Continuing Operations	70,642		61,100		56,968
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		(388)
Gain on sale of Discontinued Operations, Net of tax	170		5,402		—
Net Income	$	71,498	$	65,153	$	56,580
Depreciation and Amortization
Regulated Energy	$	46,079	$	35,227	$	31,876
Unregulated Energy	11,988		10,130		8,263
Other businesses and eliminations	50		67		81
Total depreciation and amortization	$	58,117	$	45,424	$	40,220
Capital Expenditures
Regulated Energy	$	147,100	130,604		$	235,912
Unregulated Energy	46,295		60,034		38,585
Other businesses	2,480		8,348		8,364
Total capital expenditures	$	195,875	$	198,986	$	282,861

 

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

	As of December 31,
	2020		2019
Identifiable Assets
Regulated Energy segment	$	1,547,619	$	1,434,066
Unregulated Energy segment	347,665		296,810
Other businesses and eliminations	37,203		52,322
Total identifiable assets	$	1,932,487	$	1,783,198

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Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2020, 2019 and 2018 were as follows:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Cash paid for interest	$	22,884	$	23,856	$	16,741
Cash (received) paid for income taxes, net of refunds	$	(8,135)	$	3,221	$	477

Non-cash investing and financing activities during the years ended December 31, 2020, 2019, and 2018 were as follows: 

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	23,625	$	13,470	$	39,402
Common stock issued for the Retirement Savings Plan	$	1,605	$	—	$	—
Common stock issued under the SICP	$	1,971	$	1,691	$	2,006
Capital lease obligation	$	—	$	—	$	1,310

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Derivative Instruments

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

PESCO's Derivative Instruments

As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts and, therefore, we no longer have natural gas futures and contracts recorded in our consolidated financial statements.

Volume of Derivative Activity

As of December 31, 2020, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	17.6	Cash flows hedges	May 2023
Sharp	Propane (gallons)	0.4	Fair value hedges	February 2021

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 during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in December 2020 through May 2023) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap 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 $2.7 million of unrealized gain from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2021.

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.

We designated and accounted for 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. We expect to reclassify less than $0.1 million from accumulated other comprehensive income (loss) to earnings during the next 12-month period ended December 31, 2021.

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, with the balance related to the account is as follows:

(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
Sharp	Other Current Assets	$	—	$	2,317
Sharp	Other Current Liabilities	$	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, 2020 and 2019 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	3,255		—
Total Derivative Assets		$	3,269	$	—

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	64		1,844
Interest rate swap agreements	Derivative liabilities, at fair value	40		—
Total Derivative Liabilities		$	127	$	1,844

 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)		2020		2019		2018
Derivatives not designated as hedging instruments
Propane swap agreements	Cost of sales	$	—	$	—	$	(13)
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	(12)		—		—
Put/Call option	Propane inventory	34		—		—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	2,428		1,520		(647)
Propane swap agreements	Other comprehensive income (loss)	5,035		(253)		(2,773)
Interest rate swap agreements	Interest expense	60		—		—
Interest rate swap agreements	Other comprehensive income (loss)	(40)		—		—
Natural gas swap contracts	Other comprehensive income (loss)	—		(63)		200
Natural gas futures contracts	Other comprehensive income (loss)	—		(294)		532
Total		$	7,505	$	910	$	(2,701)

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2019	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	$	27	$	27	$	—	$	—
Investments—guaranteed income fund	803		—		—		803
Investments—mutual funds and other	8,399		8,399		—		—
Total investments	9,229		8,426		—		803
Derivative assets	—		—		—		—
Total assets	$	9,229	$	8,426	$	—	$	803
Liabilities:
Derivative liabilities	$	1,844	$	—	$	1,844	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Beginning Balance	$	803	$	686
Purchases and adjustments	261		131
Transfers/disbursements	1,065		(29)
Investment income	27		15
Ending Balance	$	2,156	$	803

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

At December 31, 2020 and 2019, 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, 2020, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $523.0 million, compared to the estimated fair value of $548.5 million. At December 31, 2019, long-term debt, which includes the current maturities but excludes finance lease obligations and debt issuance costs, had a carrying value of $486.6 million, compared to a fair value of $505.0 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 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, 2019

Investments [Abstract]

Investments

INVESTMENTS

 The investment balances at December 31, 2020 and 2019, consisted of the following:

	As of December 31,
(in thousands)	2020		2019
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	10,755	$	9,202
Investments in equity securities	21		27
Total	$	10,776	$	9,229

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2020, 2019 and 2018, we recorded net unrealized gains of $1.5 million, $1.6 million, and net unrealized losses of $0.4 million, respectively in other income (expense) 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, 2020

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, 2020 and 2019 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2019	$	3,353	$	29,315	$	32,668
Additions (1)	4,264		1,799		6,063
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731

(1)Includes goodwill from the purchase of operating assets of Elkton Gas in the third quarter of 2020 and Western Natural Gas in October 2020.

The annual impairment testing for 2020 and 2019 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2020 and 2019 are as follows:

	As of December 31,
	2020				2019
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	10,680	$	4,269	$	9,391	$	3,463
Non-Compete agreements (1)	2,375		768		2,252		451
Patents	452		236		452		118
Other	270		212		270		204
Total	$	13,777	$	5,485	$	12,365	$	4,236

(1) The customer relationship and non-compete agreements amounts includes $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 amounts also include customer relationship and non-compete agreements amounts of $4.6 million and $0.5 million, respectively, recorded as a result of the purchase of the operating assets of Boulden in December 2019.

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 11 years. Amortization expense of intangible assets for the year ended December 31, 2020, 2019 and 2018 was $1.2 million, $0.8 million and $0.4 million, respectively. Amortization expense of intangible assets is expected to be $1.3 million for the year 2021, $1.0 million for the year 2022 and $0.9 million for the years 2023 through 2025.

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Income Taxes

12 Months Ended

Dec. 31, 2020

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, 2020, 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 NOL 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 NOL in various states of $40.0 million and $54.7 million as of December 31, 2020 and 2019, respectively, almost all of which will expire in 2039. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.6 million and $5.5 million related to state NOL carry-forwards at December 31, 2020 and 2019, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized.

Tax Law Changes

In March 2020, the CARES Act was signed into law and included several significant changes to the Internal Revenue Code. The CARES Act includes certain tax relief provisions including the ability to carryback five years net operating losses arising in a tax year beginning in 2018, 2019, or 2020. This provision allows a taxpayer to recover taxes previously paid at a 35 percent federal income tax rate during tax years prior to 2018. In addition, the CARES Act removed the taxable income limitation to allow a tax NOL to fully offset taxable income for tax years beginning before January 1, 2021. Our income tax expense for the year ended December 31, 2020 included a tax benefit of $1.8 million attributable to the tax NOL carryback provided under the CARES Act for losses generated in 2018 and 2019 and then applied back to our 2013 and 2015 tax years in which we paid federal income taxes at a 35 percent tax rate.

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 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 2020, 2019, and 2018; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2020, 2019, and 2018 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2020 and 2019.

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Current Income Tax Expense
Federal	$	(2,777)	$	(2,252)	$	(361)
State	2,162		(491)		617
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	(662)		(2,790)		209
Deferred Income Tax Expense (1)
Property, plant and equipment	23,224		25,907		19,178
Deferred gas costs	(714)		79		(1,435)
Pensions and other employee benefits	(75)		(454)		454
FPU merger-related premium cost and deferred gain	156		(278)		(528)
Net operating loss carryforwards	5,107		(3,772)		(250)
Other	(3,498)		2,422		3,495
Total deferred income tax expense	24,200		23,904		20,914
Income Tax Expense from Continuing Operations	23,538		21,114		21,123
Income Tax Expense (benefit) from Discontinued Operations	153		1,416		(129)
Total Income Tax	$	23,691	$	22,530	$	20,994

(1) Includes $4.9 million, $4.7 million, and $3.5 million of deferred state income taxes for the years 2020, 2019 and 2018, respectively.

	For the Year Ended December 31,
	2020			2019			2018
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	19,778		$	17,264		$	16,400
State income taxes, net of federal benefit	5,051			5,093			4,071
ESOP dividend deduction	(218)			(173)			(158)
CARES Act Tax Benefit	(1,841)			—			—
Other	768			(1,070)			810
Total Income Tax Expense for Continuing Operations	$	23,538		$	21,114		$	21,123
Effective Income Tax Rate for Continuing Operations	24.99		%	25.65		%	27.13		%

(1) Federal income taxes were calculated at 21 percent for 2020, 2019, and 2018.

	As of December 31,
	2020		2019
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	199,287	$	173,466
Acquisition adjustment	6,618		6,969
Loss on reacquired debt	201		220
Deferred gas costs	509		1,223
Natural gas conversion costs	5,379		4,956
Storm reserve liability	7,073		10,316
Other	5,587		1,456
Total deferred income tax liabilities	224,654		198,606
Deferred income tax assets:
Pension and other employee benefits	4,636		3,818
Environmental costs	1,064		1,486
Net operating loss carryforwards	1,587		5,523
Self-insurance	—		146
Storm reserve liability	409		96
Accrued Expenses	6,153		2,064
Other	5,417		4,817
Total deferred income tax assets	19,266		17,950
Deferred Income Taxes Per Consolidated Balance Sheets	$	205,388	$	180,656

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Long-Term Debt

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2020		2019
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	—	$	7,990
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	—		2,000
5.93% note, due October 31, 2023	9,000		12,000
5.68% note, due June 30, 2026	17,400		20,300
6.43% note, due May 2, 2028	5,600		6,300
3.73% note, due December 16, 2028	16,000		18,000
3.88% note, due May 15, 2029	45,000		50,000
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		—
2.96% note, due August 15, 2035	40,000		—
Term Note due February 28, 2020	—		30,000
Less: debt issuance costs	(901)		(822)
Total long-term debt	522,099		485,768
Less: current maturities	(13,600)		(45,600)
Total long-term debt, net of current maturities	$	508,499	$	440,168

Annual maturities

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

Year	2021		2022		2023		2024		2025		Thereafter		Total
(in thousands)
Payments	$	13,600	$	17,100	$	20,600	$	17,600	$	24,600	$	429,500	$	523,000

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our shelf agreements at December 31, 2020:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		—		150,000
NYL Shelf Agreement (3)	150,000		(140,000)		—		10,000
Total	$	670,000	$	(360,000)	$	—	$	310,000

(1) In April 2020, we amended the Prudential Shelf Agreement to increase the available borrowing capacity by $150.0 million. The Shelf Agreement expires in April 2023. In July 2020, we issued $50 million of Prudential Shelf Notes at the rate of 3.00 percent per annum.

(2) In May 2020, we amended an agreement with MetLife to provide a new $150 million MetLife Shelf Agreement for a three-year term ending May 2023.

(3) In August 2020 we issued $40 million of NYL Shelf Notes at the rate of 2.96 percent per annum. The NYL Shelf Agreement expires in November 2021.

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.

Term Notes

In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. This note was paid in full in February 2020 utilizing our short-term borrowing facilities.

Secured First Mortgage Bonds

In December 2020, we redeemed FPU’s 9.08 percent secured first mortgage bonds outstanding of $8.0 million, prior to their maturity, which included the outstanding principal balances, interest accrued, premium and fees. We used short-term borrowing to finance the redemption of these bonds. The difference between the carrying value of those bonds and the amount paid at redemption totaling $1.0 million was charged to expense. As a result of the redemption of these bonds, at December 31, 2020, the restriction that limited the payment of dividends by FPU is no longer applicable.

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, 2020, the cumulative consolidated net income base was $581.0 million, offset by restricted payments of $256.4 million, leaving $324.6 million of cumulative net income free of restrictions. As of December 31, 2020, we were in compliance with all of our debt covenants.

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Short-Term Borrowing

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Short-Term Borrowing

SHORT-TERM BORROWINGS

At December 31, 2020 and 2019, our short-term borrowings totaled $175.6 million and $247.4 million, respectively, at the weighted average interest rates of 1.28 percent and 2.62 percent, respectively. Included in the December 31, 2020 balance, is $60.0 million in short-term debt for which we have entered into interest rate swap agreements.

In September 2020, we entered into a new $375.0 million syndicated Revolver with six participating lenders. As a result of entering into the Revolver, in September 2020, we terminated and paid all outstanding balances under the previously existing bilateral lines of credit and the previous revolving credit facility.

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, 2020, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is 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 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 total indebtedness to total capitalization ratio. As of December 31, 2020, our pricing under the Revolver included a commitment fee of 0.175 percent and an interest rate of 1.125 percent over LIBOR. Our available credit under the new Revolver at December 31, 2020 was $196.9 million. As of December 31, 2020, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. Although the 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 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. The fixed swap rates 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 amounts totaling $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.

We are authorized by our Board of Directors to borrow up to $375 million of short-term debt, as required.

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Leases

12 Months Ended

Dec. 31, 2020

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 the Mid-Atlantic, Mid-West and in Florida. 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, 2020, 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, 2020, 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	2020		2019
Operating lease cost (1)	Operations expense	$	2,029	$	2,577
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	—		650
Interest on lease liabilities	Interest expense	—		5
Net lease cost		$	2,029	$	3,232

(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, 2020 and 2019:

(in thousands)	Balance sheet classification	December 31, 2020		December 31, 2019
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,194	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,747	$	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,872		9,896
Total lease liabilities		$	11,619	$	11,601

The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2020 and 2019:

	December 31, 2020		December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.70		8.88
Weighted-average discount rate
Operating leases	3.8	%	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, 2020 and 2019:

	Year Ended December 31,
(in thousands)	2020		2019
Operating cash flows from operating leases	$	1,956	$	2,230
Operating cash flows from finance leases	$	—	$	5
Financing cash flows from finance leases	$	—	$	650

The following table presents the future undiscounted maturities of our operating leases at December 31, 2020 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2021	$	2,027
2022	1,984
2023	1,923
2024	1,657
2025	1,395
Thereafter	4,419
Total lease payments	13,405
Less: Interest	1,786
Present value of lease liabilities	$	11,619

(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, 2020

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 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 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 loss for the years ended December 31, 2020 and 2019. 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, 2018	$	(5,928)	$	(785)	$	—	$	(6,713)
Other comprehensive income (loss) before reclassifications	(872)		2,161		—		1,289
Amounts reclassified from accumulated other comprehensive income (loss)	1,867		(2,595)		—		(728)
Net current-period other comprehensive income (loss)	995		(434)		—		561
Prior-year reclassification	—		(115)		—		(115)
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)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2020, 2019 and 2018. 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)	2020		2019		2018
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(592)		(2,600)		(579)
Total before income taxes	(515)		(2,523)		(502)
Income tax benefit (4)	150		656		63
Net of tax	$	(365)	$	(1,867)	$	(439)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	2,428	$	1,520	$	(647)
Natural gas swaps (2)(3)	—		7		197
Natural gas futures (2)(3)	—		2,096		(2,010)
Total before income taxes	2,428		3,623		(2,460)
Income tax (expense) benefit (4)	(671)		(1,028)		701
Net of tax	$	1,757	$	2,595	$	(1,759)
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	60	$	—	$	—
Total before income taxes	60		—		—
Income tax expense	(16)		—		—
Net of tax	$	44	$	—	$	—
Total reclassifications for the period	$	1,436	$	728	$	(2,198)

(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, 2020

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

We sponsor three defined benefit pension plans: the Chesapeake Utilities Pension Plan ("Chesapeake Pension Plan"), the FPU Pension Plan and the Chesapeake SERP.

The Chesapeake Pension Plan, a qualified plan, was closed to new participants, effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation, effective January 1, 2005. Benefits under the Chesapeake Pension 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 Pension Plan was frozen were credited with two additional years of service. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result, during the fourth quarter of 2019, we purchased annuities for those retirees currently receiving monthly payments and offered lump-sum payments to terminated vested employees. Accordingly, the pension settlement expense associated with the de-risking strategy allocated to our Regulated Energy operations was recorded as regulatory assets or deferred pending regulatory approval authorizing recovery through rates. The remaining portion of the pension settlement expense totaling $0.7 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, 2020 and 2019, 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, 2020 and 2019 and the net periodic cost for the years ended December 31, 2020, 2019 and 2018 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2020			2019			2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,214		$	10,712		$	65,304		$	59,377		$	2,157		$	2,285
Interest cost	176			375			2,085			2,452			63			74
Actuarial loss	450			1,443			6,069			6,508			144			159
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Benefit obligation — end of year	6,146			6,214			70,366			65,304			2,212			2,157
Change in plan assets:
Fair value of plan assets — beginning of year	4,630			8,649			49,703			43,601			—			—
Actual return on plan assets	369			1,180			6,581			7,978			—			—
Employer contributions	304			1,117			2,774			1,157			152			361
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Fair value of plan assets — end of year	4,609			4,630			55,966			49,703			—			—
Reconciliation:
Funded status	(1,537)			(1,584)			(14,400)			(15,601)			(2,212)			(2,157)
Accrued pension cost	$	(1,537)		$	(1,584)		$	(14,400)		$	(15,601)		$	(2,212)		$	(2,157)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%	2.25		%	3.00		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.50		%	—		%	—		%

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2020			2019 (1)			2018			2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic pension cost:
Interest cost	$	176		$	375		$	384		$	2,085		$	2,452		$	2,339		$	63		$	74		$	83
Expected return on assets	(157)			(487)			(542)			(2,967)			(2,770)			(3,091)			—			—			—
Amortization of actuarial loss	243			391			343			552			505			404			20			85			101
Settlement expense	203			1,982			—			—			—			—			—			58			—
Net periodic pension cost	465			2,261			185			(330)			187			(348)			83			217			184
Amortization of pre-merger regulatory asset	—			—			—			—			543			761			—			—			—
Total periodic cost	$	465		$	2,261		$	185		$	(330)		$	730		$	413		$	83		$	217		$	184
Assumptions:
Discount rate	3.00		%	3.00		%	3.50		%	3.25		%	4.25		%	3.75		%	3.00		%	4.00		%	3.50		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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.

Included in the net periodic costs for the FPU Pension Plan for the years ended December 31, 2019 and 2018 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. At December 31, 2020 and 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. The changes in investment types for the Chesapeake Pension Plan at December 31, 2020 and 2019, compared to same period in 2018, are associated with the de-risking strategy executed during the fourth quarter of 2019. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2020, 2019 and 2018:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2020		2019		2018		2020		2019		2018
Asset Category
Equity securities	—	%	—	%	49	%	54	%	53	%	50	%
Debt securities	96	%	92	%	41	%	37	%	37	%	41	%
Other	4	%	8	%	10	%	9	%	10	%	9	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

The investment policy of both the Chesapeake Utilities and FPU Pension Plans 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 plans, earn a competitive return to increasingly fund a large portion of the plans’ 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 each plan.

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ 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	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
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, 2020 and 2019, 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, 2020								At December 31, 2019
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)	$	3,615	$	—	$	—	$	3,615	$	3,553	$	—	$	—	$	3,553
U.S. Mid Cap (1)	1,672		—		—		1,672		1,604		—		—		1,604
U.S. Small Cap (1)	891		—		—		891		726		—		—		726
International (2)	11,307		—		—		11,307		9,855		—		—		9,855
Alternative Strategies (3)	5,586		—		—		5,586		4,739		—		—		4,739
	23,071		—		—		23,071		20,477		—		—		20,477
Mutual Funds - Debt securities
Fixed income (4)	21,563		—		—		21,563		19,220		—		—		19,220
High Yield (4)	2,606		—		—		2,606		2,476		—		—		2,476
	24,169		—		—		24,169		21,696		—		—		21,696
Mutual Funds - Other
Commodities (5)	2,246		—		—		2,246		1,708		—		—		1,708
Real Estate (6)	1,954		—		—		1,954		2,288		—		—		2,288
Guaranteed deposit (7)	—		—		1,019		1,019		—		—		1,147		1,147
	4,200		—		1,019		5,219		3,996		—		1,147		5,143
Total Pension Plan Assets in fair value hierarchy	$	51,440	$	—	$	1,019	52,459		$	46,169	$	—	$	1,147	47,316
Investments measured at net asset value (8)							8,116								7,017
Total Pension Plan Assets							$	60,575							$	54,333

(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, 2020 and 2019, 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, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Balance, beginning of year	$	1,147	$	627
Purchases	3,190		2,274
Transfers in	921		3,090
Disbursements	(4,290)		(4,907)
Investment income	51		63
Balance, end of year	$	1,019	$	1,147

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, 2020 and 2019:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,100		$	1,002		$	1,224		$	1,187
Interest cost	26			39			30			48
Plan participants contributions	166			149			37			38
Actuarial loss (gain)	(34)			73			(181)			47
Benefits paid	(225)			(163)			(101)			(96)
Benefit obligation — end of year	1,033			1,100			1,009			1,224
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	59			14			64			58
Plan participants contributions	166			149			37			38
Benefits paid	(225)			(163)			(101)			(96)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,033)			(1,100)			(1,009)			(1,224)
Accrued postretirement cost	$	(1,033)		$	(1,100)		$	(1,009)		$	(1,224)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%

Net periodic postretirement benefit costs for 2020, 2019, and 2018 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	26		$	39		$	38		$	30		$	48		$	47
Amortization of actuarial loss	24			46			58			(19)			—			—
Amortization of prior service cost (credit)	(77)			(77)			(77)			—			—			—
Net periodic cost	(27)			8			19			11			48			47
Amortization of pre-merger regulatory asset	—			—			—			6			8			8
Total periodic cost	$	(27)		$	8		$	19		$	17		$	56		$	55
Assumptions
Discount rate	3.00		%	4.00		%	3.50		%	3.25		%	4.25		%	3.75		%

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, 2020:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(370)	$	—	$	(370)
Net loss (gain)	2,033		21,242		699		546		(194)		24,326
Total	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,033	$	4,036	$	699	$	176	$	(37)	$	6,907
Post-merger regulatory asset	—		17,206		—		—		(157)		17,049
Total unrecognized cost	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2020 is net of income tax benefits of $1.8 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, 2020, 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 2020, 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. Since Chesapeake Utilities' plans and FPU’s plans have different expected plan lives, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan and the de-risking strategy implemented in the fourth quarter of 2019 for Chesapeake's Plan, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake Utilities' and FPU’s plans. Since both pension plans are 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 2020 used to calculate the benefit obligation is 5.0 percent for medical and 6.0 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5.0 percent for both medical and prescription drugs for the FPU Medical Plan.

Estimated Future Benefit Payments

In 2021, we expect to contribute $0.3 million and $2.1 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, 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 2021.

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

	Chesapeake Pension Plan(1)		FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2021	$	384	$	3,409	$	151	$	68	$	67
2022	$	99	$	3,493	$	150	$	66	$	67
2023	$	981	$	3,559	$	148	$	61	$	66
2024	$	106	$	3,601	$	146	$	58	$	67
2025	$	1,007	$	3,680	$	158	$	55	$	67
Years 2026 through 2030	$	1,193	$	18,627	$	735	$	222	$	317

(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, 2020, 2019 and 2018, 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, $5.7 million, and $5.5 million for the years ended December 31, 2020, 2019 and 2018, respectively. As of December 31, 2020, there were 813,230 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 designated by the Compensation Committee, 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 $10.8 million and $9.2 million at December 31, 2020 and 2019, 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 $5.7 million and $4.5 million at December 31, 2020 and 2019, 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, 2020

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 415,412 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, 2020, 2019 and 2018:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Awards to non-employee directors	$	733	$	620	$	539
Awards to key employees	4,096		3,659		2,871
Total compensation expense	4,829		4,279		3,410
Less: tax benefit	(1,254)		(1,117)		(934)
Share-based compensation amounts included in net income	$	3,575	$	3,162	$	2,476

Stock Options

There were no stock options outstanding or issued during the years 2018 through 2020.

Non-employee Directors

Shares granted to non-employee directors are issued in advance of these directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2019, each of our non-employee directors received an annual retainer of 751 shares of common stock under the SICP for board service through the 2020 Annual Meeting of Stockholders; accordingly, 6,759 shares, with a weighted average fair value of $93.14 per share, were issued and vested in 2019. In May 2020, each of our non-employee directors received an annual retainer of 887 shares of common stock under the SICP for service as a director 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.

In January 2020, a newly appointed member of our Board of Directors received a pro-rated retainer of 254 shares of common stock under the SICP to serve as a non-employee director through the 2020 Annual Meeting of Stockholders. The shares awarded to the non-employee director immediately vested upon issuance in January 2020, had a weighted average fair value of $95.83 per share, and the expense was recognized over the remaining service period ending on the date of the 2020 Annual Meeting of Stockholders

At December 31, 2020, 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 on the date of 2021 Annual Meeting of Stockholders.

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.

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 key employees:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2018	131,741	$	67.24
Granted (1)	88,048	92.74
Vested	(25,831)	67.08
Expired	(15,086)	69.28
Forfeited (2)	(21,055)	71.67
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

(1) Includes 43,032 shares that were granted to certain key employees in December 2019 associated with their promotion.

(2) In conjunction with the retirement of two key employees during 2019, these shares were forfeited for the remainder of the service periods associated with awards granted during their employment with the Company.

The intrinsic value of these awards was $20.2 million, $15.1 million and $10.7 million in 2020, 2019 and 2018, respectively. At December 31, 2020, there was $3.9 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2022.

In 2020, 2019 and 2018, 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,
	2020		2019		2018
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,319		7,635		16,918
Amounts remitted to tax authorities to satisfy obligations	$	977	$	692	$	1,210

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Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Rates and Other Regulatory Activities

RATES AND OTHER REGULATORY ACTIVITIES

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

Delaware

CGS: In August 2019, we filed with the Delaware PSC an application seeking an order that will establish the regulatory accounting treatment and valuation methodology for the acquisition of propane CGS owned by our affiliate, Sharp and the conversion of the CGS to natural gas service. We proposed to acquire each CGS one at a time and to pay replacement cost for each CGS system. In addition, we requested authorization to pay for and capitalize the CGS residents’ behind-the-meter conversion costs. Our existing natural gas customers will be protected against subsidizing the acquisitions and conversions of the CGS systems because we will complete only those systems that meet our economic test. The application was reviewed by the Delaware PSC, who approved and issued a final order in June 2020.

Maryland

Approval of the Elkton Gas Acquisition: In December 2019, we entered into an agreement with South Jersey Industries, Inc. to acquire its subsidiary, Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Elkton Gas territory is contiguous to our franchised service territory in Cecil County, Maryland. On June 29, 2020, the Maryland PSC issued a final order approving the settlement agreement, therefore, enabling the transaction to move forward. In July 2020, the transaction closed and we acquired Elkton Gas as our wholly-owned subsidiary.

Application for Authority to Exercise a Franchise: In March 2020, we filed with the Maryland PSC an application seeking approval to exercise a franchise granted to us by the Board of County Commissioners of Somerset County, Maryland in December 2019. The application was approved in June 2020.

Florida

Hurricane Michael: In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane 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, after exerting extraordinary hurricane restoration efforts, restored service to those customers who were able to accept it. 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. Additionally, in 2019, amounts undergoing review by the Florida PSC for regulatory asset treatment were recorded as receivables and other deferred charges.

In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as regulatory assets for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested to 10 years, and included costs related to Hurricane Dorian of approximately $1.2 million in this filing.

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 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 and a regulatory asset for cost of removal and undepreciated plant. The new base rates and storm surcharge were effective on November 1, 2020.

Electric Depreciation Study: 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.

West Palm Beach Expansion Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with FPU. Peninsula Pipeline will construct 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 will provide transportation service to FPU, increasing reliability, system pressure as well as introducing diversity in fuel source for natural gas to serve the increased demand in these areas. The petition was approved by the Florida PSC at the August 6, 2019 Agenda. Interim services began in the fourth quarter of 2019. We expect to complete the remainder of the project in phases through the second quarter of 2021.

Callahan Pipeline, Nassau County: In the second quarter of 2020, Peninsula Pipeline and Seacoast Gas Transmission completed construction of a jointly owned 26-mile, 16-inch steel pipeline that interconnects to the Cypress Pipeline interstate system in western Nassau County in order to serve growing demand in both Nassau and Duval counties, Florida. The Callahan pipeline terminates into the existing Peninsula Pipeline, which serves Amelia Island and the Peoples Gas distribution system. The Callahan Pipeline has enhanced FPU’s ability to expand service into Nassau County and has enabled Peoples Gas to enhance its system pressure and the reliability of its service in Duval County.

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, which was applied for in September 2018 by Eastern Shore, approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include 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. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021.

Capital Cost Surcharge: In December 2019, the FERC approved Eastern Shore’s proposed 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. Eastern Shore expects to recover $0.5 million in capital cost surcharges on an annual basis. As government mandated relocations continue resulting in Eastern Shore undertaking capital expenditures, we will continue to utilize the surcharge to seek recovery of these costs in accordance with the settlement from Eastern Shore’s last general rate case.

Renewable Natural Gas Tariff: In October 2019, Eastern Shore filed an application with the FERC to include renewable natural gas (biogas) utilization and standards in its tariff. Eastern Shore had proposed changes to its gas quality specifications that would enable it to accommodate renewable natural gas at various receipt points on its system. Changes to the gas quality specifications would ensure interchangeability of renewable natural gas with the natural gas currently delivered to Eastern Shore. The tariffs became effective in November 2019.

Ohio

Aspire Energy Express: In October 2020, the Public Utilities Commission of Ohio approved the request by Aspire Energy Express for authority to operate as an intrastate pipeline company in Ohio and also approved the submitted tariff. Aspire Energy Express will utilize the pipeline to provide natural gas transportation service in Ohio, including delivery to the Guernsey Power Station and other potential customers elsewhere in Ohio. Aspire Energy Express has entered into agreements with the Guernsey Power Station to construct the pipeline and provide natural gas transportation service to the facility, which the Public Utilities Commission of Ohio approved in November 2020. Aspire Energy Express intends to own and operate the proposed intrastate pipeline facilities that will interconnect with the Rockies Express Pipeline and other potential points of receipt. The pipeline facilities that will be initially constructed will provide firm transportation service to the Guernsey Power Station. Aspire Energy Express will be subject to ongoing jurisdiction and supervision of the Public Utilities Commission of Ohio with respect to the gas pipeline safety standards and requirements.

COVID-19 Impact

We are monitoring the global outbreak of COVID-19 and taking steps to mitigate the potential risks posed by its spread. We provide an “essential service” to our customers, which means that it is paramount that we keep our employees who operate our business safe and informed. We have taken and are continuously monitoring and updating precautions and protocols to ensure the safety of our employees and customers. As an “essential business” we are allowed to continue operational activity and construction projects with appropriate safety precautions, personal protective equipment and social distancing restrictions in

place. We have taken steps to assure our customers that disconnections for non-payment will be temporarily suspended. We are also working with our suppliers to understand the potential impacts to our supply chain; if material negative impacts are identified, we will work to mitigate them. This is a rapidly evolving situation, and could lead to extended disruption of economic activity in our markets. We will continue to monitor developments affecting our employees, customers, suppliers and shareholders, and will take additional precautions as warranted to comply with the CDC, state and local requirements and recommendations to protect our employees, customers and the communities we serve.

As a result of these measures, we are incurring costs associated with crisis management and the pandemic response including restrictions put in place by the state PSCs on utility disconnects for non-payment, technology costs incurred to expand work from home capabilities, additional sanitation and cleaning costs and costs of acquiring personal protective equipment as well as other expenses.

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 this period, 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.

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 creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs.

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish regulatory asset to record incremental expenses incurred due to COVID-19. This regulatory asset will allow us to seek recovery of these costs in our next base rate proceeding. On November 16, 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset, contending that the order should be a reversed or modified and to request a hearing on the protest. At this time, no hearing date has been established.

In the fourth quarter of 2020, we established regulatory assets based on the net incremental expense resulting from the pandemic for our natural gas distribution and electric businesses as currently authorized by the Delaware, Maryland and Florida PSCs.

The table below highlights the impact to our various regulated businesses as a result of the TCJA:

Summary TCJA Table

	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates were adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,728	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates were adjusted in March 2019.
Maryland Division (Maryland PSC)	$3,970	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates were adjusted in May 2018.
Sandpiper Energy (Maryland PSC)	$3,713	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018. Customer rates were adjusted in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,257	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$309	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Utilities Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit is provided to customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.
Elkton Gas (Maryland PSC)	$1,124	PSC approved amortization of ADIT in March 2018.	Previous owner implemented one-time bill credit (totaling less than $0.1 million) in May 2020. Customer rates were adjusted in April 2020.

Regulatory Assets and Liabilities

At December 31, 2020 and 2019, our regulated utility operations had 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,
	2020		2019
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	2,078	$	5,144
Under-recovered GRIP revenue (2)	278		—
Deferred postretirement benefits (3)	17,716		16,311
Deferred conversion and development costs (1)	23,054		20,881
Environmental regulatory assets and expenditures (4)	1,743		2,241
Acquisition adjustment (5)	28,755		30,329
Loss on reacquired debt (6)	795		869
Deferred costs associated with COVID-19 (7)	1,925		—
Deferred storm costs (8)	44,320		—
Other	3,928		2,776
Total Regulatory Assets	$	124,592	$	78,551
Regulatory Liabilities
Self-insurance (9)	$	533	$	873
Over-recovered purchased fuel and conservation cost recovery (1)	4,422		2,724
Over-recovered GRIP revenue (2)	338		2,668
Storm reserve (9)	2,673		1,437
Accrued asset removal cost (10)	45,315		36,767
Deferred income taxes due to rate change (11)	90,845		89,191
Interest related to storm recovery (8)	3,353		—
Other	1,541		75
Total Regulatory Liabilities	$	149,020	$	133,735

(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 de-risking of the Chesapeake Pension Plan pursuant to an order from the FERC that allowed us to defer Eastern Shore's 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, 2020

Text Block [Abstract]

Environmental Commitments and Contingencies

ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES

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

MGP Sites

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

As of December 31, 2020 and 2019, we had approximately $5.9 million and $8.0 million, respectively, in environmental liabilities, related to FPU’s 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, 2020 and 2019, we have recovered approximately $12.4 million and $11.9 million, respectively, leaving approximately $1.6 million and $2.1 million, respectively, in regulatory assets for future recovery 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.

The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:

MGP Site (Jurisdiction)	Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
West Palm Beach (Florida)	Remediation actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remediation actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2021.	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.
Sanford (Florida)	In March 2018, the United States Environmental Protection Agency ("EPA") approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be immaterial.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $0.4 million.
Seaford (Delaware)	Conducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction is being implemented, in accordance with the DNREC-approved Work Plan.	Between $0.2 million and $0.5 million.

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

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 on March 31, 2023.

In May 2019, FPU natural gas distribution operations and Eight Flags entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. Short-term agreements were entered for a term beginning July 2019 through October 2020 with long-term agreements executed for a 10-year term that commenced in November 2020.

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, 2020, 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	2021		2022-2023		2024-2025		Beyond 2025		Total
(in thousands)
Purchase Obligations	$	69,459	$	81,841	$	69,420	$	201,504	$	422,224

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, 2020 was $20.0 million. The aggregate amount guaranteed at December 31, 2020 was approximately $5.7 million with the guarantees expiring on various dates through September 2021.

As of December 31, 2020, we have issued letters of credit totaling approximately $4.8 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 and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. There have been no draws on these letters of credit as of December 31, 2020. 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, 2020

Text Block [Abstract]

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	$	1.24
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	$	1.28
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.64	$	0.56	$	1.24
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	$	1.28
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, 2020

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, 2020 and 2019 is provided in the following table:

	As of December 31,
(in thousands)	2020		2019
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	782,329	$	705,095
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	667,538		608,727
Electric distribution	127,710		127,651
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	151,258		141,945
Natural gas transmission and supply – Ohio	87,962		73,658
Electricity and steam generation	36,521		35,436
Mobile CNG and pipeline solutions	24,905		14,014
Other	30,769		40,006
Total property, plant and equipment	1,908,992		1,746,532
Less: Accumulated depreciation and amortization	(368,743)		(336,876)
Plus: Construction work in progress	60,929		54,141
Net property, plant and equipment	$	1,601,178	$	1,463,797

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, 2020 and 2019, the non-refundable contributions totaled $2.9 million and $2.1 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, 2020, 2019 and 2018 AFUDC totaled $0.7 million, $0.7 million and $1.9 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 $26.4 million of assets at December 31, 2020, 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 $0.3 million at December 31, 2020.

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2020 and 2019, 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 $1.7 million and $1.5 million at December 31, 2020 and 2019, 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, 2020, 2019 and 2018:

	2020	2019	2018
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.6%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.6%	2.7%
Natural gas transmission – Florida	2.3%	2.4%	2.3%
Electric distribution	2.9%	3.4%	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, 2020, 2019 and 2018, we reported $9.6 million, $8.8 million and $8.5 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

Cost of Sales

Cost of sales includes 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 cost of sales.

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, impacts from pandemics and general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.

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, 2020, 2019 or 2018.

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, 2020, 2019 and 2018 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 of each of our plans 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

Recently Adopted Accounting Standards

Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019 is provided in the following table:

	As of December 31,
(in thousands)	2020		2019
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	782,329	$	705,095
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	667,538		608,727
Electric distribution	127,710		127,651
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	151,258		141,945
Natural gas transmission and supply – Ohio	87,962		73,658
Electricity and steam generation	36,521		35,436
Mobile CNG and pipeline solutions	24,905		14,014
Other	30,769		40,006
Total property, plant and equipment	1,908,992		1,746,532
Less: Accumulated depreciation and amortization	(368,743)		(336,876)
Plus: Construction work in progress	60,929		54,141
Net property, plant and equipment	$	1,601,178	$	1,463,797

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, 2020, 2019 and 2018:

	2020	2019	2018
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.5%	2.6%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.6%	2.7%
Natural gas transmission – Florida	2.3%	2.4%	2.3%
Electric distribution	2.9%	3.4%	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, 2020

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 years ended December 31:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	70,642	$	61,100	$	56,968
Income/(Loss) from Discontinued Operations	856		4,053		(388)
Net Income	$	71,498	$	65,153	$	56,580
Weighted average shares outstanding	16,711,579		16,398,443		16,369,616
Earnings Per Share from Continuing Operations	$	4.23	$	3.73	$	3.48
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Basic Earnings Per Share	$	4.28	$	3.97	$	3.46
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,711,579		16,398,443		16,369,616
Effect of dilutive securities — Share-based compensation	59,156		50,043		50,254
Adjusted denominator — Diluted	16,770,735		16,448,486		16,419,870
Earnings Per Share from Continuing Operations	$	4.21	$	3.72	$	3.47
Earnings/(Loss) Per Share from Discontinued Operations	0.05		0.24		(0.02)
Diluted Earnings Per Share	$	4.26	$	3.96	$	3.45

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Acquisitions Divestitures (Tables)

12 Months Ended

Dec. 31, 2020

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

These acquisitions generated the following operating revenues and income:

	For the Year Ended				For the Year Ended
	December 31, 2020				December 31, 2019
	Operating Revenues		Operating Income		Operating Revenues		Operating Income
(in thousands)
Western Natural Gas	$	555	$	90	$	—	$	—
Elkton Gas	$	2,399	$	418	$	—	$	—
Boulden	$	5,717	$	1,854	$	550	$	239

Disposal Groups, Including Discontinued Operations [Table Text Block]

A summary of discontinued operations presented in the consolidated statements of income includes the following:

	For the Year Ended December 31,
(in thousands)	2020		2019		2018
Operating revenues(1)	$	26	$	161,289	$	258,713
Cost of sales(1)	—		157,646		252,111
Other operating expenses	230		5,221		6,825
Operating loss	(204)		(1,578)		(223)
Interest and other income (expense)	1,013		(297)		(294)
Earnings / (Loss) from Discontinued Operations before income taxes	809		(1,875)		(517)
Gain on sale of Discontinued Operations	200		7,344		—
Income tax (benefit) / expense	153		1,416		(129)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	856	$	4,053	$	(388)

(1) Included in operating revenues and cost of sales for the years ended December 31, 2019 and 2018, is $19.8 million, and $31.5 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity which continued with the buyers after the disposition of the assets of PESCO.

Discontinued Operations [Member]

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

Discontinued Operations Supplemental Cash Flows Schedule [Table Text Block]

The following table summarizes significant statements of cash flows data related to the discontinued operations of PESCO:

	For the Year Ended December 31,
(in thousands)	2019		2018
Depreciation and amortization	$	477	$	582
Property, plant and equipment expenditures	$	—	$	115
Deferred income taxes	$	(125)	$	1,088
Realized / (loss) gain on commodity contracts	$	(2,161)	$	5,002

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Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2020

Dec. 31, 2019

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

for the years ended December 31, 2020, 2019 and 2018:

	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 year 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

	For the year ended December 31, 2018
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	70,338	$	—	$	—	$	70,338
Florida natural gas division	25,341		—		—		25,341
FPU electric distribution	79,803		—		—		79,803
FPU natural gas distribution	81,118		—		—		81,118
Maryland natural gas division	24,172		—		—		24,172
Sandpiper natural gas/propane operations	22,088		—		—		22,088
Total energy distribution	302,860		—		—		302,860
Energy transmission
Aspire Energy	—		35,407		—		35,407
Aspire Energy Express	—		—		—		—
Eastern Shore	64,248		—		—		64,248
Peninsula Pipeline	11,927		—		—		11,927
Total energy transmission	76,175		35,407		—		111,582
Energy generation
Eight Flags	—		17,302		—		17,302
Propane operations
Propane delivery operations	—		125,560		—		125,560
Energy delivery services
Marlin Gas Services	—		121		—		121
Other and eliminations
Eliminations	(33,754)		(16,485)		(17,522)		(67,761)
Other	—		—		652		652
Total other and eliminations	(33,754)		(16,485)		(16,870)		(67,109)
Total operating revenues (1)	$	345,281	$	161,905	$	(16,870)	$	490,316

(1) Total operating revenues for the year ended December 31, 2018, include other revenue (revenues from sources other than contracts with customers) of $0.2 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, 2020 and 2019 were as follows:

	Trade Receivables		Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2019	$	47,430	$	3,465	$	589
Balance at 12/31/2020	55,600		4,816		644
Increase (decrease)	$	8,170	$	1,351	$	55

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Revenue for these businesses for the remaining performance obligations at December 31, 2020 are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026 and thereafter
Eastern Shore and Peninsula Pipeline	$	34,978	$	27,155	$	21,748	$	19,587	$	18,736	$	174,774
Natural gas distribution operations	4,351		5,394		4,937		4,705		4,172		32,996
FPU electric distribution	566		566		566		566		275		825
Total revenue contracts with remaining performance obligations	$	39,895	$	33,115	$	27,251	$	24,858	$	23,183	$	208,595

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Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2020

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,
	2020		2019		2018
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	350,853	$	340,857	$	343,313
Unregulated Energy	137,345		138,748		147,003
Total operating revenues, unaffiliated customers	$	488,198	$	479,605	$	490,316
Intersegment Revenues (1)
Regulated Energy	$	1,893	$	2,149	$	1,968
Unregulated Energy	15,181		15,403		14,902
Other businesses	528		529		652
Total intersegment revenues	$	17,602	$	18,081	$	17,522
Operating Income
Regulated Energy	$	92,124	$	86,584	$	79,215
Unregulated Energy	20,664		19,938		17,125
Other businesses and eliminations	(65)		(237)		(1,496)
Operating Income	112,723		106,285		94,844
Other income (expense), net	3,222		(1,847)		(607)
Interest charges	21,765		22,224		16,146
Income from Continuing Operations before Income Taxes	94,180		82,214		78,091
Income Taxes on Continuing Operations	23,538		21,114		21,123
Income from Continuing Operations	70,642		61,100		56,968
Income (loss) from Discontinued Operations, Net of Tax	686		(1,349)		(388)
Gain on sale of Discontinued Operations, Net of tax	170		5,402		—
Net Income	$	71,498	$	65,153	$	56,580
Depreciation and Amortization
Regulated Energy	$	46,079	$	35,227	$	31,876
Unregulated Energy	11,988		10,130		8,263
Other businesses and eliminations	50		67		81
Total depreciation and amortization	$	58,117	$	45,424	$	40,220
Capital Expenditures
Regulated Energy	$	147,100	130,604		$	235,912
Unregulated Energy	46,295		60,034		38,585
Other businesses	2,480		8,348		8,364
Total capital expenditures	$	195,875	$	198,986	$	282,861

 

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

	As of December 31,
	2020		2019
Identifiable Assets
Regulated Energy segment	$	1,547,619	$	1,434,066
Unregulated Energy segment	347,665		296,810
Other businesses and eliminations	37,203		52,322
Total identifiable assets	$	1,932,487	$	1,783,198

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Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2020, 2019 and 2018 were as follows:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Cash paid for interest	$	22,884	$	23,856	$	16,741
Cash (received) paid for income taxes, net of refunds	$	(8,135)	$	3,221	$	477

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2020, 2019, and 2018 were as follows: 

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	23,625	$	13,470	$	39,402
Common stock issued for the Retirement Savings Plan	$	1,605	$	—	$	—
Common stock issued under the SICP	$	1,971	$	1,691	$	2,006
Capital lease obligation	$	—	$	—	$	1,310

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of December 31, 2020, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	17.6	Cash flows hedges	May 2023
Sharp	Propane (gallons)	0.4	Fair value hedges	February 2021

Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]

(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
Sharp	Other Current Assets	$	—	$	2,317
Sharp	Other Current Liabilities	$	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, 2020 and 2019 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	3,255		—
Total Derivative Assets		$	3,269	$	—

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2020		December 31, 2019
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	64		1,844
Interest rate swap agreements	Derivative liabilities, at fair value	40		—
Total Derivative Liabilities		$	127	$	1,844

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)		2020		2019		2018
Derivatives not designated as hedging instruments
Propane swap agreements	Cost of sales	$	—	$	—	$	(13)
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	(12)		—		—
Put/Call option	Propane inventory	34		—		—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	2,428		1,520		(647)
Propane swap agreements	Other comprehensive income (loss)	5,035		(253)		(2,773)
Interest rate swap agreements	Interest expense	60		—		—
Interest rate swap agreements	Other comprehensive income (loss)	(40)		—		—
Natural gas swap contracts	Other comprehensive income (loss)	—		(63)		200
Natural gas futures contracts	Other comprehensive income (loss)	—		(294)		532
Total		$	7,505	$	910	$	(2,701)

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020 and 2019, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2019	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	$	27	$	27	$	—	$	—
Investments—guaranteed income fund	803		—		—		803
Investments—mutual funds and other	8,399		8,399		—		—
Total investments	9,229		8,426		—		803
Derivative assets	—		—		—		—
Total assets	$	9,229	$	8,426	$	—	$	803
Liabilities:
Derivative liabilities	$	1,844	$	—	$	1,844	$	—

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, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Beginning Balance	$	803	$	686
Purchases and adjustments	261		131
Transfers/disbursements	1,065		(29)
Investment income	27		15
Ending Balance	$	2,156	$	803

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Investments (Tables)

12 Months Ended

Dec. 31, 2020

Investments [Abstract]

Investments schedule [Table Text Block]

	As of December 31,
(in thousands)	2020		2019
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	10,755	$	9,202
Investments in equity securities	21		27
Total	$	10,776	$	9,229

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Schedule of Carrying Value of Goodwill

The carrying value of goodwill from continuing operations as of December 31, 2020 and 2019 was as follows:

(in thousands)	Regulated Energy		Unregulated Energy		Total Goodwill
Balance at December 31, 2019	$	3,353	$	29,315	$	32,668
Additions (1)	4,264		1,799		6,063
Balance at December 31, 2020	$	7,617	$	31,114	$	38,731

(1)Includes goodwill from the purchase of operating assets of Elkton Gas in the third quarter of 2020 and Western Natural Gas in October 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, 2020 and 2019 are as follows:

	As of December 31,
	2020				2019
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	10,680	$	4,269	$	9,391	$	3,463
Non-Compete agreements (1)	2,375		768		2,252		451
Patents	452		236		452		118
Other	270		212		270		204
Total	$	13,777	$	5,485	$	12,365	$	4,236

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2020

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

The following tables provide: (a) the components of income tax expense in 2020, 2019, and 2018; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2020, 2019, and 2018 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2020 and 2019.

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Current Income Tax Expense
Federal	$	(2,777)	$	(2,252)	$	(361)
State	2,162		(491)		617
Other	(47)		(47)		(47)
Total current income tax expense (benefit)	(662)		(2,790)		209
Deferred Income Tax Expense (1)
Property, plant and equipment	23,224		25,907		19,178
Deferred gas costs	(714)		79		(1,435)
Pensions and other employee benefits	(75)		(454)		454
FPU merger-related premium cost and deferred gain	156		(278)		(528)
Net operating loss carryforwards	5,107		(3,772)		(250)
Other	(3,498)		2,422		3,495
Total deferred income tax expense	24,200		23,904		20,914
Income Tax Expense from Continuing Operations	23,538		21,114		21,123
Income Tax Expense (benefit) from Discontinued Operations	153		1,416		(129)
Total Income Tax	$	23,691	$	22,530	$	20,994

(1) Includes $4.9 million, $4.7 million, and $3.5 million of deferred state income taxes for the years 2020, 2019 and 2018, respectively.

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates

	For the Year Ended December 31,
	2020			2019			2018
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	19,778		$	17,264		$	16,400
State income taxes, net of federal benefit	5,051			5,093			4,071
ESOP dividend deduction	(218)			(173)			(158)
CARES Act Tax Benefit	(1,841)			—			—
Other	768			(1,070)			810
Total Income Tax Expense for Continuing Operations	$	23,538		$	21,114		$	21,123
Effective Income Tax Rate for Continuing Operations	24.99		%	25.65		%	27.13		%

(1) Federal income taxes were calculated at 21 percent for 2020, 2019, and 2018.

Schedule of Accumulated Deferred Income Tax Assets and Liabilities

	As of December 31,
	2020		2019
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	199,287	$	173,466
Acquisition adjustment	6,618		6,969
Loss on reacquired debt	201		220
Deferred gas costs	509		1,223
Natural gas conversion costs	5,379		4,956
Storm reserve liability	7,073		10,316
Other	5,587		1,456
Total deferred income tax liabilities	224,654		198,606
Deferred income tax assets:
Pension and other employee benefits	4,636		3,818
Environmental costs	1,064		1,486
Net operating loss carryforwards	1,587		5,523
Self-insurance	—		146
Storm reserve liability	409		96
Accrued Expenses	6,153		2,064
Other	5,417		4,817
Total deferred income tax assets	19,266		17,950
Deferred Income Taxes Per Consolidated Balance Sheets	$	205,388	$	180,656

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2020

Text Block [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2020		2019
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	—	$	7,990
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	—		2,000
5.93% note, due October 31, 2023	9,000		12,000
5.68% note, due June 30, 2026	17,400		20,300
6.43% note, due May 2, 2028	5,600		6,300
3.73% note, due December 16, 2028	16,000		18,000
3.88% note, due May 15, 2029	45,000		50,000
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		—
2.96% note, due August 15, 2035	40,000		—
Term Note due February 28, 2020	—		30,000
Less: debt issuance costs	(901)		(822)
Total long-term debt	522,099		485,768
Less: current maturities	(13,600)		(45,600)
Total long-term debt, net of current maturities	$	508,499	$	440,168

Schedule of Maturities of Long-term Debt [Table Text Block]

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

Year	2021		2022		2023		2024		2025		Thereafter		Total
(in thousands)
Payments	$	13,600	$	17,100	$	20,600	$	17,600	$	24,600	$	429,500	$	523,000

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, 2020:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued		Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (2)	150,000		—		—		150,000
NYL Shelf Agreement (3)	150,000		(140,000)		—		10,000
Total	$	670,000	$	(360,000)	$	—	$	310,000

(1) In April 2020, we amended the Prudential Shelf Agreement to increase the available borrowing capacity by $150.0 million. The Shelf Agreement expires in April 2023. In July 2020, we issued $50 million of Prudential Shelf Notes at the rate of 3.00 percent per annum.

(2) In May 2020, we amended an agreement with MetLife to provide a new $150 million MetLife Shelf Agreement for a three-year term ending May 2023.

(3) In August 2020 we issued $40 million of NYL Shelf Notes at the rate of 2.96 percent per annum. The NYL Shelf Agreement expires in November 2021.

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2020

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	2020		2019
Operating lease cost (1)	Operations expense	$	2,029	$	2,577
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	—		650
Interest on lease liabilities	Interest expense	—		5
Net lease cost		$	2,029	$	3,232

(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, 2020 and 2019:

(in thousands)	Balance sheet classification	December 31, 2020		December 31, 2019
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,194	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,747	$	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,872		9,896
Total lease liabilities		$	11,619	$	11,601

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, 2020 and 2019:

	December 31, 2020		December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.70		8.88
Weighted-average discount rate
Operating leases	3.8	%	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, 2020 and 2019:

	Year Ended December 31,
(in thousands)	2020		2019
Operating cash flows from operating leases	$	1,956	$	2,230
Operating cash flows from finance leases	$	—	$	5
Financing cash flows from finance leases	$	—	$	650

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, 2020 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2021	$	2,027
2022	1,984
2023	1,923
2024	1,657
2025	1,395
Thereafter	4,419
Total lease payments	13,405
Less: Interest	1,786
Present value of lease liabilities	$	11,619

(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, 2020

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table presents the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2020 and 2019. 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, 2018	$	(5,928)	$	(785)	$	—	$	(6,713)
Other comprehensive income (loss) before reclassifications	(872)		2,161		—		1,289
Amounts reclassified from accumulated other comprehensive income (loss)	1,867		(2,595)		—		(728)
Net current-period other comprehensive income (loss)	995		(434)		—		561
Prior-year reclassification	—		(115)		—		(115)
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)

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, 2020, 2019 and 2018. 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)	2020		2019		2018
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77	$	77	$	77
Net gain (1)	(592)		(2,600)		(579)
Total before income taxes	(515)		(2,523)		(502)
Income tax benefit (4)	150		656		63
Net of tax	$	(365)	$	(1,867)	$	(439)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	2,428	$	1,520	$	(647)
Natural gas swaps (2)(3)	—		7		197
Natural gas futures (2)(3)	—		2,096		(2,010)
Total before income taxes	2,428		3,623		(2,460)
Income tax (expense) benefit (4)	(671)		(1,028)		701
Net of tax	$	1,757	$	2,595	$	(1,759)
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	60	$	—	$	—
Total before income taxes	60		—		—
Income tax expense	(16)		—		—
Net of tax	$	44	$	—	$	—
Total reclassifications for the period	$	1,436	$	728	$	(2,198)

(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, 2020

Schedule of Assets by Investment Type

The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2020, 2019 and 2018:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2020		2019		2018		2020		2019		2018
Asset Category
Equity securities	—	%	—	%	49	%	54	%	53	%	50	%
Debt securities	96	%	92	%	41	%	37	%	37	%	41	%
Other	4	%	8	%	10	%	9	%	10	%	9	%
Total	100	%	100	%	100	%	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 plans’ 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	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Cash	0	%	5	%

Summary of Pension Plan Assets

At December 31, 2020 and 2019, 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, 2020								At December 31, 2019
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)	$	3,615	$	—	$	—	$	3,615	$	3,553	$	—	$	—	$	3,553
U.S. Mid Cap (1)	1,672		—		—		1,672		1,604		—		—		1,604
U.S. Small Cap (1)	891		—		—		891		726		—		—		726
International (2)	11,307		—		—		11,307		9,855		—		—		9,855
Alternative Strategies (3)	5,586		—		—		5,586		4,739		—		—		4,739
	23,071		—		—		23,071		20,477		—		—		20,477
Mutual Funds - Debt securities
Fixed income (4)	21,563		—		—		21,563		19,220		—		—		19,220
High Yield (4)	2,606		—		—		2,606		2,476		—		—		2,476
	24,169		—		—		24,169		21,696		—		—		21,696
Mutual Funds - Other
Commodities (5)	2,246		—		—		2,246		1,708		—		—		1,708
Real Estate (6)	1,954		—		—		1,954		2,288		—		—		2,288
Guaranteed deposit (7)	—		—		1,019		1,019		—		—		1,147		1,147
	4,200		—		1,019		5,219		3,996		—		1,147		5,143
Total Pension Plan Assets in fair value hierarchy	$	51,440	$	—	$	1,019	52,459		$	46,169	$	—	$	1,147	47,316
Investments measured at net asset value (8)							8,116								7,017
Total Pension Plan Assets							$	60,575							$	54,333

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, 2020 and 2019:

	For the Year Ended December 31,
	2020		2019
(in thousands)
Balance, beginning of year	$	1,147	$	627
Purchases	3,190		2,274
Transfers in	921		3,090
Disbursements	(4,290)		(4,907)
Investment income	51		63
Balance, end of year	$	1,019	$	1,147

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, 2020:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
Prior service cost (credit)	$	—	$	—	$	—	$	(370)	$	—	$	(370)
Net loss (gain)	2,033		21,242		699		546		(194)		24,326
Total	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,033	$	4,036	$	699	$	176	$	(37)	$	6,907
Post-merger regulatory asset	—		17,206		—		—		(157)		17,049
Total unrecognized cost	$	2,033	$	21,242	$	699	$	176	$	(194)	$	23,956

(1) The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2020 is net of income tax benefits of $1.8 million.

Schedule of Estimated Future Benefit Payments

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

	Chesapeake Pension Plan(1)		FPU Pension Plan(1)		Chesapeake SERP(2)		Chesapeake Postretirement Plan(2)		FPU Medical Plan(2)
(in thousands)
2021	$	384	$	3,409	$	151	$	68	$	67
2022	$	99	$	3,493	$	150	$	66	$	67
2023	$	981	$	3,559	$	148	$	61	$	66
2024	$	106	$	3,601	$	146	$	58	$	67
2025	$	1,007	$	3,680	$	158	$	55	$	67
Years 2026 through 2030	$	1,193	$	18,627	$	735	$	222	$	317

(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, 2020 and 2019 and the net periodic cost for the years ended December 31, 2020, 2019 and 2018 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2020			2019			2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	6,214		$	10,712		$	65,304		$	59,377		$	2,157		$	2,285
Interest cost	176			375			2,085			2,452			63			74
Actuarial loss	450			1,443			6,069			6,508			144			159
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Benefit obligation — end of year	6,146			6,214			70,366			65,304			2,212			2,157
Change in plan assets:
Fair value of plan assets — beginning of year	4,630			8,649			49,703			43,601			—			—
Actual return on plan assets	369			1,180			6,581			7,978			—			—
Employer contributions	304			1,117			2,774			1,157			152			361
Effect of settlement	(612)			(5,833)			—			—			—			—
Benefits paid	(82)			(483)			(3,092)			(3,033)			(152)			(361)
Fair value of plan assets — end of year	4,609			4,630			55,966			49,703			—			—
Reconciliation:
Funded status	(1,537)			(1,584)			(14,400)			(15,601)			(2,212)			(2,157)
Accrued pension cost	$	(1,537)		$	(1,584)		$	(14,400)		$	(15,601)		$	(2,212)		$	(2,157)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%	2.25		%	3.00		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.50		%	—		%	—		%

Component of Net Periodic Pension Cost (Benefit)

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2020			2019 (1)			2018			2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic pension cost:
Interest cost	$	176		$	375		$	384		$	2,085		$	2,452		$	2,339		$	63		$	74		$	83
Expected return on assets	(157)			(487)			(542)			(2,967)			(2,770)			(3,091)			—			—			—
Amortization of actuarial loss	243			391			343			552			505			404			20			85			101
Settlement expense	203			1,982			—			—			—			—			—			58			—
Net periodic pension cost	465			2,261			185			(330)			187			(348)			83			217			184
Amortization of pre-merger regulatory asset	—			—			—			—			543			761			—			—			—
Total periodic cost	$	465		$	2,261		$	185		$	(330)		$	730		$	413		$	83		$	217		$	184
Assumptions:
Discount rate	3.00		%	3.00		%	3.50		%	3.25		%	4.25		%	3.75		%	3.00		%	4.00		%	3.50		%
Expected return on plan assets	3.50		%	6.00		%	6.00		%	6.00		%	6.50		%	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, 2020 and 2019:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2020			2019			2020			2019
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,100		$	1,002		$	1,224		$	1,187
Interest cost	26			39			30			48
Plan participants contributions	166			149			37			38
Actuarial loss (gain)	(34)			73			(181)			47
Benefits paid	(225)			(163)			(101)			(96)
Benefit obligation — end of year	1,033			1,100			1,009			1,224
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions	59			14			64			58
Plan participants contributions	166			149			37			38
Benefits paid	(225)			(163)			(101)			(96)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,033)			(1,100)			(1,009)			(1,224)
Accrued postretirement cost	$	(1,033)		$	(1,100)		$	(1,009)		$	(1,224)
Assumptions:
Discount rate	2.25		%	3.00		%	2.50		%	3.25		%

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for 2020, 2019, and 2018 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2020			2019			2018			2020			2019			2018
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	26		$	39		$	38		$	30		$	48		$	47
Amortization of actuarial loss	24			46			58			(19)			—			—
Amortization of prior service cost (credit)	(77)			(77)			(77)			—			—			—
Net periodic cost	(27)			8			19			11			48			47
Amortization of pre-merger regulatory asset	—			—			—			6			8			8
Total periodic cost	$	(27)		$	8		$	19		$	17		$	56		$	55
Assumptions
Discount rate	3.00		%	4.00		%	3.50		%	3.25		%	4.25		%	3.75		%

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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2020

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, 2020, 2019 and 2018:

	For the Year Ended December 31,
	2020		2019		2018
(in thousands)
Awards to non-employee directors	$	733	$	620	$	539
Awards to key employees	4,096		3,659		2,871
Total compensation expense	4,829		4,279		3,410
Less: tax benefit	(1,254)		(1,117)		(934)
Share-based compensation amounts included in net income	$	3,575	$	3,162	$	2,476

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,
	2020		2019		2018
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,319		7,635		16,918
Amounts remitted to tax authorities to satisfy obligations	$	977	$	692	$	1,210

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 key employees:

	Number of Shares	Weighted Average Fair Value
Outstanding — December 31, 2018	131,741	$	67.24
Granted (1)	88,048	92.74
Vested	(25,831)	67.08
Expired	(15,086)	69.28
Forfeited (2)	(21,055)	71.67
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

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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, 2020

Summary of Effects of Federal Tax Reform on Regulated Businesses [Abstract]

Summary of Effects of Federal Tax Reform on Regulated Businesses [Table Text Block]

Summary TCJA Table

	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates were adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,728	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates were adjusted in March 2019.
Maryland Division (Maryland PSC)	$3,970	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates were adjusted in May 2018.
Sandpiper Energy (Maryland PSC)	$3,713	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018. Customer rates were adjusted in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,257	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$309	Same treatment on a net basis as Chesapeake Utilities Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Utilities Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit is provided to customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.
Elkton Gas (Maryland PSC)	$1,124	PSC approved amortization of ADIT in March 2018.	Previous owner implemented one-time bill credit (totaling less than $0.1 million) in May 2020. Customer rates were adjusted in April 2020.

Schedule of Regulatory Assets [Table Text Block]

At December 31, 2020 and 2019, our regulated utility operations had 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,
	2020		2019
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	2,078	$	5,144
Under-recovered GRIP revenue (2)	278		—
Deferred postretirement benefits (3)	17,716		16,311
Deferred conversion and development costs (1)	23,054		20,881
Environmental regulatory assets and expenditures (4)	1,743		2,241
Acquisition adjustment (5)	28,755		30,329
Loss on reacquired debt (6)	795		869
Deferred costs associated with COVID-19 (7)	1,925		—
Deferred storm costs (8)	44,320		—
Other	3,928		2,776
Total Regulatory Assets	$	124,592	$	78,551
Regulatory Liabilities
Self-insurance (9)	$	533	$	873
Over-recovered purchased fuel and conservation cost recovery (1)	4,422		2,724
Over-recovered GRIP revenue (2)	338		2,668
Storm reserve (9)	2,673		1,437
Accrued asset removal cost (10)	45,315		36,767
Deferred income taxes due to rate change (11)	90,845		89,191
Interest related to storm recovery (8)	3,353		—
Other	1,541		75
Total Regulatory Liabilities	$	149,020	$	133,735

(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 de-risking of the Chesapeake Pension Plan pursuant to an order from the FERC that allowed us to defer Eastern Shore's 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, 2020

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 key MGP sites:

MGP Site (Jurisdiction)	Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
West Palm Beach (Florida)	Remediation actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remediation actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2021.	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.
Sanford (Florida)	In March 2018, the United States Environmental Protection Agency ("EPA") approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be immaterial.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $0.4 million.
Seaford (Delaware)	Conducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction is being implemented, in accordance with the DNREC-approved Work Plan.	Between $0.2 million and $0.5 million.

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Other Commitments and Contingencies Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2020

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	2021		2022-2023		2024-2025		Beyond 2025		Total
(in thousands)
Purchase Obligations	$	69,459	$	81,841	$	69,420	$	201,504	$	422,224

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2020

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	$	1.24
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	$	1.28
Diluted Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	1.77	$	0.64	$	0.56	$	1.24
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	$	1.28
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, 2020 USD ($) mi	Dec. 31, 2019 USD ($) mi	Dec. 31, 2018 USD ($)
Property, Plant and Equipment [Line Items]
Contributions in Aid of Construction	$ 2,900	$ 2,100
Public Utilities, Allowance for Funds Used During Construction, Description	$ 700	700	$ 1,900
Number of Months to Establish ROU Asset and Liability	12 months
Property, plant and equipment
Total property, plant and equipment	$ 1,908,992	1,746,532
Less: Accumulated depreciation and amortization	(368,743)	(336,876)
Net property, plant and equipment	1,601,178	1,463,797
Construction Work in Progress	60,929	54,141
Jointly Owned Pipeline [Member]
Property, plant and equipment
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	300
Natural Gas
Property, plant and equipment
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	1,700	1,500
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	782,329	705,095
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	667,538	608,727
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	87,962	73,658
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	127,710	127,651
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	151,258	141,945
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	36,521	35,436
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	24,905	14,014
Other
Property, plant and equipment
Total property, plant and equipment	30,769	$ 40,006
Natural Gas Operations
Property, plant and equipment
Net property, plant and equipment	$ 6,700
Miles Of Natural Gas Pipeline | mi	26	16
Jointly Owned Pipeline [Member]
Property, plant and equipment
Net property, plant and equipment	$ 26,400

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($) utility mi	Dec. 31, 2019 USD ($) mi	Dec. 31, 2018 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Operating Lease, Liability	$ 11,619
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	$ 2,900	$ 2,100
Net property, plant and equipment	1,601,178	1,463,797
Accumulated depreciation	368,743	336,876
Depreciation and accretion reported in operations expenses	9,600	8,800	$ 8,500
Operating Lease, Right-of-Use Asset	11,194	$ 11,563
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	$ 6,700
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, 2020	Dec. 31, 2019	Dec. 31, 2018
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%	2.60%	2.90%
Natural gas transmission | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.70%	2.60%	2.70%
Natural gas transmission | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.30%	2.40%	2.30%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.90%	3.40%	3.40%

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Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2020
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, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Additions, Charged to Income	$ 3,827
Additions, Other Accounts	613
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	(992)
Accounts Receivable, Allowance for Credit Losses, Current, Disclosure	$ 4,785	$ 1,337

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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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	$ 21,661	$ 9,280	$ 10,661	$ 29,041	$ 17,123	$ 6,251	$ 8,914	$ 28,811	$ 70,642	$ 61,100	$ 56,968
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax									$ 856	$ 4,053	$ (388)
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.24	$ 0.56	$ 0.65	$ 1.77	$ 1.05	$ 0.38	$ 0.54	$ 1.76	$ 4.23	$ 3.73	$ 3.48
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$ 0.04	$ 0	$ 0.02	$ (0.01)	$ 0.33	$ (0.04)	$ (0.03)	$ (0.01)	$ 0.05	$ 0.24	$ (0.02)
Calculation of Basic Earnings Per Share:
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	$ 71,498	$ 65,153	$ 56,580
Weighted shares outstanding - Basic (in shares)									16,711,579	16,398,443	16,369,616
Basic Earnings Per Share (in usd per share)	$ 1.28	$ 0.56	$ 0.67	$ 1.76	$ 1.38	$ 0.34	$ 0.51	$ 1.75	$ 4.28	$ 3.97	$ 3.46
Calculation of Diluted Earnings Per Share:
Net Income	$ 22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	$ 71,498	$ 65,153	$ 56,580
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									16,711,579	16,398,443	16,369,616
Share-based Compensation									59,156	50,043	50,254
Adjusted denominator — Diluted									16,770,735	16,448,486	16,419,870
Income (Loss) from Continuing Operations, Per Diluted Share	$ 1.24	$ 0.56	$ 0.64	$ 1.77	$ 1.04	$ 0.38	$ 0.54	$ 1.75	$ 4.21	$ 3.72	$ 3.47
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share	0.04	0	0.02	(0.01)	0.33	(0.04)	(0.04)	(0.01)	0.05	0.24	(0.02)
Diluted (in usd per share)	$ 1.28	$ 0.56	$ 0.66	$ 1.76	$ 1.37	$ 0.34	$ 0.50	$ 1.74	$ 4.26	$ 3.96	$ 3.45

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Acquisitions - Additional Information (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020 USD ($)	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) Dekatherm	Dec. 31, 2018 USD ($)
Cash paid for acquisition									$ 22,231	$ 23,988	$ 16,654
Revenues	$ 137,038	$ 101,419	$ 97,051	$ 152,690	$ 131,974	$ 92,626	$ 94,542	$ 160,464	488,198	479,605	490,316
Operating Income (Loss)	35,206	17,406	17,977	42,134	29,641	14,357	18,165	44,122	112,723	106,285	94,844
Net Income	22,352	$ 9,261	$ 10,956	$ 28,930	$ 22,564	$ 5,621	$ 8,304	$ 28,663	71,498	$ 65,153	56,580
Discontinued Operations [Member]
Business Combination, Working Capital	8,000								8,000
Elkton Gas [Member]
Revenues									2,399
Operating Income (Loss)									418
Marlin Gas Services [Member]
Additional Compressed Natural Gas Deliverability | Dekatherm										7,000
Boulden [Member]
Revenues									5,717	$ 550
Operating Income (Loss)									1,854	239
Business Combination, Consideration Transferred									24,600
Western Natural Gas [Member]
Revenues									555
Operating Income (Loss)									90
Regulated Energy [Member]
Operating Income (Loss)									$ 92,124	86,584	79,215
Regulated Energy [Member] | Elkton Gas [Member]
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)									$ 20,664	$ 19,938	$ 17,125
Unregulated Energy | Boulden [Member]
Number of customers acquired through acquisition									5,200
Business Combination, Working Capital	200								$ 200
Business Combination, Contingent Consideration, Liability	600								600
Property, Plant and Equipment, Acquired During Period	8,300								8,300
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles	5,100								5,100
Goodwill, Acquired During Period									11,200
Unregulated Energy | Western Natural Gas [Member]
Business Combination, Consideration Transferred									6,700
Business Combination, Working Capital	300								300
Business Combination, Contingent Consideration, Liability	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

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Acquisitions Divestitures (Details) $ in Thousands		3 Months Ended	12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Accounts Receivable, before Allowance for Credit Loss, Current		$ 50,899	$ 61,675	$ 50,899
Proceeds from the sale of discontinued operations				23,100
Depreciation and amortization				477	$ 582
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		(336,876)	(368,743)	(336,876)
Disposal Group, Including Discontinued Operation, Operating Income (Loss)			(204)	(1,578)	(223)
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax			809	(1,875)	(517)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax			200	7,344	0
Discontinued Operation, Tax Effect of Discontinued Operation			(153)	(1,416)	129
Gain Loss From Discontinued Operations			856	4,053	(388)
Disposal Group, Including Discontinued Operation, Assets, Current		134,826	136,431	134,826
Deferred Income Tax Expense (Benefit)	[1]		$ 24,200	23,904	20,914
Number of Disposal Transactions			4
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		$ 5,402	$ 170	5,402
PESCO [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax				7,500
Discontinued Operations, Held-for-sale or Disposed of by Sale
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Revenue			26	161,289	258,713
Disposal Group, Including Discontinued Operation, Costs of Goods Sold			0	157,646	252,111
Disposal Group, Including Discontinued Operation, Operating Expense			230	5,221	6,825
Disposal Group, Including Discontinued Operation, Interest Income			1,013
Disposal Group, Including Discontinued Operation, Interest Expense				(297)	(294)
Discontinued Operation, Tax Effect of Discontinued Operation			(153)	(1,416)	129
Discontinued Operations [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Combination, Working Capital			8,000
Capital Expenditure, Discontinued Operations				0	115
Deferred Income Tax Expense (Benefit)				(125)	1,088
Gain from a settlement				(2,161)	$ 5,002
PESCO [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Discontinued Operation, Intra-Entity Amounts, Discontinued Operation after Disposal, Revenue			$ 19,800	$ 31,500

[1] (1) Includes $4.9 million, $4.7 million, and $3.5 million of deferred state income taxes for the years 2020, 2019 and 2018, respectively.

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Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 55,600	$ 47,430
Contract with Customer, Asset, Net, Noncurrent	4,816	3,465
Contract with Customer, Liability, Current	644	589
Increase (Decrease) in Receivables	8,170
Increase (Decrease) in Other Noncurrent Assets	1,351
Increase (Decrease) in Other Current Liabilities	55
Contract with Customer, Liability, Revenue Recognized	$ 1,300	$ 1,000

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Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020		Dec. 31, 2019		Dec. 31, 2018
Disaggregation of Revenue [Line Items]
Revenues	$ 137,038	$ 101,419	$ 97,051	$ 152,690	$ 131,974	$ 92,626	$ 94,542	$ 160,464	$ 488,198		$ 479,605		$ 490,316
Revenue from Contract with Customer, Excluding Assessed Tax									488,198	[1]	479,605	[2]	490,316	[3]
Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(17,074)	[1]	(17,552)	[2]	(16,870)	[3]
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									528		529		652
Other [Member] | Corporate, Non-Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									528		529		652
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									126,164		121,870		111,582
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(65,921)		(67,422)		(67,761)
Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(17,602)		(18,081)		(17,522)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									352,746	[1]	343,006	[2]	345,281	[3]
Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									302,718		292,563		302,860
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									98,213		89,377		76,175
Regulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(48,185)		(38,934)		(33,754)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									152,526	[1]	154,151	[2]	161,905	[3]
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									27,951		32,493		35,407
Unregulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(134)		(10,407)		(16,485)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues									1,400		(100)		200
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues									200		300		300
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									63,389		62,659		70,338
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									30,850		28,485		25,341
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									76,863		77,416		79,803
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									90,150		82,418		81,118
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									21,853		22,517		24,172
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									17,214		19,068		22,088
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									27,951		32,493		35,407
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									75,117		72,924		64,248
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									23,080		16,453		11,927
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									16,147		16,749		17,302
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									100,744		109,614		125,560
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									7,818		5,702		121
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(65,393)		(66,893)		(67,109)
Eliminations [Member] | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(17,074)		(17,552)		(16,870)
Eliminations [Member] | Regulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(48,185)		(38,934)		(33,754)
Eliminations [Member] | Unregulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(134)		$ (10,407)		$ (16,485)
Aspire Energy Express | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									16
Elkton Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									$ 2,399

[1] 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

[2] (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

[3] (1) Total operating revenues for the year ended December 31, 2018, include other revenue (revenues from sources other than contracts with customers) of $0.2 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, 2020 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	$ 34,978
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	$ 4,351
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	$ 566
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	$ 39,895
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	$ 27,155
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	$ 5,394
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	$ 566
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	$ 33,115
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	$ 21,748
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	$ 4,937
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	$ 566
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	$ 27,251
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	$ 19,587
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	$ 4,705
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	$ 566
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	$ 24,858
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	$ 18,736
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	$ 4,172
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	$ 23,183
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	$ 174,774
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	$ 32,996
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	$ 825
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	$ 208,595

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Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		$ 137,038	$ 101,419	$ 97,051	$ 152,690	$ 131,974	$ 92,626	$ 94,542	$ 160,464	$ 488,198	$ 479,605	$ 490,316
Intersegment Revenues (1)
Total intersegment revenues		137,038	101,419	97,051	152,690	131,974	92,626	94,542	160,464	488,198	479,605	490,316
Operating Income
Operating Income		35,206	17,406	17,977	42,134	29,641	14,357	18,165	44,122	112,723	106,285	94,844
Other income										3,222	(1,847)	(607)
Interest charges										21,765	22,224	16,146
Income Before Income taxes										94,180	82,214	78,091
Income Taxes on Continuing Operations										23,538	21,114	21,123
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent		21,661	9,280	10,661	29,041	17,123	6,251	8,914	28,811	70,642	61,100	56,968
Net Income		22,352	9,261	10,956	28,930	22,564	5,621	8,304	28,663	71,498	65,153	56,580
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		691	$ (19)	$ 125	$ (111)	39	$ (630)	$ (610)	$ (148)	686	(1,349)	(388)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax						5,402				170	5,402
Depreciation and Amortization
Total depreciation and amortization										58,117	45,424	40,220
Identifiable Assets
Total identifiable assets		1,932,487				1,783,198				1,932,487	1,783,198
Regulated Energy
Operating Income
Operating Income										92,124	86,584	79,215
Depreciation and Amortization
Total depreciation and amortization										46,079	35,227	31,876
Payments to Acquire Productive Assets										147,100	130,604	235,912
Unregulated Energy
Operating Income
Operating Income										20,664	19,938	17,125
Depreciation and Amortization
Total depreciation and amortization										11,988	10,130	8,263
Payments to Acquire Productive Assets										46,295	60,034	38,585
Other
Operating Income
Operating Income										(65)	(237)	(1,496)
Depreciation and Amortization
Payments to Acquire Productive Assets										2,480	8,348	8,364
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization										50	67	81
Total for Segments [Member]
Depreciation and Amortization
Payments to Acquire Productive Assets										195,875	198,986	282,861
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										488,198	479,605	490,316
Intersegment Revenues (1)
Total intersegment revenues										488,198	479,605	490,316
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										350,853	340,857	343,313
Intersegment Revenues (1)
Total intersegment revenues										350,853	340,857	343,313
Identifiable Assets
Total identifiable assets		1,547,619				1,434,066				1,547,619	1,434,066
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										137,345	138,748	147,003
Intersegment Revenues (1)
Total intersegment revenues										137,345	138,748	147,003
Identifiable Assets
Total identifiable assets		347,665				296,810				347,665	296,810
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									17,602	18,081	17,522
Intersegment Revenues (1)
Total intersegment revenues	[1]									17,602	18,081	17,522
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									1,893	2,149	1,968
Intersegment Revenues (1)
Total intersegment revenues	[1]									1,893	2,149	1,968
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									15,181	15,403	14,902
Intersegment Revenues (1)
Total intersegment revenues	[1]									15,181	15,403	14,902
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									528	529	652
Intersegment Revenues (1)
Total intersegment revenues	[1]									528	529	$ 652
Other And Intersegment Eliminations
Identifiable Assets
Total identifiable assets		$ 37,203				$ 52,322				$ 37,203	$ 52,322

[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, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 22,884	$ 23,856	$ 16,741
Cash paid for income taxes	$ (8,135)	$ 3,221	$ 477

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Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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	$ 23,625	$ 13,470	$ 39,402
Non Cash Performance Incentive Plan DRP	1,605
Performance Incentive Plan	1,971	1,691	2,006
Capital Lease Obligation	$ 0	$ 0	$ 1,310

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Derivative Instruments - Additional Information (Detail) $ in Thousands	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2020 USD ($) gal	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		$ 127	$ 127	$ 1,844
Unrealized Gain (Loss) on Derivatives			7,505	910	$ (2,701)
Notional Amount of Nonderivative Instruments		$ 60,000	$ 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%
Interest Rate Swap [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			$ 100
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Put Option
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		$ 23	23
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		64	64	1,844
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		40	40
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			2,700
Other Receivables from Broker-Dealers and Clearing Organizations		0	0	2,317
Other Payables to Broker-Dealers and Clearing Organizations		$ 1,505	$ 1,505
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimate of Time to Transfer			12 months
Sharp Energy Inc [Member] | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal			400,000
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			$ 0	(294)	532
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			0	(63)	200
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			5,035	(253)	(2,773)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			(40)
Cost of Sales [Member] | Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			0	0	(13)
Cost of Sales [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			2,428	1,520	(647)
Cost of Sales [Member] | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			(12)	$ 0	$ 0
Inventories [Member] | Derivatives designated as fair value hedges | Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net			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, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 3,269	$ 0
Energy Marketing Contract Liabilities, Current	127	1,844
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	64	1,844
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	40
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	3,255	0
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Put Option
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	14	$ 0
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current	$ 127	$ 1,844
Gain (Loss) on derivatives	7,505	910	$ (2,701)
Cost of Sales | Derivatives not designated as hedging instruments | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	(13)
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	(12)	0	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	2,428	1,520	(647)
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	(294)	532
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	5,035	(253)	(2,773)
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	(63)	$ 200
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(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
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	64	$ 1,844
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	$ 40

XML

Derivative Instruments Volume of Derivative Activity (Details) - Sharp Energy Inc [Member]	12 Months Ended
	Dec. 31, 2020 gal
Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	17,600,000
Put Or Call Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	400,000

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2020	Dec. 31, 2019
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 523.0	$ 486.6
Fair value of long-term debt	$ 548.5	$ 505.0

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Assets:
Investments	$ 10,776	$ 9,229
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	8,620	8,426
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	3,269	0
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	127	1,844
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	2,156	803
Significant Unobservable Inputs (Level 3) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	21	27
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	2,156	803
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	8,599	8,399
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	8,620	8,426
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	2,156	803
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	3,269	0
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	14,045	9,229
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	127	1,844
Fair Value | Equity Securities [Member]
Assets:
Investments	21	27
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	2,156	803
Fair Value | Other Investments [Member]
Assets:
Investments	8,599	8,399
Fair Value | Investments [Member]
Assets:
Investments	10,776	9,229
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 3,269	$ 0

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, 2020	Dec. 31, 2019
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 803	$ 686
Purchases and adjustments	261	131
Transfers/disbursements	(1,065)	29
Investment income	27	15
Ending Balance	$ 2,156	$ 803

XML

Investments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Investments [Abstract]
Unrealized gain, net of other expenses	$ 1,500	$ 1,600	$ (400)

XML

Investments - Schedule of Investment (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Investment [Line Items]
Investments, Fair Value Disclosure	$ 10,776	$ 9,229
Rabbi Trust Associated With Deferred Compensation [Member]
Investment [Line Items]
Investments, Fair Value Disclosure	10,755	9,202
Fair Value, Inputs, Level 1 [Member] | Investments in equity securities
Investment [Line Items]
Investments, Fair Value Disclosure	$ 21	$ 27

XML

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 13,777	$ 12,365
Acquired finite-lived intangible assets, weighted average useful life		11 years
Goodwill		$ 38,731	32,668
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		1,300
Amortization of intangible assets		1,200	800	$ 400
Amortization of intangible assets, 2020		900
Amortization of intangible assets, 2019		1,000
Regulated Energy
Goodwill [Line Items]
Goodwill		7,617	3,353
Unregulated Energy
Goodwill [Line Items]
Goodwill		31,114	29,315
Customer list
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[1]	$ 10,680	9,391
Customer list | Minimum [Member]
Goodwill [Line Items]
Amortized period of acquired intangible assets		5 years
Customer list | Boulden [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 4,600
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]	2,375	$ 2,252
Noncompete Agreements [Member] | Boulden [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		500
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 includes $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 amounts also include customer relationship and non-compete agreements amounts of $4.6 million and $0.5 million, respectively, recorded as a result of the purchase of the operating assets of Boulden in December 2019.

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 13,777	$ 12,365
Finite-Lived Intangible Assets, Accumulated Amortization		5,485	4,236
Goodwill		38,731	32,668
Goodwill, Transfers	[1]	6,063
Regulated Energy
Goodwill [Line Items]
Goodwill		7,617	3,353
Goodwill, Transfers	[1]	4,264
Unregulated Energy
Goodwill [Line Items]
Goodwill		31,114	29,315
Goodwill, Transfers	[1]	1,799
Customer Lists [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	10,680	9,391
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	4,269	3,463
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	2,375	2,252
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	768	451
Patents [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		452	452
Finite-Lived Intangible Assets, Accumulated Amortization		236	118
Other Intangible Assets [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		270	270
Finite-Lived Intangible Assets, Accumulated Amortization		$ 212	$ 204

[1] (1)Includes goodwill from the purchase of operating assets of Elkton Gas in the third quarter of 2020 and Western Natural Gas in October 2020.

[2] 1) The customer relationship and non-compete agreements amounts includes $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 amounts also include customer relationship and non-compete agreements amounts of $4.6 million and $0.5 million, respectively, recorded as a result of the purchase of the operating assets of Boulden in December 2019.

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2020	Dec. 31, 2019
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		$ 13,777	$ 12,365
Accumulated Amortization		5,485	4,236
Customer Lists [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	10,680	9,391
Accumulated Amortization	[1]	4,269	3,463
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	2,375	2,252
Accumulated Amortization	[1]	768	451
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		452	452
Accumulated Amortization		236	118
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		270	270
Accumulated Amortization		$ 212	$ 204

[1] 1) The customer relationship and non-compete agreements amounts includes $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 amounts also include customer relationship and non-compete agreements amounts of $4.6 million and $0.5 million, respectively, recorded as a result of the purchase of the operating assets of Boulden in December 2019.

XML

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	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	$ 1,587	5,523
Net Operating Losses and Tax Carryback	(1,841)
Deferred State and Local Income Tax Expense (Benefit)	4,900	4,700	$ 3,500
Deferred Tax Assets, Operating Loss Carryforwards, Total	1,600	5,500
Net Operating Losses and Tax Carryback, Total	(1,800)
Deferred Tax Assets, Operating Loss Carryforwards	$ 1,587	5,523
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	$ 40,000	$ 54,700

XML

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current Income Tax Expense
Federal		$ (2,777)	$ (2,252)	$ (361)
State		2,162	(491)	617
Other		(47)	(47)	(47)
Total current income tax expense (benefit)		(662)	(2,790)	209
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	24,200	23,904	20,914
Income Tax Expense from Continuing Operations		23,538	21,114	21,123
Discontinued Operation, Tax Effect of Gain (Loss) from Disposal of Discontinued Operation		153	1,416	(129)
Income Tax Expense (Benefit), Continuing Operations, Discontinued Operations		23,691	22,530	20,994
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		23,224	25,907	19,178
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		(714)	79	(1,435)
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		(75)	(454)	454
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense		156	(278)	(528)
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		5,107	(3,772)	(250)
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ (3,498)	$ 2,422	$ 3,495

[1] (1) Includes $4.9 million, $4.7 million, and $3.5 million of deferred state income taxes for the years 2020, 2019 and 2018, respectively.

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
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]	$ 19,778	$ 17,264	$ 16,400
State income taxes, net of federal benefit		5,051	5,093	4,071
ESOP dividend deduction		(218)	(173)	(158)
Other		768	(1,070)	810
Income Tax Expense from Continuing Operations		$ 23,538	$ 21,114	$ 21,123
Effective Income Tax Rate for Continuing Operations		24.99%	25.65%	27.13%

[1] Federal income taxes were calculated at 21 percent for 2020, 2019, and 2018.

XML

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 4,900	$ 4,700	$ 3,500
Deferred income tax liabilities:
Property, plant and equipment	199,287	173,466
Acquisition adjustment	6,618	6,969
Deferred Tax Liabilities Loss On Reacquired Debt	201	220
Deferred Income Tax Liability - Deferred Gas Costs	509	1,223
Deferred Income Tax Liability, Natural Gas Conversion Costs	5,379	4,956
Deferred Income Tax Liability, Storm Reserve	7,073	10,316
Other	5,587	1,456
Total deferred income tax liabilities	224,654	198,606
Deferred income tax assets:
Pension and other employee benefits	4,636	3,818
Environmental costs	1,064	1,486
Net operating loss carryforwards	1,587	5,523
Self-insurance	0	146
Storm reserve liability	409	96
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals	6,153	2,064
Other	5,417	4,817
Total deferred income tax assets	19,266	17,950
Deferred Tax Assets, Net	$ 205,388	$ 180,656

XML

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 4.9	$ 4.7	$ 3.5

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2018
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, 2020	Dec. 31, 2018
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	$ 310,000
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	581,000
Cumulative net income with restrictions	256,400
Long-term debt including current maturities	523,000	$ 486,600
Long-term Debt and Lease Obligation	522,099	485,768
Total long-term debt, net of current maturities	508,499	440,168
Unamortized Debt Issuance Expense	(901)	(822)
Long-term Debt and Lease Obligation, Current	$ (13,600)	(45,600)
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	$ 17,400	20,300
First Mortgage Bond Due On Two Thousand Twenty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Long-term debt including current maturities		7,990
Long-term Debt, Total		8,000
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	$ 5,600	6,300
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	$ 16,000	18,000
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	$ 45,000	50,000
Uncollateralized Senior Note Due On Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Long-term debt including current maturities	$ 0	2,000
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	$ 9,000	12,000
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
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
Term Note Due February Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Long-term debt including current maturities		$ 30,000

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Restricted Payment	$ 256,400
Long-term Debt	523,000	$ 486,600
Less: debt issuance costs	(901)	(822)
Long-term Debt and Lease Obligation	522,099	485,768
Less: current maturities	(13,600)	(45,600)
Total long-term debt, net of current maturities	508,499	440,168
Unrestricted Payment	$ 324,600
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term Debt		7,990
Debt Instrument, Interest Rate, Stated Percentage	9.08%
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term Debt	$ 0	2,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	$ 9,000	12,000
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 17,400	20,300
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 5,600	6,300
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 16,000	18,000
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	$ 45,000	50,000
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%
Term Note Due February Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt		$ 30,000
Debt Instrument, Interest Rate, Stated Percentage	2.46%

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Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2020
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt Instrument, Maturity Date	Jun. 01, 2022
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt Instrument, Maturity Date	Oct. 12, 2020
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
Term Note Due February Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Debt Instrument, Maturity Date	Feb. 28, 2020
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%

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Long-Term Debt Annual Maturities (Details) $ in Thousands	Dec. 31, 2020 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months	$ 13,600
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two	17,100
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Three	20,600
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four	17,600
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Five	24,600
Long-term Debt, Maturities, Repayments of Principal in Rolling after Year Five	429,500
Total Future Repayments	$ 523,000

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Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Line of Credit Facility [Line Items]
Long-term Debt		$ (523,000)	$ (486,600)
Debt Instrument, Unused Borrowing Capacity, Amount		310,000
Prudential [Member]
Line of Credit Facility [Line Items]
Long-term Debt	[1]	(220,000)
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	150,000
MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount		150,000
Debt Instrument, Unused Borrowing Capacity, Amount	[2]	150,000
New York Life [Member]
Line of Credit Facility [Line Items]
Long-term Debt	[3]	(140,000)
Debt Instrument, Unused Borrowing Capacity, Amount	[3]	10,000
Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Long-term Debt		(360,000)
Aggregated Unfunded Commitments [Member]
Line of Credit Facility [Line Items]
Long-term Debt		$ 0
Uncollateralized Senior Note to be Issued in 2019 [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		3.00%
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%
NYL Unsecured Debt [Member]
Line of Credit Facility [Line Items]
Long-term Debt		$ (40,000)
Debt Instrument, Interest Rate, Stated Percentage		2.96%
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)
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)
Debt Instrument, Interest Rate, Stated Percentage		2.96%
9.08% bond, due June 1, 2022
Line of Credit Facility [Line Items]
Long-term Debt			(7,990)
Debt Instrument, Interest Rate, Stated Percentage		9.08%
Interest and Debt Expense		$ 1,000
Term Note Due February Two Thousand Twenty [Member]
Line of Credit Facility [Line Items]
Long-term Debt			$ (30,000)
Debt Instrument, Interest Rate, Stated Percentage		2.46%
Maximum [Member] | Prudential [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	[1]	$ 370,000
Maximum [Member] | MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	[2]	150,000
Maximum [Member] | New York Life [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	[3]	150,000
Maximum [Member] | Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount		$ 670,000

[1] (1) In April 2020, we amended the Prudential Shelf Agreement to increase the available borrowing capacity by $150.0 million. The Shelf Agreement expires in April 2023. In July 2020, we issued $50 million of Prudential Shelf Notes at the rate of 3.00 percent per annum.

[2] 2) In May 2020, we amended an agreement with MetLife to provide a new $150 million MetLife Shelf Agreement for a three-year term ending May 2023.

[3] (3) In August 2020 we issued $40 million of NYL Shelf Notes at the rate of 2.96 percent per annum. The NYL Shelf Agreement expires in November 2021

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Short-Term Borrowing - Additional Information (Detail)	1 Months Ended	3 Months Ended	12 Months Ended
	Feb. 28, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Short-term Debt [Line Items]
Short-term borrowings		$ 175,644,000	$ 175,644,000	$ 247,371,000
Line of Credit Facility, Aggregate Borrowing Capacity		$ 375,000,000.0	$ 375,000,000.0
Number Of Unsecured Bank Credit Facilities			3
Short-term Debt, Weighted Average Interest Rate, at Point in Time		1.28%	1.28%	2.62%
Ratio of Indebtedness to Net Capital		0.65	0.65
Long-term debt including current maturities		$ 523,000,000.0	$ 523,000,000.0	$ 486,600,000
Line of Credit Facility, Commitment Fee Percentage			0.175%
Line of Credit Facility, Interest Rate During Period			1.125%
Line of Credit Facility, Remaining Borrowing Capacity		196,900,000	$ 196,900,000
Letters of Credit Outstanding, Amount		4,800,000	4,800,000
Notional Amount of Nonderivative Instruments		60,000,000.0	100,000,000.0
Subsequent Event
Short-term Debt [Line Items]
Notional Amount of Nonderivative Instruments	$ 40,000,000.0
Fixed Swap Rate	0.17%
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity		$ 375,000,000	$ 375,000,000
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%
Term Note Due February Two Thousand Twenty [Member]
Short-term Debt [Line Items]
Long-term debt including current maturities				$ 30,000,000

XML

Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 375,000
Line of Credit Facility, Remaining Borrowing Capacity	196,900
Short-term borrowing	$ 175,644	$ 247,371
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, 2020 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2,027	[1]
Lessee Future Operating Lease Option Payments	2,100
Lessee, Operating Lease, Liability, Payments, Due Year Two	1,984	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,923	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,657	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,395	[1]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	4,419	[1]
Lessee, Operating Lease, Liability, Payments, Due	13,405	[1]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	1,786
Operating Lease, Liability	$ 11,619

[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, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Cost	[1]	$ 2,029	$ 2,577
Finance Lease, Right-of-Use Asset, Amortization			650
Finance Lease, Interest Expense			5
Lease, Cost		$ 2,029	$ 3,232

[1] 1) Includes short-term leases and variable lease costs, which are immaterial

XML

Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 11,194	$ 11,563
Operating Lease, Liability, Current	1,747	1,705
Operating Lease, Liability, Noncurrent	9,872	9,896
Total Operating and Finance Lease Liabilities	$ 11,619	$ 11,601

XML

Leases Weighted Average Remaining Lease Term Additional Information (Details)	Dec. 31, 2020	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	8 years 8 months 12 days	8 years 10 months 17 days
Operating Lease, Weighted Average Discount Rate, Percent	3.80%	3.80%

XML

Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Leases Cash Flows [Abstract]
Operating Lease, Payments	$ 1,956	$ 2,230
Finance Lease, Interest Expense		5
Finance Lease, Right-of-Use Asset, Amortization		$ 650

XML

Stockholders' Equity Additional Details (Details) - USD ($)	6 Months Ended	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Accumulated Other Comprehensive Income (Loss) [Line Items]
Preferred Stock, Shares Authorized	2,000,000	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01
Proceeds from issuance of common stock, net of expenses		$ 60,980,000	$ 0	$ 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		$ 61,000,000.0
Fees on Equity Issuance - At The Market		1,500,000
Stock Issued During Period, Shares, Dividend Reinvestment Plan	300,000
Stock Issued During Period, Value, Dividend Reinvestment Plan	$ 86.12
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan	$ 22,000,000.0	22,627,000
Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Proceeds from Stock Plans		$ 75,000,000.0

XML

Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (6,267)	$ (6,713)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	4,838	1,289
Amounts reclassified from accumulated other comprehensive income/(loss)	(1,436)	(728)
Net current-period other comprehensive income/(loss)	3,402	561
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(115)
Accumulated other comprehensive loss at end of period	(2,865)	(6,267)
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	(4,933)	(5,928)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(578)	(872)
Amounts reclassified from accumulated other comprehensive income/(loss)	365	1,867
Net current-period other comprehensive income/(loss)	(213)	995
Accumulated other comprehensive loss at end of period	(5,146)	(4,933)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(1,334)	(785)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	5,400	2,161
Amounts reclassified from accumulated other comprehensive income/(loss)	(1,757)	(2,595)
Net current-period other comprehensive income/(loss)	3,643	(434)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(115)
Accumulated other comprehensive loss at end of period	2,309	$ (1,334)
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Other Comprehensive Income (Loss), before Reclassifications, before Tax	16
Amounts reclassified from accumulated other comprehensive income/(loss)	(44)
Net current-period other comprehensive income/(loss)	(28)
Accumulated other comprehensive loss at end of period	$ (28)

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Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Amortization of defined benefit pension and postretirement plan items:
Income tax benefit		$ (23,538)	$ (21,114)	$ (21,123)
Accumulated other comprehensive loss		(2,865)	(6,267)	(6,713)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		4,838	1,289
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1,436)	(728)
Other Comprehensive Income (Loss), Net of Tax		3,402	561
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect			(115)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss		2,309	(1,334)	(785)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		5,400	2,161
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(1,757)	(2,595)
Other Comprehensive Income (Loss), Net of Tax		3,643	(434)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect			(115)
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss		(28)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		16
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		(44)
Other Comprehensive Income (Loss), Net of Tax		(28)
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss		(5,146)	(4,933)	(5,928)
Other Comprehensive Income (Loss), before Reclassifications, before Tax		(578)	(872)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax		365	1,867
Other Comprehensive Income (Loss), Net of Tax		(213)	995
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of defined benefit pension and postretirement plan items:
Net of tax		1,436	728	(2,198)
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	[1]	(592)	(2,600)	(579)
Total before income taxes		(515)	(2,523)	(502)
Income tax benefit	[2]	150	656	63
Net of tax		(365)	(1,867)	(439)
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		2,428	3,623	(2,460)
Income tax benefit	[2]	(671)	(1,028)	701
Net of tax		1,757	2,595	(1,759)
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		60
Income tax benefit		(16)
Net of tax		44
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]	2,428	1,520	(647)
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	2,096	(2,010)
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	$ 7	$ 197
Interest Rate Swap [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		$ 60

[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.

XML

Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2020 USD ($) plan shares	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans | plan		3
Income tax benefits		$ 1,800
Total unrecognized cost		23,956
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		$ 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	$ 5,700	$ 5,500
Shares reserved to fund future contributions | shares		813,230
Investments, Fair Value Disclosure		$ 10,776	9,229
Deferred compensation obligation		$ 5,679	4,543
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]
Total unrecognized cost		$ 2,033
Unfunded accumulated benefit obligation		(1,537)	(1,584)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		300
Expected contribution	[1]	384
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		21,242
Unfunded accumulated benefit obligation		(14,400)	(15,601)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		2,100
Expected contribution	[1]	3,409
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		699
Unfunded accumulated benefit obligation		(2,212)	(2,157)
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		$ 176
Unfunded accumulated benefit obligation		$ (1,033)	(1,100)
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]	68
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		194
Unfunded accumulated benefit obligation		$ (1,009)	(1,224)
Health care inflation rate		5.00%
Expected contribution	[2]	$ 67
Rabbi Trust Associated With Deferred Compensation [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure		$ 10,755	9,202
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		$ 10,800	9,200
Deferred Compensation Equity		$ 5,700	$ 4,500

[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, 2020	Dec. 31, 2019		Dec. 31, 2018
Change in benefit obligation:
Interest cost	$ 63	$ 74		$ 83
Chesapeake Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	6,214	10,712
Interest cost	176	375	[1]	384
Actuarial loss	450	1,443
Defined Benefit Plan, Benefit Obligation, Payment for Settlement	(612)	(5,833)
Benefits paid	(82)	(483)
Benefit obligation - end of year	6,146	6,214		10,712
Change in plan assets:
Balance, beginning of year	4,630	8,649
Actual return on plan assets	369	1,180
Employer contributions	304	1,117
Defined Benefit Plan, Plan Assets, Payment for Settlement	(612)	(5,833)
Benefits paid	(82)	(483)
Balance, end of year	4,609	4,630		$ 8,649
Reconciliation:
Funded status	(1,537)	(1,584)
Accrued pension cost	$ (1,537)	$ (1,584)
Assumptions:
Discount rate	2.25%	3.00%
Expected return on plan assets	3.50%	6.00%		6.00%
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 65,304	$ 59,377
Interest cost	2,085	2,452		$ 2,339
Actuarial loss	6,069	6,508
Benefits paid	(3,092)	(3,033)
Benefit obligation - end of year	70,366	65,304		59,377
Change in plan assets:
Balance, beginning of year	49,703	43,601
Actual return on plan assets	6,581	7,978
Employer contributions	2,774	1,157
Benefits paid	(3,092)	(3,033)
Balance, end of year	55,966	49,703		$ 43,601
Reconciliation:
Funded status	(14,400)	(15,601)
Accrued pension cost	$ (14,400)	$ (15,601)
Assumptions:
Discount rate	2.50%	3.25%
Expected return on plan assets	6.00%	6.50%		6.50%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year	$ 2,157	$ 2,285
Interest cost	63	74
Actuarial loss	144	159
Benefits paid	(152)	(361)
Benefit obligation - end of year	2,212	2,157		$ 2,285
Change in plan assets:
Employer contributions	152	361
Benefits paid	(152)	(361)
Reconciliation:
Funded status	(2,212)	(2,157)
Accrued pension cost	$ (2,212)	$ (2,157)
Assumptions:
Discount rate	2.25%	3.00%
Chesapeake Postretirement Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1,100	$ 1,002
Interest cost	26	39		38
Plan participants contributions	166	149
Actuarial loss	(34)	73
Benefits paid	(225)	(163)
Benefit obligation - end of year	1,033	1,100		1,002
Change in plan assets:
Balance, beginning of year	0	0
Employer contributions	59	14
Plan participants contributions	166	149
Benefits paid	(225)	(163)
Balance, end of year	0	0		0
Reconciliation:
Funded status	(1,033)	(1,100)
Accrued pension cost	$ (1,033)	$ (1,100)
Assumptions:
Discount rate	2.25%	3.00%
FPU Medical Plan
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1,224	$ 1,187
Interest cost	30	48		47
Plan participants contributions	37	38
Actuarial loss	(181)	47
Benefits paid	(101)	(96)
Benefit obligation - end of year	1,009	1,224		1,187
Change in plan assets:
Balance, beginning of year	0	0
Employer contributions	64	58
Plan participants contributions	37	38
Benefits paid	(101)	(96)
Balance, end of year	0	0		$ 0
Reconciliation:
Funded status	(1,009)	(1,224)
Accrued pension cost	$ (1,009)	$ (1,224)
Assumptions:
Discount rate	2.50%	3.25%

[1] (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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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, 2020	Dec. 31, 2019		Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 63	$ 74		$ 83
Prior service cost (credit)		(370)
Net loss		24,326
Total		23,956
Accumulated other comprehensive loss pre-tax		6,907
Post-merger regulatory asset		(17,049)
Total unrecognized cost		(23,956)
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		176	375	[1]	384
Prior service cost (credit)		0
Net loss		2,033
Total		2,033
Accumulated other comprehensive loss pre-tax	[2]	2,033
Post-merger regulatory asset		0
Total unrecognized cost		(2,033)
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		157	487	[1]	542
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(243)	(391)	[1]	(343)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		(203)	(1,982)	[1]	0
Net Periodic Cost Benefit		465	2,261	[1]	185
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		465	2,261	[1]	185
Amortization Of Pre Merger Regulatory Asset		$ 0	$ 0	[1]	$ 0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.00%	3.00%		3.50%
Expected return on plan assets		3.50%	6.00%		6.00%
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 2,085	$ 2,452		$ 2,339
Prior service cost (credit)		0
Net loss		21,242
Total		21,242
Accumulated other comprehensive loss pre-tax	[2]	4,036
Post-merger regulatory asset		(17,206)
Total unrecognized cost		(21,242)
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		2,967	2,770		3,091
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(552)	(505)		(404)
Net Periodic Cost Benefit		(330)	187		(348)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		(330)	730		413
Amortization Of Pre Merger Regulatory Asset		$ 0	$ 543		$ 761
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.25%	4.25%		3.75%
Expected return on plan assets		6.00%	6.50%		6.50%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 63	$ 74
Prior service cost (credit)		0
Net loss		699
Total		699
Accumulated other comprehensive loss pre-tax	[2]	699
Post-merger regulatory asset		0
Total unrecognized cost		(699)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(20)	(85)		$ (101)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0	(58)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 83	$ 217		$ 184
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.00%	4.00%		3.50%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 26	$ 39		$ 38
Prior service cost (credit)		(370)
Net loss		546
Total		176
Accumulated other comprehensive loss pre-tax	[2]	176
Post-merger regulatory asset		0
Total unrecognized cost		(176)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(24)	(46)		(58)
Net Periodic Cost Benefit		(27)	8		19
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ (27)	$ 8		$ 19
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.00%	4.00%		3.50%
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost		$ 30	$ 48		$ 47
Prior service cost (credit)		0
Net loss		(194)
Total		(194)
Accumulated other comprehensive loss pre-tax	[2]	(37)
Post-merger regulatory asset		(157)
Total unrecognized cost		(194)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(19)	0		0
Net Periodic Cost Benefit		11	48		47
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		17	56		55
Amortization Of Pre Merger Regulatory Asset		$ 6	$ 8		$ 8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.25%	4.25%		3.75%

[1] (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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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] The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2020 is net of income tax benefits of $1.8 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, 2020 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	$ 1.8

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Employee Benefit Plans - Schedule of Assets by Investment Type (Detail) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Fair Value, Inputs, Level 1, 2 and 3
Asset Category
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments	$ 52,459	$ 47,316
Chesapeake Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
Chesapeake Pension Plan | Investments in equity securities
Asset Category
Percentage of assets by investment type	0.00%	0.00%	49.00%
Chesapeake Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	96.00%	92.00%	41.00%
Chesapeake Pension Plan | Other
Asset Category
Percentage of assets by investment type	4.00%	8.00%	10.00%
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	54.00%	53.00%	50.00%
FPU Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	37.00%	37.00%	41.00%
FPU Pension Plan | Other
Asset Category
Percentage of assets by investment type	9.00%	10.00%	9.00%

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Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2020
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	6.00%
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	14.00%
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, 2020	Dec. 31, 2019	Dec. 31, 2018
Debt and Equity Securities, FV-NI [Line Items]
Investments measured at net asset value	[1]	$ 8,116	$ 7,017
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		23,071	20,477
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	3,615	3,553
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1,672	1,604
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	891	726
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	11,307	9,855
Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	5,586	4,739
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		24,169	21,696
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	21,563	19,220
Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	2,606	2,476
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		5,219	5,143
Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	2,246	1,708
Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	1,954	2,288
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	1,019	1,147
Quoted Prices in Active Markets (Level 1)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		51,440	46,169
Quoted Prices in Active Markets (Level 1) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		23,071	20,477
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]	3,615	3,553
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]	1,672	1,604
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]	891	726
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]	11,307	9,855
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]	5,586	4,739
Quoted Prices in Active Markets (Level 1) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		24,169	21,696
Quoted Prices in Active Markets (Level 1) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	21,563	19,220
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]	2,606	2,476
Quoted Prices in Active Markets (Level 1) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		4,200	3,996
Quoted Prices in Active Markets (Level 1) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	2,246	1,708
Quoted Prices in Active Markets (Level 1) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	1,954	2,288
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		1,019	1,147	$ 627
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		1,019	1,147
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]	1,019	1,147
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		52,459	47,316
Fair Value Measured at Net Asset Value Per Share
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 60,575	$ 54,333

[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 - Summary of Changes in Fair Value of Level 3 Investments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Defined Benefit Plan, Alternative Investments, Fair Value of Plan Assets	[1]	$ 8,116	$ 7,017
Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		46,169
Balance, end of year		51,440	46,169
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		1,147	627
Purchases		3,190	2,274
Transfers in		921	3,090
Disbursements		(4,290)	(4,907)
Investment Income		51	63
Balance, end of year		1,019	1,147
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		52,459	47,316
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		54,333
Balance, end of year		60,575	54,333
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		20,477
Balance, end of year		23,071	20,477
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		20,477
Balance, end of year		23,071	20,477
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		21,696
Balance, end of year		24,169	21,696
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		21,696
Balance, end of year		24,169	21,696
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		5,143
Balance, end of year		5,219	5,143
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		3,996
Balance, end of year		4,200	3,996
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		1,147
Balance, end of year		1,019	1,147
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]	3,553
Balance, end of year	[2]	3,615	3,553
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]	3,553
Balance, end of year	[2]	3,615	3,553
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]	1,604
Balance, end of year	[2]	1,672	1,604
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]	1,604
Balance, end of year	[2]	1,672	1,604
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]	726
Balance, end of year	[2]	891	726
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]	726
Balance, end of year	[2]	891	726
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]	9,855
Balance, end of year	[3]	11,307	9,855
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]	9,855
Balance, end of year	[3]	11,307	9,855
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]	4,739
Balance, end of year	[4]	5,586	4,739
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]	4,739
Balance, end of year	[4]	5,586	4,739
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]	19,220
Balance, end of year	[5]	21,563	19,220
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]	19,220
Balance, end of year	[5]	21,563	19,220
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]	2,476
Balance, end of year	[5]	2,606	2,476
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]	2,476
Balance, end of year	[5]	2,606	2,476
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]	1,708
Balance, end of year	[6]	2,246	1,708
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]	1,708
Balance, end of year	[6]	2,246	1,708
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]	2,288
Balance, end of year	[7]	1,954	2,288
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]	2,288
Balance, end of year	[7]	1,954	2,288
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]	1,147
Balance, end of year	[8]	1,019	1,147
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]	1,147
Balance, end of year	[8]	$ 1,019	$ 1,147

[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, 2020	Dec. 31, 2019		Dec. 31, 2018
Components of net periodic cost:
Interest cost	$ 63	$ 74		$ 83
Expected Amortization Of Pre Merger Regulatory Asset	0
Chesapeake Postretirement Plan
Components of net periodic cost:
Interest cost	26	39		38
Amortization of prior service cost	(77)	(77)		(77)
Actuarial (gain) loss	24	46		58
Net periodic pension cost	(27)	8		19
Expected Amortization Of Pre Merger Regulatory Asset		0		0
Net periodic postretirement cost	$ (27)	$ 8		$ 19
Assumptions
Discount rate	3.00%	4.00%		3.50%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	$ 166	$ 149
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(34)	73
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(225)	(163)
Defined Benefit Plan, Plan Assets, Amount	0	0		$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	59	14
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	166	149
Defined Benefit Plan, Plan Assets, Benefits Paid	(225)	(163)
Funded status	(1,033)	(1,100)
Accrued pension cost	$ (1,033)	$ (1,100)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.25%	3.00%
FPU Medical Plan
Components of net periodic cost:
Interest cost	$ 30	$ 48		47
Amortization of prior service cost	0	0		0
Actuarial (gain) loss	19	0		0
Net periodic pension cost	11	48		47
Amortization of pre-merger regulatory asset	6	8		8
Net periodic postretirement cost	$ 17	$ 56		$ 55
Assumptions
Discount rate	3.25%	4.25%		3.75%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant	$ 37	$ 38
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	(181)	47
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(101)	(96)
Defined Benefit Plan, Plan Assets, Amount	0	0		$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	64	58
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant	37	38
Defined Benefit Plan, Plan Assets, Benefits Paid	(101)	(96)
Funded status	(1,009)	(1,224)
Accrued pension cost	$ (1,009)	$ (1,224)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.50%	3.25%
Chesapeake SERP
Components of net periodic cost:
Interest cost	$ 63	$ 74
Actuarial (gain) loss	20	85		101
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	0	58
Net periodic postretirement cost	$ 83	$ 217		$ 184
Assumptions
Discount rate	3.00%	4.00%		3.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 144	$ 159
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(152)	(361)
Defined Benefit Plan, Plan Assets, Contributions by Employer	152	361
Defined Benefit Plan, Plan Assets, Benefits Paid	(152)	(361)
Funded status	(2,212)	(2,157)
Accrued pension cost	$ (2,212)	$ (2,157)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.25%	3.00%
Chesapeake Pension Plan
Components of net periodic cost:
Interest cost	$ 176	$ 375	[1]	$ 384
Expected return on assets	(157)	(487)	[1]	(542)
Actuarial (gain) loss	243	391	[1]	343
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement	203	1,982	[1]	0
Net periodic pension cost	465	2,261	[1]	185
Amortization of pre-merger regulatory asset	0	0	[1]	0
Net periodic postretirement cost	$ 465	$ 2,261	[1]	$ 185
Assumptions
Discount rate	3.00%	3.00%		3.50%
Expected return on plan assets	3.50%	6.00%		6.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 450	$ 1,443
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(82)	(483)
Defined Benefit Plan, Plan Assets, Amount	4,609	4,630		$ 8,649
Defined Benefit Plan, Plan Assets, Contributions by Employer	304	1,117
Defined Benefit Plan, Plan Assets, Benefits Paid	(82)	(483)
Funded status	(1,537)	(1,584)
Accrued pension cost	$ (1,537)	$ (1,584)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.25%	3.00%
FPU Pension Plan
Components of net periodic cost:
Interest cost	$ 2,085	$ 2,452		2,339
Expected return on assets	(2,967)	(2,770)		(3,091)
Actuarial (gain) loss	552	505		404
Net periodic pension cost	(330)	187		(348)
Amortization of pre-merger regulatory asset	0	543		761
Net periodic postretirement cost	$ (330)	$ 730		$ 413
Assumptions
Discount rate	3.25%	4.25%		3.75%
Expected return on plan assets	6.00%	6.50%		6.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 6,069	$ 6,508
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(3,092)	(3,033)
Defined Benefit Plan, Plan Assets, Amount	55,966	49,703		$ 43,601
Defined Benefit Plan, Plan Assets, Contributions by Employer	2,774	1,157
Defined Benefit Plan, Plan Assets, Benefits Paid	(3,092)	(3,033)
Funded status	(14,400)	(15,601)
Accrued pension cost	$ (14,400)	$ (15,601)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	2.50%	3.25%

[1] (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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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, 2020	Dec. 31, 2019		Dec. 31, 2018
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 0	$ 0	[1]	$ 0
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	0	543		761
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 6	$ 8		$ 8

[1] (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 remeasured which triggered settlement accounting expense in the fourth quarter of 2019. We recorded $0.7 million of 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, 2020 USD ($)
Chesapeake Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	$ 384	[1]
2018	99	[1]
2019	981	[1]
2020	106	[1]
2021	1,007	[1]
Years 2022 through 2026	1,193	[1]
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	3,409	[1]
2018	3,493	[1]
2019	3,559	[1]
2020	3,601	[1]
2021	3,680	[1]
Years 2022 through 2026	18,627	[1]
Chesapeake SERP
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	151	[2]
2018	150	[2]
2019	148	[2]
2020	146	[2]
2021	158	[2]
Years 2022 through 2026	735	[2]
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	68	[2]
2018	66	[2]
2019	61	[2]
2020	58	[2]
2021	55	[2]
Years 2022 through 2026	222	[2]
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	67	[2]
2018	67	[2]
2019	66	[2]
2020	67	[2]
2021	67	[2]
Years 2022 through 2026	$ 317	[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, 2020	Dec. 31, 2019
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Funded status	$ (1,537)	$ (1,584)

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Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019		Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Number of Additional Shares Authorized	43,032
Unrecognized compensation expense related to the awards to Non employee directors	$ 3.9
Shares reserved for issuance	813,230
Number of Shares, Granted	887	751
Number of shares withheld	10,319	7,635		16,918
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
Weighted average grant-date fair value of awards granted	$ 84.47	$ 93.14
Total [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Granted	8,870	6,759
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
Number of Shares, Granted	254
Weighted average grant-date fair value of awards granted	$ 95.83
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	$ 66.48	$ 67.08
Number of Shares, Granted	70,014	88,048	[1]
Weighted average grant-date fair value of awards granted	$ 91.89	$ 92.74	[1]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 20.2	$ 15.1		$ 10.7
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	415,412

[1] Includes 43,032 shares that were granted to certain key employees in December 2019 associated with their promotion

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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, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 4,829	$ 4,279	$ 3,410
Less: tax benefit	(1,254)	(1,117)	(934)
Share-Based Compensation amounts included in net income	3,575	3,162	2,476
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	3,900
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	733	620	539
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	20,200	15,100	10,700
Total compensation expense	$ 4,096	$ 3,659	$ 2,871

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Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	887	751
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	$ 3.9
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, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Weighted Average Grant Date Fair Value, Granted	$ 84.47	$ 93.14

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Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2020	Dec. 31, 2019
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted		887	751
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance		157,817	131,741
Number of Shares, Granted		70,014	88,048	[1]
Number of Shares, Vested		(35,651)	(25,831)
Number of Shares, Expired			(15,086)
Number of Shares, Outstanding Ending Balance		186,878	157,817
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		$ 80.28	$ 67.24
Weighted Average Grant Date Fair Value, Granted		91.89	92.74	[1]
Weighted Average Grant Date Fair Value, Vested		66.48	67.08
Weighted Average Grant Date Fair Value, Expired			69.28
Weighted Average Grant Date Fair Value, Outstanding Ending Balance		87.06	$ 80.28
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	[2]		21,055
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	[2]		$ 71.67
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		$ 65.32
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number		5,302

[1] Includes 43,032 shares that were granted to certain key employees in December 2019 associated with their promotion

[2] (2) In conjunction with the retirement of two key employees during 2019, 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, 2020	Dec. 31, 2019	Dec. 31, 2018
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation	10,319	7,635	16,918
Payment, Tax Withholding, Share-based Payment Arrangement	$ 977	$ 692	$ 1,210

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Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2020 USD ($) mi	Sep. 30, 2020 USD ($)	Jun. 30, 2020 USD ($)	Mar. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2020 USD ($) dekatherm / d mi	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Rates and Other Regulatory Activities [Line Items]
Restricted Payment	$ 256,400								$ 256,400
Regulatory Assets	124,592				$ 78,551				124,592	$ 78,551
Revenues	$ 137,038	$ 101,419	$ 97,051	$ 152,690	$ 131,974	$ 92,626	$ 94,542	$ 160,464	488,198	$ 479,605	$ 490,316
Regulatory Asset - Storm Cost Recovery									45,800
Surcharge - Storm Cost Recovery									7,700
Incremental Revenue - Storm Cost Recovery									$ 3,300
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Extent of Customers Losing Service									100.00%
Amounts Spent to Restore Service									$ 65,000
Peninsula Pipeline [Member] | Callahan Project [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Pipeline Miles | mi	26								26
Diameter of Pipe | mi	16								16
Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
Cost Recovery, Capital									$ 500
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								6
number of customers									4
Number of Mainline Pipeline Miles | mi	13								13
Hurricane Dorrian [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liability, Amortization Period									30 years
Regulatory Liability, Amortization Period, Revised									10 years
Asset Recovery Damaged Property Costs, Noncurrent	$ 1,200								$ 1,200
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
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid	34,200								$ 34,200
Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	900								900
Maryland Division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	365								365
Sandpiper [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	608								608
Delaware natural gas division [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	1,500								1,500
Elkton Gas [Member]
Rates and Other Regulatory Activities [Line Items]
One time bill credit related to TCJA	$ 47								47
Elkton Gas [Member]
Rates and Other Regulatory Activities [Line Items]
Revenues									$ 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, 2020	Dec. 31, 2019
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 124,592	$ 78,551
Regulatory Liabilities		149,020	133,735
Self Insured Liabilities [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	533	873
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		4,422	2,724
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	2,673	1,437
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	45,315	36,767
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	90,845	89,191
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		1,541	75
Storm Cost Recovery, Interest
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		3,353
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[4]	2,078	5,144
Under-recovered GRIP Revenue [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[5]	278	0
Regulatory Liabilities	[5]	338	2,668
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	17,716	16,311
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[4]	23,054	20,881
Environmental Regulatory Assets And Expenditures [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	1,743	2,241
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[8]	28,755	30,329
Loss on Reacquired Debt [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	795	869
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		3,928	$ 2,776
COVID-19 Deferred Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		1,925
Deferred Storm Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		44,320
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34,200
Regulatory Liabilities		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] See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

[3] ) 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.

[4] 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.

[5] 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.

[6] The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the de-risking of the Chesapeake Pension Plan pursuant to an order from the FERC that allowed us to defer Eastern Shore's portion. See Note 17, Employee Benefit Plans, for additional information.

[7] 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.

[8] 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.

[9] 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.

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Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2020	Dec. 31, 2019
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 149,020	$ 133,735
Eastern Shore Gas Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	34,190
Delaware natural gas division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	12,728
Maryland Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,970
Sandpiper [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,713
Central Florida Gas Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	8,184
Florida Public Utilities Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	19,257
Fort Meade and Indiantown Divisions [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	309
FPU electric division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	6,694
Elkton Gas [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 1,124

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Environmental Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2020 USD ($) site	Dec. 31, 2019 USD ($)
Environmental Commitments And Contingencies [Line Items]
Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 4,299,000	$ 6,468,000
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
Winter Haven Florida | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Remediation Expense	425,000
Seaford | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	500,000
Seaford | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	200,000
FPU
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	5,900,000	8,000,000.0
Approval of recovery of environmental costs	14,000,000.0
Environmental costs recovered	12,400,000	11,900,000
FPU | Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	$ 1,600,000	$ 2,100,000

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Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2020 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	$ 69,459
Total purchase obligations for 2019 - 2020	81,841
Total purchase obligations for 2021 - 2022	69,420
Total purchase obligations thereafter	201,504
Aggregate guaranteed amount	20,000
Guarantor Obligations, Current Carrying Value	5,700
Amount of letter of credit to our current primary insurance company	$ 4,800
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, 2020 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 69,459
Purchase Obligation, Due in Second and Third Year	81,841
Purchase Obligation, Due in Fourth and Fifth Year	69,420
Purchase Obligation, Due after Fifth Year	201,504
Purchase Obligation	$ 422,224

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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, 2020	Sep. 30, 2020	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Disclosure Quarterly Financial Data Schedule Of Quarterly Financial Information [Abstract]
Revenues	$ 137,038	$ 101,419	$ 97,051	$ 152,690	$ 131,974	$ 92,626	$ 94,542	$ 160,464	$ 488,198	$ 479,605	$ 490,316
Operating Income	35,206	17,406	17,977	42,134	29,641	14,357	18,165	44,122	112,723	106,285	94,844
Net Income	22,352	9,261	10,956	28,930	22,564	5,621	8,304	28,663	71,498	65,153	56,580
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	21,661	9,280	10,661	29,041	17,123	6,251	8,914	28,811	70,642	61,100	56,968
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	$ 691	$ (19)	$ 125	$ (111)	39	$ (630)	$ (610)	$ (148)	686	(1,349)	$ (388)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax					$ 5,402				$ 170	$ 5,402
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.24	$ 0.56	$ 0.65	$ 1.77	$ 1.05	$ 0.38	$ 0.54	$ 1.76	$ 4.23	$ 3.73	$ 3.48
Earnings per share:
Basic (in usd per share)	1.28	0.56	0.67	1.76	1.38	0.34	0.51	1.75	4.28	3.97	3.46
Income (Loss) from Continuing Operations, Per Diluted Share	1.24	0.56	0.64	1.77	1.04	0.38	0.54	1.75	4.21	3.72	3.47
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share	0.04	0	0.02	(0.01)	0.33	(0.04)	(0.04)	(0.01)	0.05	0.24	(0.02)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0.04	0	0.02	(0.01)	0.33	(0.04)	(0.03)	(0.01)	0.05	0.24	(0.02)
Diluted (in usd per share)	$ 1.28	$ 0.56	$ 0.66	$ 1.76	$ 1.37	$ 0.34	$ 0.50	$ 1.74	$ 4.26	$ 3.96	$ 3.45

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Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 1,058	$ 876
Additions, Charged to Income	1,392	1,119
Additions, Other Accounts	278	133
Deductions	(1,391)	(1,070)
Balance at End of Year	$ 1,337	$ 1,058