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, 2019

☐ 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 ☒

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2019, 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 $1.5 billion.

The number of shares of Chesapeake Utilities Corporation's common stock outstanding as of February 20, 2020 was 16,407,017

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Part II and Part III, which Proxy Statement shall be filed with the Securities and Exchange Commission within 120 days after the end of registrant's fiscal year ended December 31, 2019.

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2019

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	2
Item 1A. Risk Factors	10
Item 1B. Unresolved Staff Comments	16
Item 2. Properties	17
Item 3. Legal Proceedings	17
Item 4. Mine Safety Disclosures	17
Part II	18
Item 5. Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	18
Item 6. Selected Financial Data	20
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	22
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	41
Item 8. Financial Statements and Supplementary Data	43
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	95
Item 9A. Controls and Procedures	95
Item 9B. Other Information	96
Part III	96
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance	96
Item 11. Executive Compensation	96
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	96
Item 13. Certain Relationships and Related Transactions, and Director Independence	96
Item 14. Principal Accounting Fees and Services	96
Part IV	96
Item 15. Exhibits, Financial Statement Schedules	96
Item 16. Form 10-K Summary	102
Signatures	102

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

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

CDD: Cooling Degree-Day

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

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 or below 65 degrees Fahrenheit

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

DFS: Dominion Field Services, Inc., a subsidiary of Dominion Energy, Inc.

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's OnSight Services, LLC

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 Chesapeake Utilities

FPL: Florida Power & Light Company, an unaffiliated electric company that supplies electricity to FPU

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

GAAP: Generally Accepted Accounting Principles

Gas South: Gas South LLC

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

Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU

HDD: Heating Degree Day

MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which Chesapeake Utilities has entered into a Shelf Agreement

MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use

MTM: Mark-to-Market (fair value accounting)

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

NJRES: New Jersey Resource Energy Services Company a subsidiary of New Jersey Resources Inc.

NYL: NYL Investors LLC, an institutional debt investment management firm, with which Chesapeake Utilities has 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 division of Tampa Electric Company

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

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

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

Rayonier: Rayonier Performance Fibers, LLC, the company that owns the property on which Eight Flags' CHP plant is located and a customer of the steam generated by the CHP plant

Revolver: Our unsecured revolving credit facility with certain lenders

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

SEC: Securities and Exchange Commission

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

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

Shelf Agreement: An agreement entered into by Chesapeake Utilities and a counterparty pursuant to which Chesapeake Utilities may request that the counterparty purchase our unsecured senior debt with a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance

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

SICP: 2013 Stock and Incentive Compensation Plan

TCJA: Tax Cuts and Jobs Act enacted on December 22, 2017

TETLP: Texas Eastern Transmission, LP

UET: United Energy Trading, LLC

U.S.: The United States of America

Xeron: Xeron, Inc., an inactive subsidiary of Chesapeake Utilities

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 wholly-owned 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 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 and electricity;

• 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 electricity, natural gas, 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 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; and

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies.

Chesapeake Utilities Corporation 2019 Form 10-K Page 1

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, propane and electricity; the transmission of natural gas; the generation of electricity and steam, and in providing related services to our customers.

Our strategy is to consistently produce industry leading total shareholder return by profitably investing capital into opportunities that leverage our skills and expertise in energy distribution and transmission to achieve high levels of service and growth. The key elements of our strategy include:

•

capital investment in growth opportunities that generate our target returns;

•

expanding our energy distribution and transmission operations within our existing service areas as well as into new geographic areas;

•

providing new services in our current service areas;

•

expanding our footprint in potential growth markets through strategic acquisitions that complement our businesses;

•

entering new energy markets and businesses that complement our existing operations and growth strategy; and

•

operating as a customer-centric full-service energy supplier/partner/provider, while providing safe and reliable service.

Our employees strive to build meaningful connections that generate opportunities to grow our businesses, develop new markets, and enrich the communities in which we live, work and serve.

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, 2019 and total assets as of December 31, 2019, 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 (Delaware division, Maryland division and Sandpiper Energy)	Delaware/Maryland	$	9,873	$	280,002
Central Florida Gas and FPU	Florida	13,721		420,483
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	17,965		447,041
Peninsula Pipeline	Florida	5,571		115,685
Electric Distribution
FPU	Florida	640		170,855
Total Regulated Energy		$	47,770	$	1,434,066

Revenues in this operating 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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 2

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 our underground distribution system in Worcester County, which we are in the process of converting to natural gas. 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.

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, 2019:

	Delmarva Natural Gas Distribution				Florida Natural Gas Distribution (2)				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	62,708	60	%	$	38,248	34	%	$	45,738		59	%
Commercial	33,070		32	%	33,126		30	%	38,254			49	%
Industrial	8,314		8	%	37,202		34	%	2,128			3	%
Other (1)	152		<1%		2,327		2	%	(8,704		)	(11	)%
Total Operating Revenues	$	104,244	100	%	110,903		100	%	$	77,416		100	%
Volumes (in Dts for natural gas/KW Hours for electric)
Residential	3,871,032		29	%	1,744,486		4	%	306,445			47	%
Commercial	3,776,388		29	%	6,190,350		14	%	310,856			49	%
Industrial	5,358,474		40	%	32,736,870		76	%	27,929			4	%
Other	220,541		2	%	2,574,925		6	%	—			—	%
Total Volumes	13,226,435		100	%	43,246,631		100	%	645,230			100	%
Average Number of Customers (3)
Residential	73,995		91	%	74,915		90	%	24,573			77	%
Commercial	7,097		9	%	5,478		7	%	7,243			23	%
Industrial	169		<1%		2,453		3	%	2			<1%
Other	15		<1%		12		<1%		—			—	%
Total Average Number of Customers	81,276		100	%	82,858		100	%	31,818			100	%

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

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

⁽³⁾ Average number of customers is based on the twelve-month average for the year ended December 31, 2019.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 3

The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, 2019, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, 2019:

	Eastern Shore				Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated (1)	$	24,709	33	%	$	14,003	85	%
Local distribution companies - non-affiliated	25,171		35	%	840		5	%
Commercial and industrial - affiliated	—		—	%	1,120		7	%
Commercial and industrial - non-affiliated	22,527		31	%	490		3	%
Other (2)	516		1	%	—		—	%
Total Operating Revenues	$	72,923	100	%	$	16,453	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	125,152		42	%	243,500		95	%
Local distribution companies - non-affiliated	76,619		26	%	4,825		2	%
Commercial and industrial - affiliated	—		—	%	1,500		1	%
Commercial and industrial - non-affiliated	96,348		32	%	5,100		2	%
Total Contracted firm transportation capacity	298,119		100	%	254,925		100	%
Design day capacity (in Dts/d)	298,119		100	%	254,925		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 for 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. The table reflects rate increases and rates of return approved prior to the enactment of the TCJA on December 22, 2017. See Item 8, Financial Statements and Supplementary Data (Note 19, Rates and Other Regulatory Activities and Note 12, Income Taxes 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	Chesapeake's Florida natural gas division	FPU	FPU	Eastern Shore
Regulatory Agency	Delaware PSC	Maryland PSC	Maryland PSC	Florida PSC	Florida PSC	Florida PSC	FERC
Effective date - Last Rate Order	01/01/2017	12/1/2007	12/01/2019	01/14/2010	01/14/2010(1)	01/03/2018	08/01/2017
Rate Base (in Rates)	Not stated	Not stated	Not stated	$46,680,000	$68,940,000	$11,850,000	Not stated
Annual Rate Increase Approved	$2,250,000	$648,000	N/A(2)	$2,540,000	$7,970,000	$1,560,000	$9,800,000
Capital Structure (in rates)(3)*	Not stated	LTD: 42.00% STD: 5.00% Equity: 53.00%	Not stated	LTD: 30.63% STD: 6.26% Equity: 43.49% Other: 19.62%	LTD: 30.75% Equity: 46.67% Other: 22.58%	LTD: 21.91% STD: 23.50% Equity: 54.59%	Not stated
Allowed Return on Equity	9.75% (4)	10.75%(4)	Not Stated (5)	10.80%(4)	10.85%(4)	10.25%(4), (6)	Not Stated
TJCA Refund Status associated with customer rates	Refunded	Refunded	Refunded	Retained	Retained	Refunded	Refunded

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

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

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

⁽⁴⁾ Allowed after-tax return on equity.

Chesapeake Utilities Corporation 2019 Form 10-K Page 4

⁽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. The FPU electric division could not file for a base rate increase prior to December 2019, unless its allowed return on equity was below the authorized range and it experienced an unanticipated and unforeseen event that impacted the annual revenue requirement in excess of $800,000 within any contiguous four-month period.

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

In October 2018, Hurricane Michael passed through FPU’s electric distribution service territory in Northwest Florida. The hurricane caused widespread and severe damage to FPU’s infrastructure resulting in 100 percent of its customers in the service territory losing electrical service. FPU expended more than $65.0 million to restore service, which has been recorded as new plant and equipment, charged against FPU’s accumulated depreciation or charged against FPU’s storm reserve. While there is a short-term negative impact, the storm is not expected to have a significant impact on our financial results going forward, assuming permanent recovery is granted through the regulatory process.

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 a regulatory asset 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 the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC on November 5, 2019 and interim rate increases became effective January 2, 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 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’s surcharge to expand natural gas service in eastern Sussex County; Maryland's surcharge to fund natural gas conversions and system improvement 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.

Operation(s)/Division(s)	Jurisdiction	Infrastructure mechanism	Revenue normalization
Delaware division	Delaware	Yes	No
Maryland division	Maryland	No	Yes
Sandpiper Energy	Maryland	Yes	Yes
FPU and Central Florida Gas natural gas divisions	Florida	Yes	No
FPU electric division	Florida	Yes	No

Weather

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

Competition

Natural Gas Distribution

While our natural gas distribution operations do not compete directly with other distributors of natural gas for residential and commercial customers in our service areas, we do compete with other natural gas suppliers and alternative fuel providers for sales to industrial customers. Large customers could bypass our natural gas distribution systems and connect directly to 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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 5

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 pipeline companies to provide service to large industrial, generation and distribution customers, primarily in the northern portion of 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, flexibility and service offerings 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.

The Delmarva natural gas distribution systems are directly connected to Eastern Shore’s pipeline, which has connections to the other pipelines that provide us with transportation and storage. These operations can also use propane-air and liquefied natural gas peak-shaving equipment to serve customers. Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of the sale of PESCO's assets and contracts, effective October 1, 2019, these agreements are now managed by NJRES. 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 the Peoples Gas System division of Tampa Electric Company ("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 one year term beginning July 2019 through July 2020 with the expectation that long-term agreements will then be executed for a 10-year term commencing on or about July 2020.

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	125,152	2020-2028
	Columbia Gas(1)	15,160	2020-2024
	Transco(1)	27,732	2019-2028
	TETLP(1)	50,000	2027
Florida Natural Gas Distribution	Gulfstream(2)	10,000	2022
	FGT	53,409 - 84,817	2020-2041
	Peninsula Pipeline	237,500	2033-2048
	Peoples Gas	2,660	2024-2035
	Florida Southeast Connection	5,000	2045
	Southern Natural Gas Company	5,000	2020

⁽¹⁾ Transcontinental Gas Pipe Line Company, LLC ("Transco"), Columbia Gas Transmission, LLC ("Columbia Gas") and Texas Eastern Transmission, LP ("TETLP") are interstate pipelines interconnected with Eastern Shore's pipeline

Chesapeake Utilities Corporation 2019 Form 10-K Page 6

⁽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.

Electric Distribution

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

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

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

Unregulated Energy

In the third and fourth quarter of 2019, we reached agreements with four entities to sell PESCO's assets and contracts. These transactions closed during the fourth quarter of 2019. As a result of the sale, 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. The following table presents net income for the year ended December 31, 2019 and total assets as of December 31, 2019, 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)	Delaware, Maryland, Virginia, Pennsylvania, Florida	$	6,297	$	134,791
Energy Transmission (Aspire Energy)	Ohio	3,822		94,124
Energy Generation (Eight Flags)	Florida	1,908		38,569
Marlin Gas Services	The Eastern U.S.	986		27,269
Other	Other	382		171
Total		$	13,395	$	294,924

Propane Operations

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 7

Propane Operations - Operational Highlights

For the year ended December 31, 2019, operating revenues, volumes sold and average number of customers by customer class for our Mid-Atlantic and Florida propane operations were as follows:

	Operating Revenues (in thousands)								Volumes (in thousands of gallons)						Average Number of Customers (1)
	Mid-Atlantic				Florida				Mid-Atlantic			Florida			Mid-Atlantic (2)			Florida
Residential bulk	$	26,190	30	%	$	6,639	34	%	10,491	18	%	1,489	23	%	27,729	67	%	10,416	60	%
Residential metered	9,407		11	%	4,852		25	%	4,146	7	%	818	13	%	9,863	23	%	5,922	34	%
Commercial bulk	20,079		23	%	4,506		23	%	13,979	24	%	2,372	36	%	4,418	10	%	934	5	%
Commercial metered	—		—	%	1,971		10	%	—	—	%	814	13	%	—	—	%	271	1	%
Wholesale	21,154		24	%	862		4	%	25,629	44	%	983	15	%	26	<1%		6	<1%
AutoGas	4,806		6	%	—		—	%	3,895	7	%	—	—	%	86	<1%		—	—	%
Other (3)	6,822		6	%	676		4	%	—	—	%	—	—	%	—	—	%	—	—	%
Total	$	88,458	100	%	$	19,506	100	%	58,140	100	%	6,476	100	%	42,122	100	%	17,549	100	%

⁽¹⁾ Average number of customers is based on a twelve-month average for the year ended December 31, 2019.

⁽²⁾ Average numbers of customers for the Mid-Atlantic propane operations includes approximately 5,200 customers added in December 2019 in the acquisition of certain propane operating assets of Boulden. 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.

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 7.4 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 21,000 end-use customers. Aspire Energy purchases natural gas to serve these customers from conventional producers in the Marcellus and Utica natural gas production areas. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

Chesapeake Utilities Corporation 2019 Form 10-K Page 8

For the twelve-month period ended December 31, 2019, 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	$	13,391	41	%	2,607	41	%
Supply to CGC	12,544		39	%	1,615	25	%
Supply to Marketers - affiliated	1,952		6	%	929	15	%
Supply to Marketers - unaffiliated	2,307		7	%	1,096	17	%
Other (including natural gas gathering and processing)	2,299		7	%	120	2	%
Total	$	32,493	100	%	6,367	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 compressed natural gas (“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. 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 steel tube CNG trailers, composite CNG trailers, mobile compression equipment 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 leverages its patented technology to potentially serve liquefied natural gas and renewable natural gas transportation needs.

Other Businesses and Eliminations

Other businesses and eliminations consists primarily of subsidiaries that own real estate leased to affiliates, eliminations of inter-segment revenue and corporate costs which are not directly attributable to a specific business unit. See Item 8, Financial Statements and Supplementary Data (Note 6, Segment Information, in the consolidated financial statements) for more information.

Environmental Matters

See Item 8, Financial Statements and Supplementary Data (see Note 20, Environmental Commitments and Contingencies, in the consolidated financial statements).

Employees

As of December 31, 2019, we had a total of 955 employees, 120 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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 9

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 report.

Name	Age	Officer Since	Offices Held During the Past Five Years
Jeffry M. Householder	62	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	53	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) Corporate Secretary (June 2005 - March 2015)
James F. Moriarty	62	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	61	2010	Senior Vice President (February 2019 - present) President FPU (February 2019 - present) Vice President Gas Operations and Business Development Florida Business Units (July 2010 - February 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 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;

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

•Corporate Governance Guidelines on Director Independence.

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 report for an additional discussion of these and other related factors that affect our operations and/or financial performance.

Chesapeake Utilities Corporation 2019 Form 10-K Page 10

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 earnings 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, term loans, the Revolver and our committed short-term lines of credit 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.

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 lines of credit 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 commitments; and (vi) lack of available and qualified third-party contractors which could impact the timely construction of new facilities.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 11

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 division and Sandpiper Energy 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 earnings, financial condition and results of operations. 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.

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,

Chesapeake Utilities Corporation 2019 Form 10-K Page 12

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.

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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 13

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 one pipeline system, FGT, for most of its natural gas supply and transmission. Our Florida electric operation secures electricity from external parties. Any continued interruption of service from these suppliers could adversely affect our ability to meet the demands of our customers, which could negatively impact our earnings, financial condition and results of operations.

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

Fluctuating commodity prices may affect our earnings and financing costs because our propane operations use derivative instruments, including forwards, futures, swaps, puts, and calls, to hedge price risk. While we have risk management policies and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our results of operations, cash flows, and financial condition may be adversely affected.

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 14

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 future 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.

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).

Chesapeake Utilities Corporation 2019 Form 10-K     Page 15

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 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 products. Federal or state 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 lawsuits related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate change, which could impact adversely our business, results of operations and cash flows.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

Chesapeake Utilities Corporation 2019 Form 10-K Page 16

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.

Regulated Energy Segment

We own approximately 1,690 miles of natural gas distribution mains (together with related service lines, meters and regulators) in Kent, New Castle and Sussex Counties, Delaware; and Caroline, Cecil, Dorchester, Wicomico and Worcester Counties, Maryland. We own approximately 2,860 miles of natural gas distribution mains (and related equipment) in Brevard, Broward, Citrus, Clay, DeSoto, Escambia, Gadsden, Gilchrist, Hernando, Hillsborough, Holmes, Indian River, Jackson, Liberty, Marion, Martin, Nassau, Okeechobee, Osceola, Palm Beach, Polk, Seminole, Suwannee, Union, Volusia and Washington Counties, Florida. In addition, we have adequate gate stations to handle receipt of the gas into each of the distribution systems. We also own approximately 50 miles of underground propane distribution mains in Worcester County, Maryland and facilities in Delaware and Maryland, which we use for propane-air injection during periods of peak demand.

We own and operate approximately 500 miles of natural gas transmission pipeline, extending from interconnects at Daleville, Honey Brook and Parkesburg, Pennsylvania; and Hockessin, Delaware, to 93 delivery points in southeastern Pennsylvania, Delaware and the eastern shore of Maryland and approximately 90 miles of natural gas transmission pipeline in Escambia, Indian River, Palm Beach, Pensacola, Polk, Suwannee and Volusia Counties, Florida. We also own approximately 45 percent of the 16-mile natural gas pipeline extending from the Duval/Nassau County line to Amelia Island in Nassau County, Florida. The remaining 55 percent of the natural gas pipeline is owned by Peoples Gas.

We own and operate approximately 16 miles of electric transmission line located in Nassau County, Florida and approximately 900 miles of electric distribution line in Calhoun, Jackson, Liberty and Nassau Counties, Florida.

Unregulated Energy Segment

We own bulk propane storage facilities, with an aggregate capacity of approximately 7.4 million gallons, in Delaware, Maryland, Virginia, Pennsylvania, and Florida. These facilities are located on real estate that is either owned or leased by us.

We own approximately 190 miles of underground propane distribution mains in New Castle County, Delaware; Cecil, Dorchester, Princess Anne, Queen Anne's, Somerset, Talbot, Wicomico and Worcester Counties, Maryland; Chester and Delaware Counties, Pennsylvania; and Alachua, Brevard, Broward, Citrus, Duval, Hillsborough, Marion, Nassau, Orange, Palm Beach, Polk, Seminole, St. Johns and Volusia Counties, Florida.

We own 16 natural gas gathering systems and approximately 2,700 miles of pipeline in central and eastern Ohio.

Florida liens

All of the assets owned by FPU are subject to a lien in favor of the holders of its first mortgage bond securing its indebtedness under its Mortgage Indenture and Deed of Trust. These assets are not subject to any other lien as all other debt is unsecured. FPU owns offices and facilities in the following locations: Alachua, Brevard, Broward, Citrus, Hendry, Jackson, Nassau, Okeechobee, Palm Beach and Volusia Counties, Florida. The FPU assets subject to the lien also include: 2,000 miles of natural gas distribution mains (and related equipment) in its service areas; 16 miles of electric transmission line located in Nassau County, Florida; 900 miles of electric distribution line located in Calhoun, Jackson, Liberty and Nassau Counties in Florida; propane storage facilities with a total capacity of 1.1 million gallons, located in south, central and north Florida; and 65 miles of underground propane distribution mains in Alachua, Brevard, Broward, Citrus, Duval, Hillsborough, Indian River, Marion, Martin, Nassau, Orange, Palm Beach, Polk, Seminole, St. Johns and Volusia Counties, Florida.

ITEM 3. Legal Proceedings.

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

ITEM 4. Mine Safety Disclosures.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 17

Not applicable.

PART II

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

Common Stock Dividends and Stockholder Information:

Chesapeake Utilities common stock is traded on the New York Stock Exchange ("NYSE") under the ticker symbol CPK. As of February 20, 2020, we had 2,177 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $1.585 per share in 2019 and $1.435 per share in 2018, and have paid a cash dividend to our common stock stockholders for 59 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. FPU’s first mortgage bonds, which are due in 2022, contain a similar restriction that limits the payment of dividends by FPU. 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, 2019.

	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, 2019 through October 31, 2019 (1)	406	$	94.79	—	—
November 1, 2019 through November 30, 2019	—	—		—	—
December 1, 2019 through December 31, 2019	—	—		—	—
Total	406	$	94.79	—	—

⁽¹⁾ In October 2019, we purchased 406 shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts for certain directors and senior executives under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8, Financial Statements and Supplementary Data (see Note 17, Employee Benefit Plans, in the consolidated financial statements).

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 18

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, 2019, 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, 2014 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.

	2014		2015		2016		2017		2018		2019
Chesapeake Utilities	$	100	$	117	$	141	$	168	$	177	$	212
Industry Index	$	100	$	111	$	134	$	154	$	165	$	195
S&P 500 Index	$	100	$	101	$	113	$	138	$	132	$	174

Chesapeake Utilities Corporation 2019 Form 10-K     Page 19

ITEM 6. SELECTED FINANCIAL DATA

	For the Year Ended December 31,
	2019			2018			2017			2016			2015
Operating (1)
(in thousands)
Revenues
Regulated Energy	$	343,006		$	345,281		$	326,310		$	305,689		$	301,902
Unregulated Energy	154,150			161,904			140,076			108,364			105,861
Other businesses and eliminations	(17,552		)	(16,869		)	(16,740		)	(9,318		)	(3,920		)
Total revenues	$	479,604		$	490,316		$	449,646		$	404,735		$	403,843
Operating income from Continuing Operations
Regulated Energy	$	86,584		$	79,215		$	74,584		$	71,515		$	62,137
Unregulated Energy	19,939			17,124			14,941			11,732			14,244
Other businesses and eliminations	(236		)	(1,496		)	205			402			418
Total operating income from Continuing Operations	$	106,287		$	94,843		$	89,730		$	83,649		$	76,799
Income from Continuing Operations	$	61,142		$	56,862		$	60,326		$	43,284		$	39,813
Income/(Loss) from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)	1,391			1,327
Gain on sale of Discontinued Operations, Net of Tax	5,402			—			—			—			—
Net Income	$	65,153		$	56,580		$	58,124		$	44,675		$	41,140
Assets
(in thousands)
Gross property, plant and equipment (1)	$	1,746,532		$	1,568,441		$	1,310,993		$	1,175,595		$	1,007,489
Net property, plant and equipment (1)	$	1,463,797		$	1,353,520		$	1,124,938		$	986,664		$	854,951
Total assets (2)	$	1,783,198		$	1,693,671		$	1,414,934		$	1,229,219		$	1,067,421
Capital expenditures (3)	$	198,986		$	282,861		$	179,337		$	169,376		$	195,261
Capitalization
(in thousands)
Stockholders’ equity	$	561,577		$	518,439		$	486,294		$	446,086		$	358,138
Long-term debt, net of current maturities	440,168			316,020			197,395			136,954			149,006
Total capitalization	$	1,001,745		$	834,459		$	683,689		$	583,040		$	507,144
Current portion of long-term debt	45,600			11,935			9,421			12,099			9,151
Short-term debt	247,371			294,458			250,969			209,871			173,397
Total capitalization and short-term financing	$	1,294,716		$	1,140,852		$	944,079		$	805,010		$	689,692

(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 2015 through 2018, include assets held for sale for PESCO.

(3) As a result of the sale of PESCO's assets and contracts during the fourth quarter of 2019, capital expenditures for 2015 to 2018 were recast to exclude amounts associated with PESCO.

Chesapeake Utilities Corporation 2019 Form 10-K Page 20

	For the Year Ended December 31,
	2019			2018			2017			2016			2015
Common Stock Data and Ratios
Basic Earnings Per Share:
Earnings Per Share from Continuing Operations	$	3.73		$	3.48		$	3.69		$	2.78		$	2.64
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)	0.09			0.09
Basic Earnings Per Share	$	3.97		$	3.46		$	3.56		$	2.87		$	2.73
Diluted Earnings Per Share
Earnings Per Share from Continuing Operations	$	3.72		$	3.47		$	3.68		$	2.77		$	2.63
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)	0.09			0.09
Diluted Earnings Per Share	$	3.96		$	3.45		$	3.55		$	2.86		$	2.72
Diluted earnings per share growth - 1 year (1)	7.2		%	(5.7		)%	32.9		%	5.3		%	11.0		%
Diluted earnings per share growth - 5 year (1)	9.4		%	10.0		%	14.3		%	9.0		%	8.9		%
Diluted earnings per share growth - 10 year (1)	11.3		%	11.3		%	11.5		%	9.8		%	8.9		%
Return on average equity (1)	11.3		%	11.2		%	13.0		%	11.0		%	11.7		%
Common equity / total capitalization	56.1		%	62.1		%	71.1		%	76.5		%	70.6		%
Common equity / total capitalization and short-term financing	43.4		%	45.4		%	51.5		%	55.4		%	51.9		%
Capital expenditures / average total capitalization (1)	21.7		%	37.3		%	30.2		%	31.1		%	29.5		%
Book value per share	$	34.23		$	31.65		$	29.75		$	27.36		$	23.45
Weighted average number of shares outstanding	16,398,443			16,369,616			16,336,789			15,570,539			15,094,423
Shares outstanding at year-end	16,403,776			16,378,545			16,344,442			16,303,499			15,270,659
Cash dividends declared per share	$	1.59		$	1.44		$	1.28		$	1.20		$	1.13
Dividend yield (annualized) (2)	1.7		%	1.8		%	1.7		%	1.8		%	2.0		%
Book yield (3)	4.8		%	4.7		%	4.5		%	4.7		%	5.1		%
Payout ratio (1)(4)	42.6		%	41.4		%	34.7		%	43.2		%	42.8		%
Additional Data
Customers
Natural gas distribution	164,134			158,387			153,537			149,179			144,872
Electric distribution	31,818			32,185			32,026			31,695			31,430
Propane operations	59,671			56,915			54,760			54,947			53,682
Total employees	955			983			945			903			832

⁽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 2019 Form 10-K     Page 21

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 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 previously announced sale of assets and contracts of PESCO and recorded a pre-tax gain of $7.3 million ($5.4 million after tax). As a result, PESCO’s results for all periods presented have been separately reported as discontinued operations and its assets and liabilities have been reclassified as held for sale where applicable.

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 2019 Form 10-K Page 22

OVERVIEW AND HIGHLIGHTS

(in thousands except per share data)							Increase									Increase
For the Year Ended December 31,	2019			2018			(decrease)			2018			2017			(decrease)
Business Segment:
Regulated Energy	$	86,584		$	79,215		$	7,369		$	79,215		$	74,584		$	4,631
Unregulated Energy	19,939			17,124			2,815			17,124			14,941			2,183
Other businesses and eliminations	(236		)	(1,496		)	1,260			(1,496		)	205			(1,701		)
Operating Income	106,287			94,843			11,444			94,843			89,730			5,113
Other expense, net	(1,830		)	(603		)	(1,227		)	(603		)	(2,204		)	1,601
Interest charges	22,224			16,146			6,078			16,146			12,530			3,616
Income from Continuing Operations Before Income Taxes	82,233			78,094			4,139			78,094			74,996			3,098
Income Taxes on Continuing Operations	21,091			21,232			(141		)	21,232			14,670			6,562
Income from Continuing Operations	61,142			56,862			4,280			56,862			60,326			(3,464		)
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(1,109		)	(282		)	(2,202		)	1,920
Gain on sale of Discontinued Operations, Net of tax	5,402			—			5,402			—			—			—
Net Income	$	65,153		$	56,580		$	8,573		$	56,580		$	58,124		$	(1,544	)
Basic Earnings Per Share of Common Stock
Earnings Per Share from Continuing Operations	$	3.73		$	3.48		$	0.25		$	3.48		$	3.69		$	(0.21	)
Earnings/(loss) Per Share from Discontinued Operations	0.24			(0.02		)	0.26			(0.02		)	(0.13		)	0.11
Basic Earnings Per Share of Common Stock	$	3.97		$	3.46		$	0.51		$	3.46		$	3.56		$	(0.10	)
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	3.72		$	3.47		$	0.25		$	3.47		$	3.68		$	(0.21	)
Earnings/(loss) Per Share from Discontinued Operations	0.24			(0.02		)	0.26			(0.02		)	(0.13		)	0.11
Diluted Earnings Per Share of Common Stock	$	3.96		$	3.45		$	0.51		$	3.45		$	3.55		$	(0.10	)

Chesapeake Utilities Corporation 2019 Form 10-K     Page 23

2019 compared to 2018

Key variances in continuing operations between 2019 and 2018 included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Year ended December 31, 2018 Reported Results from Continuing Operations	$	78,094		$	56,862		$	3.47
Adjusting for unusual items:
Decreased customer consumption - primarily due to warmer weather	(4,852		)	(3,607		)	(0.22		)
Nonrecurring separation expenses associated with a former executive	1,548			1,421			0.09
2018 retained tax savings for certain Florida natural gas operations*	1,321			990			0.06
Lower wholesale propane margins due to non-recurring impact of the 2018 Bomb Cyclone	(866		)	(644		)	(0.04		)
Pension settlement expense associated with the de-risking of the Chesapeake Utilities Pension Plan (1)	(693		)	(515		)	(0.03		)
	(3,542		)	(2,355		)	(0.14		)
Increased (Decreased) Gross Margins:
Eastern Shore and Peninsula Pipeline service expansions (including related Florida natural gas distribution operation expansions)*	12,600			9,369			0.57
Margin contribution from Unregulated Energy acquisitions*	6,830			5,078			0.31
Natural gas distribution growth (excluding service expansions)	4,718			3,508			0.21
Increased retail propane margins	3,229			2,401			0.15
Retained tax savings for certain Florida natural gas operations in 2019 associated with TCJA*	1,023			760			0.05
Sandpiper's margin primarily from natural gas conversions	983			731			0.04
Higher Aspire Energy margins from rate increases	518			385			0.02
Florida GRIP*	508			378			0.02
Higher Eight Flags margin from increased production	418			311			0.02
	30,827			22,921			1.39
(Increased) Decreased Other Operating Expenses (Excluding Cost of Sales):
Depreciation, amortization and property tax costs due to new capital investments	(5,727		)	(4,258		)	(0.26		)
Operating expenses for Unregulated Energy acquisitions	(4,636		)	(3,447		)	(0.21		)
Payroll, benefits and other employee-related expenses	(4,204		)	(3,126		)	(0.19		)
Insurance expense (non-health) - both insured and self-insured components	(2,267		)	(1,685		)	(0.10		)
Stock compensation expense associated with leadership transitions during 2019	(1,114		)	(828		)	(0.05		)
Vehicle expenses due to additional fleet to support growth	(309		)	(230		)	(0.01		)
Timing of excavation and inspection activities in 2018 to comply with the Company's integrity management program	1,733			1,289			0.08
Facilities and maintenance costs due to consolidation of facilities	581			432			0.03
	(15,943		)	(11,853		)	(0.71		)
Other income tax effects	—			816			0.05
Interest charges	(6,078		)	(4,519		)	(0.27		)
Net Other changes	(1,125		)	(730		)	(0.07		)
Year ended December 31, 2019 Reported Results from Continuing Operations	$	82,233		$	61,142		$	3.72

⁽¹⁾ In the fourth quarter of 2019, the Company executed a de-risking strategy for its Pension Plan. This amount reflects a portion of the cost of the pension settlement that was charged to expense as it was deemed not recoverable through the regulatory process.

* See the Major Projects and Initiatives table.

Chesapeake Utilities Corporation 2019 Form 10-K Page 24

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)	2017		2018		2019		2020		2021
Expansions:
2017 Eastern Shore System Expansion - including interim services	$	483	$	9,103	$	16,434	$	15,799	$	15,799
Northwest Florida Expansion (including related natural gas distribution services)	—		4,350		6,516		6,500		6,500
Western Palm Beach County, Florida Expansion	—		54		2,139		5,047		5,227
Del-Mar Energy Pathway - including interim services	—		—		731		2,512		4,100
Auburndale	—		—		283		679		679
Callahan Intrastate Pipeline	—		—		—		3,219		6,400
Guernsey Power Station	—		—		—		—		1,400
Total Expansions	483		13,507		26,103		33,756		40,105
Acquisitions:
Marlin Gas Services	—		110		5,410		6,400		7,000
Ohl Propane	—		—		1,200		1,236		1,250
Boulden Propane	—		—		329		4,000		4,200
Elkton Gas Company	—		—		—		TBD (4)		TBD
Total Acquisitions	—		110		6,939		11,636		12,450
Regulatory Initiatives:
Florida GRIP(1) (2)	13,454		13,020		13,528		14,858		15,831
Tax benefit retained by certain Florida entities(3)	—		—		2,740		1,400		1,500
Hurricane Michael regulatory proceeding	—		—		—		TBD		TBD
Total Regulatory Initiatives	13,454		13,020		16,268		16,258		17,331
Total	$	13,937	$	26,637	$	49,310	$	61,650	$	69,886

(1) All periods shown have been adjusted to reflect lower customer rates as a result of the TCJA. Lower customer rates are offset by the corresponding decrease in federal income tax expense and have no negative impact on net income.

(2) During 2019, we recorded a reduction in depreciation expense totaling $1.3 million, as a result of a Florida PSC approved depreciation study that lowered annual depreciation rates. We also recorded $0.6 million in lower GRIP margin due to a concurrent reduction in surcharge collected from customers as a result of the reduced depreciation rates.

(3) The amount disclosed for the year ended December 31, 2019 includes tax savings of $1.3 million for the year ended December 31, 2018. The tax savings were recorded in the first quarter of 2019 due to an order by the Florida PSC allowing reversal of a TCJA refund reserve, recorded in 2018, which increased gross margin for the year ended December 31, 2019 by that amount.

(4) The amount of margin to be generated by Elkton Gas Company in 2020 will depend, largely, on the date the acquisition closes. Further guidance will be provided during 2020 as the timing becomes certain.

Detailed Discussion of Major Projects and Initiatives

Expansions

2017 Eastern Shore System Expansion

Eastern Shore has completed the construction of a system expansion project that increased its capacity by 26 percent. The project generated $7.3 million in incremental gross margin, including margin from interim services, for the year ended December 31, 2019, compared to 2018. The project is expected to produce gross margin of approximately $15.8 million annually, from 2020 through 2022; and $13.2 million annually thereafter based on current customer capacity commitments.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 25

Northwest Florida Expansion

In May 2018, Peninsula Pipeline completed construction of transmission lines, and our Florida natural gas division completed construction of lateral distribution lines, to serve customers in Northwest Florida. The project generated incremental gross margin of $2.2 million during 2019 compared to 2018. The estimated annual gross margin from this project is $6.5 million for 2020 and beyond, with the opportunity for additional margin as the remaining capacity is sold.

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 $2.1 million during 2019 compared to 2018. We expect to complete the remainder of the project in phases through early 2020, and estimate that the project will generate gross margin of $5.0 million in 2020 and $5.2 million annually thereafter.

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 provide an additional 14,300 Dts/d of firm service to four customers, will provide additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and it will represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Interim services in advance of this project generated gross margin of $0.7 million for the year ended December 31, 2019. The estimated annual gross margin from this project is approximately $2.5 million in 2020, $4.1 million in 2021 and $5.1 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 constructed pipeline facilities in Polk County, Florida. Peninsula Pipeline will provide transportation service to the Florida Division of Chesapeake Utilities increasing both delivery capacity and downstream pressure as well as introducing a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. Peninsula Pipeline generated gross margin from this project of $0.3 million for the year ended December 31, 2019 and expects to generate annual gross margin of $0.7 million in 2020 and beyond.

Callahan Intrastate Pipeline

In May 2018, Peninsula Pipeline announced a plan to construct a jointly owned intrastate transmission pipeline in Nassau County, Florida with Seacoast Gas Transmission.  The 26-mile pipeline, having an initial capacity of 148,000 Dts/d, will serve growing demand in both Nassau and Duval Counties, Florida. The project is expected to be placed in-service during the third quarter of 2020 and is expected to generate gross margin for Peninsula Pipeline of $3.2 million in 2020 and $6.4 million annually thereafter.

Guernsey Power Station

Guernsey Power Station, LLC ("Guernsey Power Station") and our affiliate, Aspire Energy Express, LLC ("Aspire Energy Express"), entered into a precedent firm transportation capacity agreement whereby Guernsey Power Station will construct a power generation facility and Aspire Energy Express will provide 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 third quarter of 2020.  This project is expected to produce gross margin of approximately $1.4 million annually once placed into service in the first quarter of 2021. 

Acquisitions

Marlin Gas Services

In December 2018, Marlin Gas Services, our wholly-owned subsidiary, acquired certain operating assets of Marlin Gas Transport, a supplier of 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 generated incremental gross margin of $5.3 million in 2019 compared to 2018. We estimate that Marlin Gas Services will generate annual gross margin of approximately $6.4 million in 2020 and $7.0 million in 2021 and beyond. Marlin Gas Services continues to actively expand the territories it serves, as well as leverage its patented technology to serve liquefied natural gas transportation needs and to aid in the transportation of renewable natural gas from the supply sources to various pipeline interconnection points.

Chesapeake Utilities Corporation 2019 Form 10-K Page 26

Ohl Propane

In December 2018, Sharp acquired certain propane customers and operating assets of R. F. Ohl Fuel Oil, Inc. ("Ohl"). Located between two of Sharp's existing districts, Ohl provided propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania. The customers and assets acquired from Ohl have been assimilated into Sharp. The operations acquired from Ohl generated $1.2 million of incremental gross margin in 2019. We estimate that this acquisition will generate additional gross margin for Sharp in 2020 and beyond.

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 $0.3 million of incremental gross margin for 2019. We estimate that this acquisition will generate additional gross margin of approximately $4.0 million in 2020, and $4.2 million in 2021, with the potential for additional growth in future years.

Elkton Gas Company

In December 2019, we entered into an agreement with South Jersey Industries, Inc. ("SJI") to acquire Elkton Gas Company, which provides natural gas distribution service to approximately 7,000 residential and commercial customers in Cecil County, Maryland contiguous to our existing franchise territory in Cecil County. The acquisition is expected to close in the second half of 2020, subject to approval by the Maryland PSC.

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 $143.9 million of capital expenditures to replace 303 miles of qualifying distribution mains, including $16.7 million and $13.3 million of new pipes during 2019 and 2018, respectively. GRIP generated additional gross margin of $0.5 million in 2019 compared to 2018.

During 2019, we recorded a reduction in depreciation expense totaling $1.3 million, as a result of a Florida PSC approved depreciation study that lowered annual depreciation rates. We also recorded $0.6 million in lower GRIP margin due to a concurrent reduction in surcharges collected from customers as a result of the reduced depreciation rates.

Florida Tax Savings Related to the TCJA

In February 2019, the Florida PSC issued orders authorizing certain of our natural gas distribution operations to retain a portion of the tax savings associated with the lower federal tax rates resulting from the TCJA. In accordance with the PSC orders, we recognized $1.3 million in margin during the first quarter of 2019, reflecting the reversal of reserves recorded during 2018. We expect the annual savings beginning in 2019 to continue in future years, and recognized additional margin of $1.0 million during 2019.

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 100 percent of its customers in the Northwest Florida service territory losing electrical service. FPU expended more than $65.0 million to restore service as quickly as possible, which has been recorded as new plant and equipment, charged against FPU’s accumulated depreciation or charged against FPU’s storm reserve. Additionally, amounts currently being reviewed by the Florida PSC for regulatory asset treatment have been 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 (plant investment and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as a regulatory asset for items currently not allowed to be recovered through the storm reserve as well as the recovery of plant investment replaced as a result of the storm. FPU has proposed an overall return component on both the plant additions and regulatory assets. In the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC in November 2019 and interim rate increases were implemented effective January 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 2020.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 27

Other Major Factors Influencing Gross Margin

Weather and Consumption

Weather conditions accounted for decreased gross margin of $4.9 million in 2019 compared to 2018 and $3.4 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, 2019 compared to 2018.

HDD and CDD Information

	For the Years Ended December 31,
	2019		2018		Variance		2018		2017		Variance
Delmarva
Actual HDD	4,089		4,251		(162	)	4,251		3,800		451
10-Year Average HDD ("Normal")	4,323		4,379		(56	)	4,379		4,374		5
Variance from Normal	(234	)	(128	)			(128	)	(574	)
Florida
Actual HDD	619		780		(161	)	780		533		247
10-Year Average HDD ("Normal")	792		800		(8	)	800		818		(18	)
Variance from Normal	(173	)	(20	)			(20	)	(285	)
Ohio
Actual HDD	5,498		5,845		(347	)	5,845		5,126		719
10-Year Average HDD ("Normal")	5,983		5,823		160		5,823		5,914		(91	)
Variance from Normal	(485	)	22				22		(788	)
Florida
Actual CDD	3,200		3,105		95		3,105		3,013		92
10-Year Average CDD ("Normal")	2,939		2,889		50		2,889		2,865		24
Variance from Normal	261		216				216		148

Natural Gas Distribution Margin Growth

New customer growth for our natural gas distribution operations generated $4.7 million of additional margin in 2019. The average number of residential customers served on the Delmarva Peninsula and Florida increased by approximately 3.7 percent during 2019. Growth in commercial and industrial customers also contributed additional margin during 2019. The details are provided in the following table:

	Gross Margin increase
	For the Year Ended December 31, 2019
(in thousands)	Delmarva		Florida
Customer growth:
Residential	$	1,179	$	769
Commercial and industrial, excluding the impact of the Northwest Florida expansion project	664		2,106
Total customer growth	$	1,843	$	2,875

Chesapeake Utilities Corporation 2019 Form 10-K Page 28

REGULATED ENERGY

							Increase									Increase
For the Year Ended December	2019			2018			(decrease)			2018			2017			(decrease)
(in thousands)
Revenue	$	343,006		$	345,281		$	(2,275	)	$	345,281		$	326,310		$	18,971
Cost of sales	102,803			121,828			(19,025		)	121,828			118,769			3,059
Gross margin	240,203			223,453			16,750			223,453			207,541			15,912
Operations & maintenance	102,099			97,741			4,358			97,741			90,931			6,810
Gain from a settlement	(130		)	(130		)	—			(130		)	(130		)	—
Depreciation & amortization	35,227			31,876			3,351			31,876			28,554			3,322
Other taxes	16,423			14,751			1,672			14,751			13,602			1,149
Other operating expenses	153,619			144,238			9,381			144,238			132,957			11,281
Operating Income	$	86,584		$	79,215		$	7,369		$	79,215		$	74,584		$	4,631

2019 compared to 2018

Operating income for the Regulated Energy segment for 2019 was $86.6 million, an increase of $7.4 million, or 9.3 percent, compared to 2018. The increased operating income resulted from increased gross margin of $16.8 million, offset by $5.0 million in higher depreciation, amortization and other taxes and $4.4 million in higher operating and maintenance expenses. In February 2019, the Florida PSC issued a final order regarding the treatment of the TCJA impact, allowing us to retain the savings associated with lower federal tax rates for certain of our natural gas distribution operations. As a result, $1.3 million in reserves for customer refunds, recorded in 2018, were reversed in the first quarter of 2019. Excluding the impact of the reversal, gross margin and operating income for 2019 increased by $15.5 million and $6.1 million, or 6.9 percent and 7.7 percent, respectively.

Gross Margin

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

(in thousands)	Margin Impact
Eastern Shore and Peninsula Pipeline service expansions (including related Florida natural gas distribution operation expansions)	$	12,600
Natural gas distribution - customer growth (excluding service expansions)	4,718
2018 retained tax savings for certain Florida natural gas distribution operations	1,321
Retained tax savings for certain Florida natural gas operations in 2019 associated with TCJA	1,023
Sandpiper's margin primarily from natural gas conversions	983
Florida GRIP (1)	508
Decreased customer consumption - primarily due to warmer weather	(3,295		)
Other	(1,108		)
Year-over-year increase in gross margin	$	16,750

⁽¹⁾ In 2019, we recorded a reduction in depreciation expense totaling $1.3 million as a result of a Florida PSC approved depreciation study that lowered annual depreciation rates. We also recorded $0.6 million in lower GRIP margin due to a concurrent reduction in surcharge collected from customers as a result of the reduced depreciation rates.

The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.

Eastern Shore and Peninsula Pipeline Service Expansions (including new natural gas distribution service in Northwest Florida)

We generated additional gross margin of $12.6 million, primarily from the following natural gas service expansions:

• $7.3 million from Eastern Shore's services in conjunction with its 2017 System Expansion Project.

• $4.6 million generated from Peninsula Pipeline's Western Palm Beach County Pipeline, Northwest Pipeline Expansion and Auburndale Projects.

• $0.7 million generated from interim services in advance of Eastern Shore's Del-Mar Energy Pathway Project.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 29

Natural Gas Customer Growth

We generated additional gross margin of $4.7 million from natural gas customer growth. Gross margin increased by $2.9 million in Florida and $1.8 million on the Delmarva Peninsula in 2019 compared to 2018, due primarily to residential customer growth of 3.8 percent in Florida and 3.7 percent on the Delmarva Peninsula, as well as increases in the number of commercial and industrial customers served.

2018 Retained Tax Savings for Florida Natural Gas Operations

We generated additional gross margin of $1.3 million in 2019 compared to 2018, due to a final order from the Florida PSC allowing us to retain the tax savings associated with TCJA. Pursuant to the order, refund reserves recorded by our Florida natural gas businesses in 2018, were reversed in 2019. See Note 19, Rates and Other Regulatory Activities, for additional information.

Tax Reform Impact

We generated additional gross margin of $1.0 million in 2019 compared to 2018, related to the tax savings we retained in 2019 as compared to reserving for those taxes in 2018. See Note 19, Rates and Other Regulatory Activities, for additional information.

Sandpiper's Margin Primarily from Natural Gas Conversions

Gross margin increased by $1.0 million in 2019 compared to 2018 due primarily to the continuing conversion of the Sandpiper system from propane service to natural gas service. We expect to complete conversion of customers from propane to natural gas service in 2020.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $0.5 million in 2019 compared to 2018. Excluding the impact of $0.6 million associated with the natural gas depreciation study, gross margin generated from Florida GRIP in 2019 compared to 2018 increased by $1.1 million.

Impact of Weather on Customer Consumption

Gross margin decreased by $3.3 million due to lower weather-related usage as weather on the Delmarva Peninsula was approximately 3.8 percent warmer and 20.6 percent warmer in Florida in 2019 compared to 2018.

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

(in thousands)
Depreciation, amortization and property tax costs due to growth investments(1)	$	5,160
Payroll, benefits and other employee-related expenses	3,705
Insurance (non-health) expense - both insured and self-insured components	1,847
Stock compensation expense associated with leadership transitions during 2019	908
Vehicle expenses due to additional fleet to support growth	268
Timing of excavation and inspection activities in 2018 to comply with the Company's integrity management program	(1,733		)
Facilities and maintenance costs due to consolidation of facilities	(542		)
Other variances	(232		)
Period-over-period increase in other operating expenses	$	9,381

⁽¹⁾ In 2019 we recorded lower depreciation expense of $1.3 million resulting from the depreciation study approved by the Florida PSC that lowered annual depreciation rates.

2018 compared to 2017

The results for the Regulated Energy segment for the year ended December 31, 2018 compared 2017 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, 2018.

Chesapeake Utilities Corporation 2019 Form 10-K Page 30

UNREGULATED ENERGY

					Increase							Increase
For the Year Ended December 31,	2019		2018		(decrease)			2018		2017		(decrease)
(in thousands)
Revenue	$	154,150	$	161,904	$	(7,754	)	$	161,904	$	140,076	$	21,828
Cost of sales	68,884		84,708		(15,824		)	84,708		69,716		14,992
Gross margin	85,266		77,196		8,070			77,196		70,360		6,836
Operations & maintenance	52,038		48,697		3,341			48,697		44,833		3,864
Depreciation & amortization	10,129		8,263		1,866			8,263		7,741		522
Other taxes	3,160		3,112		48			3,112		2,845		267
Other operating expenses	65,327		60,072		5,255			60,072		55,419		4,653
Operating Income	$	19,939	$	17,124	$	2,815		$	17,124	$	14,941	$	2,183

(1) These results exclude operating results from PESCO that are now reflected as discontinued operations.

2019 Compared to 2018

Operating income for the Unregulated Energy segment for 2019 was $19.9 million, an increase of $2.8 million compared to 2018. The increased operating income was due to an increase in gross margin of $8.1 million, which was partially offset by an increase of $5.3 million in other operating expenses.

Gross Margin

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

(in thousands)	Margin Impact
Marlin Gas Services (acquired assets of Marlin Gas Transport in December 2018)	$	5,300
Propane Operations:
Increased retail propane margins per gallon driven by favorable market conditions and supply management	3,229
Ohl acquisition (assets acquired in December 2018)	1,200
Boulden acquisition (assets acquired in December 2019)	329
Decrease in customer consumption due primarily to the absence of the 2018 Bomb Cyclone	(1,800		)
Lower wholesale propane margins due to non-recurring impact of the 2018 Bomb Cyclone	(866		)
Aspire Energy - higher margins from rate increases	518
Eight Flags - higher margin from increased production	418
Other variances	(258		)
Year-over-year increase in gross margin	$	8,070

The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.

Acquisitions

Marlin Gas Services - Gross margin increased by $5.3 million, as a result of the acquisition of certain assets of Marlin Gas Transport in December 2018.

Propane Operations

• Increased Retail Propane Margins - Gross margin increased by $3.2 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.

• Ohl Propane - Gross margin increased by $1.2 million as a result of the acquisition of certain assets of Ohl in December 2018.

• Boulden Propane - Gross margin increased by $0.3 million as a result of the acquisition of certain assets of Boulden by Sharp in December 2019.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 31

• Decreased Customer Consumption Primarily Driven by Weather - Gross margin decreased by $1.1 million for the Mid-Atlantic propane operations due primarily to extreme weather conditions during the January 2018 "Bomb Cyclone," which drove weather-related consumption in 2018, along with warmer weather in the Mid-Atlantic region in 2019. Weather in Florida was approximately 21 percent warmer in 2019 reducing consumption by propane distribution customers and decreasing gross margin by approximately $0.7 million. 

• Lower Wholesale Propane Margins and Volumes - Gross margin decreased by $0.9 million in 2019 due to a lower margin per gallon and a decrease in volumes delivered for the Mid-Atlantic propane operations as a result of higher demand in 2018 associated with the Bomb Cyclone.

Aspire Energy

• Increased Margin Driven by Changes in Rates - Gross margin increased by $0.5 million, due primarily to changes in customer rates in 2019.

Eight Flags

• Increased Production - Gross margin increased by $0.4 million as a result of increased production associated with a higher output of electricity after the turbine upgrade.

Other Operating Expenses

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

(in thousands)
Operating expenses for unregulated energy acquisitions	$	3,314
Depreciation and amortization due to new capital investments	1,866
Insurance expense (non-health) - both insured and self-insured components	415
Other variances	(340		)
Period-over-period increase in other operating expenses	$	5,255

2018 compared to 2017

The results for the Unregulated Energy segment for the year ended December 31, 2018 compared 2017 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, 2018.

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. We executed four separate transactions associated with the sale of PESCO’s assets and contracts:

• PESCO’s Florida retail operations were sold to Gas South. The initial closing for the transaction was completed in November 2019 with subsequent closings occurring in December 2019.

• PESCO’s other non-Florida retail operations and contracts were sold to UET in October 2019.

• PESCO’s Mid-Atlantic wholesale contracts and Chesapeake Utilities’ Delaware division, Maryland division and Sandpiper Energy asset management agreements were sold to NJRES in October 2019.

• PESCO's producer services portfolio was sold to DFS in December 2019.

As a result of the sales agreements, 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. PESCO's results for the year ended December 31, 2018 compared to 2017 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, 2018.

We received a total of $22.9 million in cash consideration from the aforementioned buyers that was inclusive of working capital of $8.0 million from UET. We recognized a pre-tax gain of $7.3 million ($5.4 million after tax) in connection with the closing of these transactions during the fourth quarter of 2019. The final working capital true up, and sale of certain contracts, to UET is expected to be finalized in the first quarter of 2020.

Chesapeake Utilities Corporation 2019 Form 10-K Page 32

OTHER EXPENSE, NET

Other expense, net was $1.8 million and $0.6 million for 2019 and 2018, respectively. Other 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 in other expense, net in 2019 was due to higher pension expense as well as pension settlement expense associated with the de-risking of the Chesapeake Pension Plan see Note 17, Employee Benefit Plans, for additional information.

INTEREST CHARGES

2019 Compared to 2018

Interest charges for 2019 increased by approximately $6.1 million, compared to 2018 attributable primarily to:

(in thousands)
Long-term debt - largely for the NYL Shelf Notes issued in November 2018 and Prudential Shelf Notes issued in August 2019	$	3,007
Lower capitalization of interest largely as a result of Eastern Shore's 2017 System Expansion Project being fully completed	1,309
Higher short-term borrowings to support growth	1,186
Term Notes - issued in connection with Hurricane Michael	383
Other	193
Year-over-year increase	$	6,078

INCOME TAXES

2019 Compared to 2018

Income tax expense was $21.1 million for 2019 compared to $21.2 million for 2018. Our effective income tax rate was 25.6 percent and 27.1 percent for the year ended December 31, 2019 and 2018, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to more closely align our capital structure with our target capital structure.

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 $199.0 million (including the purchase of certain propane assets of Boulden) in 2019 and $282.9 million in 2018 (including the purchase of certain assets from Marlin Gas Services and Ohl). The 2018 capital expenditures also includes over $60.0 million of restoration costs associated with repairing damages caused by Hurricane Michael to our electric distribution operations’ service territory in Northwest Florida.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 33

The following table shows total capital expenditures for the year ended December 31, 2019 by segment and by business line:

	For the Year Ended December 31, 2019
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	62,744
Natural gas transmission	62,000
Electric distribution	5,860
Total Regulated Energy	130,604
Unregulated Energy:
Propane distribution (1)	38,347
Energy transmission	11,206
Other unregulated energy	10,481
Total Unregulated Energy	60,034
Other:
Corporate and other businesses	8,348
Total Other	8,348
Total 2019 Capital Expenditures	$	198,986

⁽¹⁾ This amount includes $24.5 million for the acquisition of certain propane operating assets of Boulden completed in December 2019.

The following table shows a range of the expected 2020 capital expenditure by segment and by business line:

	Estimate for Fiscal 2020
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	72,000	$	83,000
Natural gas transmission	83,000		96,000
Electric distribution	5,000		7,000
Total Regulated Energy	160,000		186,000
Unregulated Energy:
Propane distribution	10,000		11,000
Energy transmission	6,000		6,000
Other unregulated energy	6,000		8,000
Total Unregulated Energy	22,000		25,000
Other:
Corporate and other businesses	3,000		4,000
Total Other	3,000		4,000
Total 2020 Expected Capital Expenditures	$	185,000	$	215,000

The 2020 budget, excluding acquisitions, includes: Eastern Shore's Del-Mar Energy Pathway Project, Florida's Callahan and Palm Beach County Western Expansion and other potential pipeline projects, continued expenditures under Florida GRIP, further expansions of our natural gas distribution and transmission systems, continued natural gas infrastructure improvement activities, 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, customer growth in existing areas, regulation, new growth or acquisition opportunities, availability of capital and other factors discussed in Item 1A. Risk Factors.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 34

Capital Structure

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

The following table presents our capitalization, excluding and including short-term borrowings, as of December 31, 2019 and 2018 follows:

	December 31, 2019				December 31, 2018
(in thousands)
Long-term debt, net of current maturities	$	440,168	44	%	$	316,020	38	%
Stockholders’ equity	561,577		56	%	518,439		62	%
Total capitalization, excluding short-term borrowings	$	1,001,745	100	%	$	834,459	100	%

	December 31, 2019				December 31, 2018
(in thousands)
Short-term debt	$	247,371	19	%	$	294,458	26	%
Long-term debt, including current maturities	485,768		38	%	327,955		29	%
Stockholders’ equity	561,577		43	%	518,439		45	%
Total capitalization, including short-term borrowings	$	1,294,716	100	%	$	1,140,852	100	%

As of December 31, 2019, we had no restrictions on our cash balances. Chesapeake Utilities’ Senior Notes and FPU’s first mortgage bonds contain a restriction that limits the payment of dividends or other restricted payments in excess of certain pre-determined thresholds. As of December 31, 2019, $282.0 million of our consolidated net income and $130.5 million of FPU’s net income were free of such restrictions.

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Including the funds expended specifically related to the impact of Hurricane Michael, our equity to total capitalization ratio, including short-term borrowings, was 43 percent as of December 31, 2019. Excluding the funds expended for Hurricane Michael restoration activities, our equity to total capitalization ratio, including short-term borrowings, would have been approximately 45 percent. We seek to align permanent financing with the in-service dates of its 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.

Term Notes

In December 2018, we issued a $30.0 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. This note was paid off in December 2019 utilizing the proceeds from the issuance of uncollateralized senior notes discussed below. 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. The interest rate, at December 31, 2019, was 2.46%, which equals the one-month LIBOR rate plus 75 basis points. As of December 31, 2019, this term note is included in the current maturities of long-term debt.

Uncollateralized Senior Notes

In December 2019, we issued $70.0 million of 2.98% uncollateralized senior notes to four financial institutions. We used the proceeds to pay off the $30.0 million PNC Term Note described above to reduce our short-term borrowing amount and to finance our purchase of certain propane operating assets of Boulden.

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, 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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 35

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL who are under no obligation to purchase any unsecured debt. The Prudential Shelf Agreement totaling $150.0 million was entered in October 2015 and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was amended in September 2018 to increase the borrowing capacity to $150.0 million, and in August 2019, we issued $100.0 million of 3.98% unsecured debt. In January 2020, we submitted a request that Prudential purchase $50.0 million of our unsecured debt which was accepted and confirmed by Prudential. The Shelf notes will bear interest at the rate of 3.00% per annum and the proceeds received from the issuances will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the sale and issuance of the Shelf Notes is expected to occur on or before July 15, 2020.

We entered into the NYL Shelf Agreement, totaling $100.0 million, in March 2017, and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement was amended in November 2018 to provide additional borrowing capacity of $50.0 million. As of December 31, 2019, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement, which we entered into in March 2017. In February 2020, we submitted a request for NYL to purchase $40.0 million of our unsecured debt which was accepted and confirmed by NYL. The Shelf Notes will bear interest at the rate of 2.96% per annum and the proceeds received from the issuance will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the issuance of the Shelf Notes is expected to occur on or before August 14, 2020.

The following table summarizes our shelf agreements at December 31, 2019:

	Total Borrowing Capacity		Less: Amount of Debt Issued			Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
(in thousands)
Prudential Shelf Agreement (1)	$	220,000	$	(170,000	)	$	—	$	50,000
MetLife Shelf Agreement	150,000		—			—		150,000
NYL Shelf Agreement (2)	150,000		(100,000		)	—		50,000
Total	$	520,000	$	(270,000	)	$	—	$	250,000

⁽¹⁾ As described above, in January 2020, we requested and Prudential accepted our request to purchase $50 million of our unsecured debt.

⁽²⁾ As described above, in February 2020, we requested and NYL accepted our request to purchase $40 million of our unsecured debt.

The Uncollateralized 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.

Short-Term Borrowings

Our outstanding short-term borrowings at December 31, 2019 and 2018 were $247.4 million and $294.5 million, respectively, at weighted average interest rates of 2.62 percent and 3.44 percent, respectively. Our current short-term borrowing limit, authorized by our Board of Directors, is $370.0 million, including the Revolver.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures program. As of December 31, 2019, we had four unsecured bank credit facilities with four financial institutions totaling $220.0 million in available credit. In addition, we have $150.0 million of additional short-term debt capacity available under the Revolver. The terms of the Revolver are described in further detail below. None of the unsecured bank lines of credit requires compensating balances.

The $150.0 million Revolver is available through October 8, 2020 and is subject to the terms and conditions set forth in the credit agreement among us and the lenders related to the Revolver ("Credit Agreement"). Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR rate plus an applicable margin of 1.125 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.125 percent or less. Interest is payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We have the right, under certain circumstances, to extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the lenders' approval. We may also request the lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each lender.

Chesapeake Utilities Corporation 2019 Form 10-K Page 36

Our outstanding short-term borrowings at December 31, 2019 and 2018 included $3.2 million and $4.4 million, respectively, of book overdrafts, which are not actual borrowings under the credit facilities but, if presented, would be funded through the credit facilities and, therefore, were included in the short-term borrowings.

Our outstanding borrowings under these unsecured short-term credit facilities at December 31, 2019 and 2018 were $244.2 million and $290.1 million, respectively. Short-term borrowings were as follows during 2019, 2018 and 2017:

(in thousands)	2019			2018			2017
Average borrowings during the year	$	257,587		$	238,750		$	183,561
Weighted average interest rate for the year	3.11		%	2.93		%	2.03		%
Maximum month-end borrowings	$	244,190		$	290,103		$	240,671

As of December 31, 2019, we had issued $5.0 million in letters of credit to various counterparties under the 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 the Revolver.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2019, 2018 and 2017:

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Net cash provided by (used in):
Operating activities	$	102,964		$	117,362		$	110,089
Investing activities	(186,587		)	(256,848		)	(186,895		)
Financing activities	84,519			139,961			78,242
Net increase in cash and cash equivalents	896			475			1,436
Cash and cash equivalents—beginning of period	6,089			5,614			4,178
Cash and cash equivalents—end of period	$	6,985		$	6,089		$	5,614

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 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.

During 2019 and 2018, net cash provided by operating activities was $103.0 million and $117.4 million, respectively, resulting in a decrease in cash flows of $14.4 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 decreased cash flows by $45.1 million, in part due to the absence of PESCO which ceased invoicing the majority of its former customers during the middle of the fourth quarter of 2019 and had also settled most of its outstanding vendor obligations at December 31, 2019. The remainder of the decrease was primarily driven by the timing of the receipt of payments from continuing operations.

• Changes in net prepaid expenses and other current assets, customer deposits and refunds and other assets and liabilities, net increased cash flows by $38.2 million.

• Changes in net regulatory assets and liabilities decreased cash flows by $10.1 million due primarily to the change in fuel costs collected through the various cost recovery mechanisms.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 37

• Net income, adjusted for non-cash adjustments and reconciling activities, decreased cash flows by $7.8 million, primarily due to recognition of the gain on the sale of the assets of PESCO, partially offset by increases in depreciation, amortization, and deferred income taxes;

• Net cash flows from changes in propane inventory, storage gas and other inventories increased by approximately $6.1 million;

• Net cash flows from income taxes receivable decreased by $4.2 million due primarily to the absence of tax refunds associated with lower corporate tax rates implemented in the prior year as a component of the TCJA.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $186.6 million and $256.8 million during the year ended December 31, 2019 and 2018, respectively, resulting in a decrease in cash flows of $70.2 million. Key investing activities contributing to the cash flow change included:

• Cash used to pay for capital expenditures was $184.7 million for the year ended December 31, 2019, compared to $240.4 million in December 31, 2018, resulting in increased cash flows of $55.7 million;

• Net cash of $24.0 million was primarily used to acquire certain propane operating assets of Boulden in 2019 compared to net cash of $16.7 million used to acquire operating assets of Ohl and Marlin Gas Services in 2018; and

• Change in cash flows of $22.9 million for the year ended December 31, 2019 is attributed to the proceeds from the sale of assets and contracts for PESCO.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $84.5 million for the year ended December 31, 2019, compared to net cash of $140.0 million provided by financing activities during the prior year resulted in a decrease in cash flows of $55.5 million, primarily due to the following:

• Decreased cash flows from repayments of short-term borrowing of $95.3 million under our line of credit arrangements;

• Increased cash flows of $44.8 million associated with the issuance of long-term debt. For the year ended December 31, 2019, we received net proceeds of $199.6 million from the issuance of Term Notes, Prudential Shelf Notes and uncollateralized senior notes. For the year ended December 31, 2018 we had received $154.8 million in net cash proceeds from the Revolver, the Term Notes and the issuance of the NYL Shelf Notes (Series A) in May and November 2018;

• Decreased cash flows of $7.5 million as a result of repayment of long-term debt;

• Increased cash flows of $4.8 million as a result of changes in cash overdrafts in 2019; and

• Cash dividend payments of $24.7 million in 2019 compared to $22.0 million for 2018.

CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2019:

	Payments Due by Period
Contractual Obligations	2020		2021-2022		2023-2024		After 2024		Total
(in thousands)
Long-term debt (1)	$	45,600	$	38,700	$	38,200	$	364,100	$	486,600
Operating leases (2)	2,104		3,582		3,182		4,916		13,784
Purchase obligations (3)
Transmission capacity	34,484		58,408		47,102		162,273		302,267
Storage capacity	814		871		109		—		1,794
Commodities	19,105		104		—		—		19,209
Electric supply	6,333		12,739		12,838		38,857		70,767
Unfunded benefits (4)	351		700		607		1,401		3,059
Funded benefits (5)	4,425		—		—		8,287		12,712
Total Contractual Obligations	$	113,216	$	115,104	$	102,038	$	579,834	$	910,192

⁽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 $17.5 million, $31.9 million, $27.7 million and $94.4 million, respectively, for the periods indicated above. Expected interest payments for all periods total $171.5 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

Chesapeake Utilities Corporation 2019 Form 10-K Page 38

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 $17.2 million at December 31, 2019 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 $3.5 million, reflecting the payments we expect to make to the trust funds in 2020. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8, Financial Statements and Supplementary Data, Note 17, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $9.2 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

We have issued corporate guarantees to certain vendors of our subsidiaries that provide for the payment of propane and natural gas purchases in the event of the subsidiary’s default. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at December 31, 2019 was $24.7 million, with the guarantees expiring on various dates throughout 2020.

At December 31, 2019, a majority of our corporate guarantees were associated with the operations of PESCO. As a result of the sale of PESCO's assets and contracts we are finalizing the wind-down of corporate guarantees and letters of credit associated with the business. See Note 4, Acquisitions and Divestitures, for additional details on the sale of PESCO.

We have issued letters of credit totaling $5.4 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carrier with expiration dates extending through October 22, 2020. There were no draws on these letters of credit as of December 31, 2019. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit 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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 39

Derivative Instruments

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

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

We determined that certain propane put options, call options, swap agreements and natural gas futures contracts 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, propane 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 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 and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.

Our natural gas supply operation in Ohio 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 Doubtful Accounts

An allowance for doubtful accounts 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

Chesapeake Utilities Corporation 2019 Form 10-K Page 40

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 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 2019 indicated no impairment of goodwill. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 11, Goodwill and Other Intangible Assets, in the consolidated financial statements.

Other Assets Impairment Evaluations

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

Pension and Other Postretirement Benefits

Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 17, Employee Benefit Plans, in the consolidated financial statements, including plan asset investment allocation, estimated future benefit payments, general descriptions of the plans, significant assumptions, the impact of certain changes in assumptions, and significant changes in estimates.

For 2019, actuarial assumptions include expected long-term rates of return on plan assets of 6.00 percent and 6.50 percent for Chesapeake Utilities' pension plan and FPU’s pension plan, respectively, and discount rates of 3.00 percent and 4.25 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 yield curve Index, changes in those rates from the prior year and other pertinent factors, including the expected lives of the plans and the availability of the lump-sum payment option. A 0.25 percent decrease in the discount rate could decrease our annual pension and postretirement costs by an immaterial amount, and a 0.25 percent increase could increase our annual pension and postretirement costs by an immaterial amount.

Actual changes in the fair value of plan assets and the differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension benefit costs that we ultimately recognize. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $0.1 million and would not have an impact on the postretirement and Chesapeake 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. Additional information

Chesapeake Utilities Corporation 2019 Form 10-K     Page 41

about our long-term debt is disclosed in Item 8, Financial Statements and Supplementary Data, Note 13, Long-term Debt, in the consolidated financial statements.

COMMODITY PRICE RISK

Regulated Energy Segment

We have entered into agreements with various wholesale suppliers to purchase natural gas and electricity for resale to our customers. Our regulated energy distribution businesses that sell natural gas or electricity to end-use customers have fuel cost recovery mechanisms authorized by the PSCs that allow us to recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.

Unregulated Energy Segment

Our propane operations are exposed to commodity price risk as a result of the competitive nature of retail pricing offered to our customers. In order to mitigate this risk, we utilize propane storage activities and forward contracts for supply.

We can store up to approximately 7.4 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.

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

The following table reflects the changes in the fair market value of financial derivatives contracts related to natural gas and propane purchases and sales from December 31, 2018 to December 31, 2019:

(in thousands)	Balance at December 31, 2018			Increase (Decrease) in Fair Market Value		Less Amounts Settled			Balance at December 31, 2019
Sharp	$	(1,522	)	$	1,177	$	(1,499	)	$	(1,844	)
Total	$	(1,522	)	$	1,177	$	(1,499	)	$	(1,844	)

There were no changes in the methods of valuations during the year ended December 31, 2019.

The following is a summary of fair market value of financial derivatives as of December 31, 2019, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2020			2021			2022			2023		Total Fair Value
Price based on Mont Belvieu - Sharp	$	(1,525	)	$	(296	)	$	(23	)	—		$	(1,844	)
Total	$	(1,525	)	$	(296	)	$	(23	)	$	—	$	(1,844	)

WHOLESALE CREDIT RISK

The Risk Management Committee reviews credit risks associated with counterparties to commodity derivative contracts prior to such contracts being approved.

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

INFLATION

Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. To help cope with the effects of inflation on our capital investments and returns, we periodically seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated energy business operations. To compensate for fluctuations in propane gas prices, we adjust propane sales prices to the extent allowed by the market.

Chesapeake Utilities Corporation 2019 Form 10-K Page 42

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, 2019 and 2018, 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, 2019, 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, 2019, 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, 2019 and 2018, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2019, 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, 2019, based on criteria established in Internal Control - Integrated Framework: (2013) issued by COSO.

Basis for Opinion

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 43

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, 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 $29.3 million of goodwill within the Unregulated Energy reportable segment as of December 31, 2019, 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 2019 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 Virchow Krause, LLP

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

Philadelphia, Pennsylvania

February 26, 2020

Chesapeake Utilities Corporation 2019 Form 10-K Page 44

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Income
	For the Year Ended December 31,
	2019			2018			2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	343,006		$	345,281		$	326,310
Unregulated Energy	154,150			161,904			140,076
Other businesses and eliminations	(17,552		)	(16,869		)	(16,740		)
Total operating revenues	479,604			490,316			449,646
Operating Expenses
Regulated Energy cost of sales	102,803			121,828			118,769
Unregulated Energy and other cost of sales	51,697			68,342			53,420
Operations	137,844			132,523			121,949
Maintenance	15,679			14,387			12,701
Gain from a settlement	(130		)	(130		)	(130		)
Depreciation and amortization	45,423			40,220			36,386
Other taxes	20,001			18,303			16,821
Total operating expenses	373,317			395,473			359,916
Operating Income	106,287			94,843			89,730
Other expense, net	(1,830		)	(603		)	(2,204		)
Interest charges	22,224			16,146			12,530
Income from Continuing Operations Before Income Taxes	82,233			78,094			74,996
Income Taxes on Continuing Operations	21,091			21,232			14,670
Income from Continuing Operations	61,142			56,862			60,326
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)
Gain on sale of Discontinued Operations, Net of tax	5,402			—			—
Net Income	$	65,153		$	56,580		$	58,124
Weighted Average Common Shares Outstanding:
Basic	16,398,443			16,369,616			16,336,789
Diluted	16,448,486			16,419,870			16,383,352
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	3.73		$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)
Basic Earnings Per Share of Common Stock	$	3.97		$	3.46		$	3.56
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	3.72		$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)
Diluted Earnings Per Share of Common Stock	$	3.96		$	3.45		$	3.55

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 45

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Comprehensive Income
	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Net Income	$	65,153		$	56,580		$	58,124
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(20), $(22) and $(31), respectively	(57		)	(55		)	(46		)
Net gain(loss), net of tax of $368, $(49), and $432, respectively	1,052			(108		)	663
Cash Flow Hedges, net of tax:
Unrealized (loss) on commodity contract cash flow hedges, net of tax of $(176), $(555) and $(8), respectively	(434		)	(1,371		)	(11		)
Total Other Comprehensive Income (Loss)	561			(1,534		)	606
Comprehensive Income	$	65,714		$	55,046		$	58,730

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 46

Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets
	As of December 31,
Assets	2019			2018
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,441,473		$	1,297,416
Unregulated Energy	265,209			236,440
Other businesses and eliminations	39,850			34,585
Total property, plant and equipment	1,746,532			1,568,441
Less: Accumulated depreciation and amortization	(336,876		)	(294,089		)
Plus: Construction work in progress	54,141			79,168
Net property, plant and equipment	1,463,797			1,353,520
Current Assets
Cash and cash equivalents	6,985			6,089
Accounts receivable (less allowance for uncollectible accounts of $1,337 and $1,058, respectively)	49,562			53,837
Accrued revenue	20,846			22,640
Propane inventory, at average cost	5,824			9,791
Other inventory, at average cost	6,067			7,127
Regulatory assets	5,144			4,796
Storage gas prepayments	3,541			3,433
Income taxes receivable	20,050			15,300
Prepaid expenses	13,928			10,079
Derivative assets, at fair value	—			82
Other current assets	2,879			5,682
Current assets held for sale	—			52,681
Total current assets	134,826			191,537
Deferred Charges and Other Assets
Goodwill	32,668			21,568
Other intangible assets, net	8,129			3,850
Investments, at fair value	9,229			6,711
Operating lease right-of-use assets	11,563			—
Regulatory assets	73,407			72,422
Receivables and other deferred charges	49,579			36,401
Noncurrent assets held for sale	—			7,662
Total deferred charges and other assets	184,575			148,614
Total Assets	$	1,783,198		$	1,693,671

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 47

Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets
	As of December 31,
Capitalization and Liabilities	2019			2018
(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)	7,984			7,971
Additional paid-in capital	259,253			255,651
Retained earnings	300,607			261,530
Accumulated other comprehensive loss	(6,267		)	(6,713		)
Deferred compensation obligation	4,543			3,854
Treasury stock	(4,543		)	(3,854		)
Total stockholders’ equity	561,577			518,439
Long-term debt, net of current maturities	440,168			316,020
Total capitalization	1,001,745			834,459
Current Liabilities
Current portion of long-term debt	45,600			11,935
Short-term borrowing	247,371			294,458
Accounts payable	54,068			98,681
Customer deposits and refunds	30,939			32,620
Accrued interest	2,554			2,317
Dividends payable	6,644			6,060
Accrued compensation	16,236			13,923
Regulatory liabilities	5,991			7,883
Derivative liabilities, at fair value	1,844			1,604
Other accrued liabilities	12,077			10,081
Current liabilities held for sale	—			48,672
Total current liabilities	423,324			528,234
Deferred Credits and Other Liabilities
Deferred income taxes	180,656			156,820
Regulatory liabilities	127,744			135,039
Environmental liabilities	6,468			7,638
Other pension and benefit costs	30,569			28,513
Operating lease - liabilities	9,896			—
Deferred investment tax credits and other liabilities	2,796			2,968
Total deferred credits and other liabilities	358,129			330,978
Environmental and other commitments and contingencies (Note 20 and 21)
Total Capitalization and Liabilities	$	1,783,198		$	1,693,671

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 48

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Cash Flows
	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Operating Activities
Net Income	$	65,153		$	56,580		$	58,124
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	45,900			40,802			36,599
Depreciation and accretion included in operations expenses	8,752			8,535			8,122
Deferred income taxes, net	24,476			21,226			11,085
Gain on sale of discontinued operations	(7,344		)	—			—
Realized gain (loss) on sale of assets/commodity contracts	(4,135		)	5,497			3,179
Unrealized loss (gain) on investments/commodity contracts	(1,595		)	429			(1,001		)
Employee benefits and compensation	1,985			856			1,577
Share-based compensation	4,279			2,813			2,490
Other, net	—			—			(750		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	36,489			(16,311		)	(19,506		)
Propane inventory, storage gas and other inventory	8,227			2,107			(9,036		)
Regulatory assets/liabilities, net	(7,812		)	2,250			(2,855		)
Prepaid expenses and other current assets	11,115			(7,421		)	(7,001		)
Accounts payable and other accrued liabilities	(62,021		)	35,907			15,596
Income taxes receivable (payable)	(4,750		)	(522		)	8,110
Customer deposits and refunds	(1,811		)	(596		)	5,513
Accrued compensation	2,120			708			2,488
Other assets and liabilities, net	(16,064		)	(35,498		)	(2,645		)
Net cash provided by operating activities	102,964			117,362			110,089
Investing Activities
Property, plant and equipment expenditures	(184,727		)	(240,351		)	(175,329		)
Proceeds from sale of assets	427			782			708
Acquisitions, net of cash acquired	(23,988		)	(16,654		)	(11,945		)
Proceeds from the sale of discontinued operations	22,871			—			—
Environmental expenditures	(1,170		)	(625		)	(329		)
Net cash used in investing activities	(186,587		)	(256,848		)	(186,895		)
Financing Activities
Common stock dividends	(24,693		)	(22,043		)	(19,928		)
Issuance of stock for Dividend Reinvestment Plan	(721		)	(706		)	89
Proceeds from issuance of common stock, net of expenses	—			—			(10		)
Tax withholding payments related to net settled stock compensation	(692		)	(1,210		)	(692		)
Change in cash overdrafts due to outstanding checks	(1,174		)	(5,943		)	1,738
Net borrowings (repayments) under line of credit agreements	(45,913		)	49,432			39,338
Proceeds from issuance of long-term debt	199,648			154,819			69,807
Repayment of long-term debt and finance lease obligation	(41,936		)	(34,388		)	(12,100		)
Net cash provided by financing activities	84,519			139,961			78,242
Net Increase in Cash and Cash Equivalents	896			475			1,436
Cash and Cash Equivalents — Beginning of Period	6,089			5,614			4,178
Cash and Cash Equivalents — End of Period	$	6,985		$	6,089		$	5,614

Supplemental Cash Flow Disclosures (see Note 7)

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 49

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, 2016	16,303,499	$	7,935	$	250,967		$	192,062		$	(4,878	)	$	2,416	$	(2,416	)	$	446,086
Net Income	—	—		—			58,124			—			—		—			58,124
Other comprehensive income	—	—		—			—			606			—		—			606
Dividends declared ($1.2800 per share)	—	—		—			(21,045		)	—			—		—			(21,045		)
Retirement savings plan and dividend reinvestment plan	10,771	5		730			—			—			—		—			735
Stock issuance (3)	—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit (4) (5)	30,172	15		1,783			—			—			—		—			1,798
Treasury stock activities(2)	—	—		—			—			—			979		(979		)	—
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 income	—	—		—			—			(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 (4) (5)	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 (4) (5)	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

⁽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 95,329, 97,053 and 90,961 shares at December 31, 2019, 2018 and 2017, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

⁽³⁾ Represents capitalized legal fees associated with our September 22, 2016 public offering.

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

⁽⁵⁾ The shares issued under the SICP are net of shares withheld for employee taxes. For 2019, 2018 and 2017, we withheld 7,635, 16,918 and 10,269 shares, respectively, for taxes.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 50

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 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 connection with this strategy, during the third and fourth quarter of 2019, we reached agreements with four entities to sell PESCO's assets and contracts. These transactions closed during the fourth quarter of 2019. As a result of the sale, 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. Refer to Note 4, Acquisitions and Divestitures for further information.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Property, Plant and Equipment

Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment for continuing operations by classification as of December 31, 2019 and 2018 is provided in the following table:

Chesapeake Utilities Corporation 2019 Form 10-K     Page 51

Notes to the Consolidated Financial Statements

	As of December 31,
(in thousands)	2019			2018
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	705,095		$	657,630
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	608,727			537,654
Electric distribution	127,651			102,133
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	141,841			123,632
Natural gas transmission and supply – Ohio	73,658			70,225
Electricity and steam generation	35,436			35,239
Mobile CNG and pipeline solutions	14,014			7,240
Other unregulated energy	104			104
Other	40,006			34,584
Total property, plant and equipment	1,746,532			1,568,441
Less: Accumulated depreciation and amortization	(336,876		)	(294,089		)
Plus: Construction work in progress	54,141			79,168
Net property, plant and equipment	$	1,463,797		$	1,353,520

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, 2019 and 2018, the non-refundable contributions totaled $2.1 million and $2.8 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, 2019 and 2018, AFUDC totaled $0.7 million and $1.9 million, respectively, which was reflected as a reduction of interest charges. During the year ended December 31, 2017, AFUDC was not material.

Leases

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 52

Notes to the Consolidated Financial Statements

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2019 and 2018, which consist of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned with Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. 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 $1.5 million and $1.4 million, at December 31, 2019 and 2018, respectively.

In May 2018, Peninsula Pipeline announced a plan to construct a jointly-owned 26-mile intrastate transmission pipeline in Nassau County, Florida with Seacoast Gas Transmission.  Peninsula Pipeline's ownership will be 50 percent. The pipeline is expected to be placed in-service during the third quarter of 2020.

Asset Impairment Evaluations

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, 2019, 2018 and 2017:

	2019	2018	2017
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.6%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.6%	2.7%	2.8%
Natural gas transmission – Florida	2.4%	2.3%	3.5%
Electric distribution	3.4%	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, 2019, 2018 and 2017, we reported $8.8 million, $8.5 million and $8.1 million, respectively, of depreciation and accretion in operations expenses.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 53

Notes to the Consolidated Financial Statements

Regulated Operations

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 54

Notes to the Consolidated Financial Statements

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 Doubtful Accounts

Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and general economic conditions. Accounts 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 during 2019, 2018 or 2017.

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 2019, 2018 and 2017 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 primarily 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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 55

Notes to the Consolidated Financial Statements

as the Prudential curve index and the FTSE Pension Discount curve, formerly the Citigroup yield curve, 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

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.

Recently Adopted Accounting Standards

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a right of use model that requires a lessee to recognize a right of use asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; ASU No. 2018-11, Targeted Improvements; and ASU No. 2019-01, Codification Improvements. We adopted ASU 2016-02 and the related amendments on January 1, 2019, and used the optional transition method for all existing leases. The optional transition method enabled us to adopt the new standard as of the beginning of the period of adoption and did not require

Chesapeake Utilities Corporation 2019 Form 10-K Page 56

Notes to the Consolidated Financial Statements

restatement of prior period financial information. As a result, prior period financial information was not recast and continues to be reported under the accounting guidance effective during those periods.

At adoption, we elected the following practical expedients: (1) the ‘package of practical expedients,’ pursuant to which we did not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs, (2) the ‘use-of-hindsight’ practical expedient, which allowed us to use hindsight in assessing impairment of our existing land easements, (3) the creation of an accounting policy for short-term leases resulting in lease payments being recorded as an expense on a straight-line basis over the lease term, and (4) the aggregation, rather than separation, of the lease and non-lease components for all leases.

See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease accounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted ASU 2018-07 on January 1, 2019. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

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. ASU 2016-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and is not expected to have a material impact on our financial position or results of operations.

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 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively, and are not expected to have a material impact on our financial position or results of operations.

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. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020, and since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 57

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,
	2019		2018			2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	61,142	$	56,862		$	60,326
Income/(Loss) from Discontinued Operations	4,011		(282		)	(2,202		)
Net Income	$	65,153	$	56,580		$	58,124
Weighted average shares outstanding	16,398,443		16,369,616			16,336,789
Earnings Per Share from Continuing Operations	$	3.73	$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Basic Earnings Per Share	$	3.97	$	3.46		$	3.56
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,398,443		16,369,616			16,336,789
Effect of dilutive securities — Share-based compensation	50,043		50,254			46,563
Adjusted denominator — Diluted	16,448,486		16,419,870			16,383,352
Earnings Per Share from Continuing Operations	$	3.72	$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Diluted Earnings Per Share	$	3.96	$	3.45		$	3.55

4. ACQUISITIONS AND DIVESTITURES

Acquisition of Elkton Gas Company

In December 2019, we entered into an agreement with SJI to acquire its subsidiary, Elkton Gas Company, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Upon completion of the transaction, Elkton Gas Company will become our wholly-owned subsidiary. The acquisition, which is expected to close in the second half of 2020, is subject to approval by the Maryland PSC. Elkton Gas Company's territory is contiguous to our franchised service territory in Cecil County, Maryland and it will continue to operate out of its existing office with the same local personnel.

Acquisitions in 2019

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 contract through the first anniversary of the transaction closing. We accounted for the purchase of the operating assets of Boulden as a business combination within our Unregulated Energy segment. 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 are preliminary and subject to adjustment based on contractual provisions that will be finalized at the end of the measurement period. Contributions to our operating revenues and operating income as a result of this acquisition for the year ended December 31, 2019 can be found in the table below.

Acquisitions in 2018

In December 2018, Marlin Gas Services acquired certain operating assets of Marlin Gas Transport, a supplier of CNG and pipeline solutions, primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services,

Chesapeake Utilities Corporation 2019 Form 10-K Page 58

Notes to the Consolidated Financial Statements

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 steel tube CNG trailers, composite CNG trailers, mobile compression equipment and an internally-developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas.

In December 2018, Sharp acquired certain propane operating assets and customers of Ohl, which provided propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania.

We accounted for the purchases of the operating assets of Marlin Gas Transport and Ohl, which totaled approximately $18.2 million, as business combinations within our Unregulated Energy segment. Goodwill of $4.8 million, related to the Marlin Gas Transport acquisition, and $1.5 million, associated with the Ohl acquisition, were initially recorded at the close of these transactions. In 2019, we recorded a reduction to the purchase price for Ohl of $0.2 million upon completing our verification of the assets purchased.  The purchase price adjustment was recorded as a reduction in our property, plant and equipment balance.  Due to the timing of these acquisitions, the revenue and operating income from these acquisitions in 2018 were immaterial. For the year ended December 31, 2019, these acquisitions generated the following operating revenue and income:

	For the Year Ended
	December 31, 2019
	Operating Revenues		Operating Income
(in thousands)
Marlin Gas Services	$	5,702	$	1,500
Ohl propane acquisition	$	1,662	$	385
Boulden acquisition	$	550	$	239

Divestiture of PESCO

In September of 2019, we initiated a plan to sell a majority of the assets of PESCO, our natural gas marketing subsidiary. This was done in an effort to enable us to focus on the strategies that support our core energy delivery business. During the fourth quarter of 2019, we executed four separate transactions associated with the sale of PESCO’s assets and contracts:

• PESCO’s Florida retail operations were sold to Gas South. The initial closing for the transaction was completed in November 2019 with subsequent closings occurring in December 2019.

• PESCO’s other non-Florida retail operations and contracts were sold to UET in October 2019.

• PESCO’s Mid-Atlantic wholesale contracts and Chesapeake Utilities’ Delaware division, Maryland division and Sandpiper Energy asset management agreements were sold to NJRES in October 2019.

• PESCO's producer services portfolio was sold to DFS in December 2019.

We received a total of $22.9 million in cash consideration from the aforementioned buyers that was inclusive of working capital of $8.0 million from UET. We recognized a pre-tax gain of $7.3 million in connection with the closing of these transactions during the fourth quarter of 2019. The final working capital true up associated with the sale of assets and contracts to UET will be finalized in the first quarter of 2020.

As a result of the sales agreements, 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. The assets and liabilities of PESCO are presented as current and noncurrent assets and liabilities of a business held for sale in the consolidated balance sheets.

Additionally, amounts for operating revenues and costs of sales which had previously been 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 all periods presented. We have recast these amounts because, upon completion of the sales transactions, we will continue to provide and receive services from the buyers.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 59

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)	2019			2018			2017
Operating revenues(1)	$	161,289		$	258,713		$	184,519
Cost of sales(1)	157,646			252,111			182,307
Other operating expenses	5,222			6,825			4,522
Operating loss	(1,579		)	(223		)	(2,310		)
Interest and other expense	315			297			253
Loss from Discontinued Operations before income taxes	(1,894		)	(520		)	(2,563		)
Gain on sale of Discontinued Operations	7,344			—			—
Income tax (benefit) / expense	1,439			(238		)	(361		)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	4,011		$	(282	)	$	(2,202	)

⁽¹⁾ Included in operating revenues and cost of sales for the years ended December 31, 2019, 2018 and 2017, is $19.8 million, $31.5 million and $16.6 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity that will continue with the buyers after the disposition of the assets of PESCO.

As a result of the disposition of the assets and contracts of PESCO, there were no assets or liabilities classified as held for sale at December 31, 2019. The assets and liabilities of the discontinued operations classified as held for sale in the consolidated balance sheet at December 31, 2018 include the following:

	As of
(in thousands)	December 31, 2018
Property, plant and equipment	$	1,242
Less: accumulated depreciation	(206		)
Net property, plant and equipment (1)	1,036
Current assets (2)	52,681
Deferred charges and other assets (1)	6,626
Assets of Discontinued Operations held for sale	$	60,343
Current liabilities (3)	$	48,672
Liabilities of Discontinued Operations held for sale	$	48,672
Net assets	$	11,671

⁽¹⁾ These balances have been combined within the consolidated balance sheets to arrive at noncurrent assets held for sale.

⁽²⁾ At December 31, 2018, current assets were primarily comprised of $31.1 million of accounts receivable, $13.1 million of derivative assets at fair value, $4.9 million of accrued revenue and $3.2 million of storage gas prepayments.

⁽³⁾ At December 31, 2018, current liabilities were primarily comprised of $31.1 million of accounts payable, $13.3 million of derivative liabilities at fair value and $2.7 million of other accrued liabilities.

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		2017
Depreciation and amortization	$	477		$	582	$	213
Property, plant and equipment expenditures	—			115		11,766
Deferred income taxes	(125		)	1,088		(1,515		)
Realized / (loss) gain on commodity contracts	(2,161		)	5,002		4,911

Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each expires on March 31, 2020. As a result of the sale of the assets of PESCO, effective October 1, 2019, these agreements are now managed by NJRES through the remainder of the contract term. In addition to the asset management agreements, Eastern Shore had several firm transportation

Chesapeake Utilities Corporation 2019 Form 10-K Page 60

Notes to the Consolidated Financial Statements

and capacity arrangements with PESCO which were included in the assets sold to UET. Eastern Shore will continue to fulfill these arrangements throughout the remainder of their contractual term. These agreements currently have expiration dates of March 31, 2020 and 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, 2019 and 2018:

Chesapeake Utilities Corporation 2019 Form 10-K     Page 61

Notes to the Consolidated Financial Statements

	For the Year Ended December 31, 2019												For the Year Ended December 31, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	62,659		$	—		$	—		$	62,659		$	70,338		$	—		$	—		$	70,338
Florida natural gas division	28,485			—			—			28,485			25,341			—			—			25,341
FPU electric distribution	77,416			—			—			77,416			79,803			—			—			79,803
FPU natural gas distribution	82,418			—			—			82,418			81,118			—			—			81,118
Maryland natural gas division	22,517			—			—			22,517			24,172			—			—			24,172
Sandpiper natural gas/propane operations	19,068			—			—			19,068			22,088			—			—			22,088
Total energy distribution	292,563			—			—			292,563			302,860			—			—			302,860
Energy transmission
Aspire Energy	—			32,493			—			32,493			—			35,407			—			35,407
Eastern Shore	72,924			—			—			72,924			64,248			—			—			64,248
Peninsula Pipeline	16,453			—			—			16,453			11,927			—			—			11,927
Total energy transmission	89,377			32,493			—			121,870			76,175			35,407			—			111,582
Energy generation
Eight Flags	—			16,749			—			16,749			—			17,302			—			17,302
Propane operations
Propane delivery operations	—			107,964			—			107,964			—			123,603			—			123,603
Energy delivery services
Marlin Gas Services	—			5,702			—			5,702			—			121			—			121
Other and eliminations
Eliminations	(38,934		)	(10,407		)	(18,080		)	(67,421		)	(33,754		)	(16,486		)	(17,522		)	(67,762		)
Other	—			1,649			528			2,177			—			1,957			653			2,610
Total other and eliminations	(38,934		)	(8,758		)	(17,552		)	(65,244		)	(33,754		)	(14,529		)	(16,869		)	(65,152		)
Total operating revenues (1)	$	343,006		$	154,150		$	(17,552	)	$	479,604		$	345,281		$	161,904		$	(16,869	)	$	490,316

⁽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, and $0.2 million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, for the year ended December 31, 2018. 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

Chesapeake Utilities Corporation 2019 Form 10-K Page 62

Notes to the Consolidated Financial Statements

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

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 63

Notes to the Consolidated Financial Statements

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2019 and 2018 were as follows:

	Trade Receivables			Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2018	$	52,140		$	2,614	$	480
Balance at 12/31/2019	47,430			3,465		589
Increase (decrease)	$	(4,710	)	$	851	$	109

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 years ended December 31, 2019 and 2018, we recognized revenue of $1.0 million and $0.7 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, 2019 are expected to be recognized as follows:

(in thousands)	2020		2021		2022		2023		2024		2025 and thereafter
Eastern Shore and Peninsula Pipeline	$	37,307	$	34,000	$	27,034	$	21,608	$	19,385	$	194,868
Natural gas distribution operations	3,996		4,058		5,100		4,916		4,681		37,149
FPU electric distribution	566		566		566		566		566		1,100
Total revenue contracts with remaining performance obligations	$	41,869	$	38,624	$	32,700	$	27,090	$	24,632	$	233,117

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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 64

Notes to the Consolidated Financial Statements

• Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and our mobile compressed natural gas and pipeline solutions subsidiary. 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, PESCO's results, previously reported in the Unregulated Energy segment, are reflected in discontinued operations. See Note 4, Acquisitions and Divestitures for additional details regarding the divestiture of PESCO.

The remainder of our operations is 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,
	2019			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	340,857		$	343,313		$	323,972
Unregulated Energy	138,747			147,003			125,674
Total operating revenues, unaffiliated customers	$	479,604		$	490,316		$	449,646
Intersegment Revenues (1)
Regulated Energy	$	2,149		$	1,968		$	2,338
Unregulated Energy	15,403			14,902			14,402
Other businesses	528			652			774
Total intersegment revenues	$	18,080		$	17,522		$	17,514
Operating Income
Regulated Energy	$	86,584		$	79,215		$	74,584
Unregulated Energy	19,939			17,124			14,941
Other businesses and eliminations	(236		)	(1,496		)	205
Operating Income	106,287			94,843			89,730
Other expense, net	(1,830		)	(603		)	(2,204		)
Interest charges	22,224			16,146			12,530
Income from Continuing Operations before Income Taxes	$	82,233		$	78,094		$	74,996
Income Taxes on Continuing Operations	21,091			21,232			14,670
Income from Continuing Operations	61,142			56,862			60,326
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)
Gain on sale of Discontinued Operations, Net of tax	5,402			—			—
Net Income	$	65,153		$	56,580		$	58,124
Depreciation and Amortization
Regulated Energy	$	35,227		$	31,876		$	28,554
Unregulated Energy	10,129			8,263			7,741
Other businesses and eliminations	67			81			91
Total depreciation and amortization	$	45,423		$	40,220		$	36,386
Capital Expenditures
Regulated Energy	$	130,604		$	235,912		$	159,011
Unregulated Energy	60,034			38,585			14,424
Other businesses	8,348			8,364			5,902
Total capital expenditures	$	198,986		$	282,861		$	179,337

 

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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 65

Notes to the Consolidated Financial Statements

	As of December 31,
	2019		2018
Identifiable Assets (1)
Regulated Energy segment	$	1,434,066	$	1,345,805
Unregulated Energy segment (1)	296,810		245,702
Other businesses and eliminations	52,322		41,821
Total identifiable assets (1)	$	1,783,198	$	1,633,328

⁽¹⁾ 2018 balance excludes assets held for sale related to the sale of assets and contracts for PESCO.

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2019, 2018 and 2017 were as follows:

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Cash paid for interest	$	22,611	$	16,741	$	12,420
Cash paid for income taxes, net of refunds	$	3,221	$	477	$	(4,114	)

Non-cash investing and financing activities during the years ended December 31, 2019, 2018, and 2017 were as follows: 

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	13,470	$	39,402	$	15,457
Common stock issued under the SICP	$	1,691	$	2,006	$	1,127
Capital lease obligation	$	—	$	1,310	$	2,070

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. 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. Aspire Energy 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. As of December 31, 2019 and 2018, 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 to UET, NJRES, Gas South, and DFS and, therefore, no longer have natural gas futures and contracts recorded in our consolidated financial statements. The gains and losses associated with PESCO's financial instruments are reflected as discontinued operations in the consolidated statements of income and PESCO's assets and liabilities are reflected as held-for-sale in the consolidated balance sheets.

Volume of Derivative Activity

As of December 31, 2019, 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)	9.9	Cash flows hedges	June 2022

Chesapeake Utilities Corporation 2019 Form 10-K Page 66

Notes to the Consolidated Financial Statements

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 2019 through June 2022) 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 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 $1.5 million from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2020.

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 MTM 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, 2019		December 31, 2018
Sharp	Other Current Assets	$	2,317	$	2,173

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. As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets and liabilities held-for-sale in the consolidated balance sheet as of December 31, 2018. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2019 and 2018 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	71
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	—		11
Total Derivative Assets		$	—	$	82

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	$	1,844	$	1,604
Total Derivative Liabilities		$	1,844	$	1,604

Chesapeake Utilities Corporation 2019 Form 10-K     Page 67

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)		2019			2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	—		$	112
Propane swap agreements	Cost of sales	—			(13		)	8
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	1,520			(647		)	1,607
Propane swap agreements	Other comprehensive income (loss)	(253		)	(2,773		)	487
Natural gas swap contracts	Other comprehensive income (loss)	(63		)	200			986
Natural gas futures contracts	Other comprehensive income (loss)	(294		)	532			(1,476		)
Total		$	910		$	(2,701	)	$	1,715

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represented the effect of trading activities for Xeron on our consolidated statement of income.

As of December 31, 2019 and 2018, we did not have any material fair value hedges.

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 and 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 2019 Form 10-K Page 68

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, 2019 and 2018, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2018	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets (1)	82		—		82		—
Total assets	$	6,793	$	6,025	$	82	$	686
Liabilities:
Derivative liabilities (1)	$	1,604	$	—	$	1,604	$	—

⁽¹⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 69

Notes to the Consolidated Financial Statements

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Beginning Balance	$	686		$	648
Purchases and adjustments	131			68
Transfers/disbursements	(29		)	(41		)
Investment income	15			11
Ending Balance	$	803		$	686

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

At December 31, 2019 and 2018, 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 short maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2019, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $486.6 million, compared to the estimated fair value of $505.0 million. At December 31, 2018, long-term debt, which includes the current maturities but excludes finance lease obligations and debt issuance costs, had a carrying value of $327.2 million, compared to a fair value of $323.8 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, 2019 and 2018, consisted of the following:

	As of December 31,
(in thousands)	2019		2018
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	9,202	$	6,689
Investments in equity securities	27		22
Total	$	9,229	$	6,711

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2019, 2018 and 2017, we recorded net unrealized gains of $1.6 million, net unrealized losses of $0.4 million, and net unrealized gains of $1.0 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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 70

Notes to the Consolidated Financial Statements

11. GOODWILL AND OTHER INTANGIBLE ASSETS

The carrying value of goodwill from continuing operations as of December 31, 2019 and 2018 was as follows:

	As of December 31,
(in thousands)	2019		2018
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy(2)
Mid-Atlantic Propane Operations(3)	13,299		2,147
Florida Propane Operations	1,188		1,188
Aspire Energy	10,120		10,120
Marlin Gas Services	4,708		4,760
Total Goodwill	$	32,668	$	21,568

⁽¹⁾ Florida Natural Gas Distribution includes Chesapeake Utilities' Central Florida Gas division, FPU and FPU's Indiantown and Fort Meade divisions.

⁽²⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. The goodwill balance for PESCO is reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018.

⁽³⁾ Mid-Atlantic Propane Operations goodwill balance includes $11.2 million recognized as a result of the purchase of the operating assets of Boulden in December 2019.

The annual impairment testing for 2019 and 2018 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2019 and 2018 are as follows:

	As of December 31,
	2019				2018
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	9,391	$	3,463	$	4,801	$	3,066
Non-Compete agreements (1) (2)	2,252		451		1,793		202
Patents	452		118		452		—
Other	270		204		270		198
Total	$	12,365	$	4,236	$	7,316	$	3,466

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

⁽²⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. Intangible assets for PESCO are reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018 and amortization is reflected as discontinued operations in the consolidated statements of income.

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, 2019 was $0.8 million and $0.4 million for both years ended December 31, 2018 and 2017. Amortization expense of intangible assets is expected to be $1.2 million for the years 2020 and 2021, $0.9 million for the year 2022 and $0.8 million for the years 2023 and 2024.

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 2014 are subject to examination. At December 31, 2019, the 2015 through 2018 federal income tax returns are under examination, and no report has been issued at this time.

We had a net operating loss for federal income tax purposes as of December 31, 2019 totaling $3.0 million. We will have a federal net operating loss totaling $12.2 million for 2018 upon the settlement of the Internal Revenue Service audit described above. We did not have a federal net operating loss for tax year 2017. For state income tax purposes, we had net operating losses in various

Chesapeake Utilities Corporation 2019 Form 10-K     Page 71

Notes to the Consolidated Financial Statements

states of $54.7 million and $60.1 million as of December 31, 2019 and 2018, respectively, almost all of which will expire in 2038. Excluding net operating losses from discontinued operations we have recorded deferred tax assets of $5.5 million and $2.0 million related to state net operating loss carry-forwards at December 31, 2019 and 2018, respectively, but we have not recorded a valuation allowance to reduce the future benefit of the tax net operating losses because we believe they will be fully utilized.

Federal Tax Reform

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.

In 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flow hedges.

The following tables provide: (a) the components of income tax expense in 2019, 2018, and 2017; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2019, 2018, and 2017 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2019 and 2018.

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Current Income Tax Expense
Federal	$	(2,271	)	$	48		$	2,046
State	(492		)	581			610
Other	(47		)	(47		)	(71		)
Total current income tax expense (benefit)	(2,810		)	582			2,585
Deferred Income Tax Expense (1)
Property, plant and equipment	25,910			19,189			8,181
Deferred gas costs	79			(1,435		)	2,002
Pensions and other employee benefits	(454		)	446			180
FPU merger-related premium cost and deferred gain	(278		)	(528		)	(1,148		)
Net operating loss carryforwards	(3,776		)	(183		)	193
Other	2,420			3,161			2,677
Total deferred income tax expense	23,901			20,650			12,085
Income Tax Expense from Continuing Operations	21,091			21,232			14,670
Income Tax Expense (benefit) from Discontinued Operations	1,439			(238		)	(361		)
Total Income Tax	$	22,530		$	20,994		$	14,309

⁽¹⁾ Includes $4.7 million, $3.5 million, and $0.9 million of deferred state income taxes for the years 2019, 2018 and 2017, respectively.

Chesapeake Utilities Corporation 2019 Form 10-K Page 72

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	17,246		$	16,491		$	26,249
State income taxes, net of federal benefit	5,088			4,057			2,000
ESOP dividend deduction	(173		)	(158		)	(257		)
Revaluation of deferred tax assets and liabilities	—			—			(14,299		)
Other	(1,070		)	842			977
Total Income Tax Expense for Continuing Operations	$	21,091		$	21,232		$	14,670
Effective Income Tax Rate for Continuing Operations (2)	25.65		%	27.19		%	19.56		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2019 and 2018 and 35 percent for 2017.

⁽²⁾The effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA.

	As of December 31,
	2019		2018
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	173,466	$	153,423
Acquisition adjustment	6,969		8,896
Loss on reacquired debt	220		32
Deferred gas costs	1,223		1,139
Natural gas conversion costs	4,956		3,987
Storm reserve liability	10,316		97
Other	1,456		2,544
Total deferred income tax liabilities	198,606		170,118
Deferred income tax assets:
Pension and other employee benefits	3,818		3,711
Environmental costs	1,486		1,710
Net operating loss carryforwards	5,523		2,010
Self-insurance	146		151
Storm reserve liability	96		—
Other	6,881		5,716
Total deferred income tax assets	17,950		13,298
Deferred Income Taxes Per Consolidated Balance Sheets	$	180,656	$	156,820

Chesapeake Utilities Corporation 2019 Form 10-K     Page 73

Notes to the Consolidated Financial Statements

13. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,990		$	7,986
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	2,000			4,000
5.93% note, due October 31, 2023	12,000			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			7,000
3.73% note, due December 16, 2028	18,000			20,000
3.88% note, due May 15, 2029	50,000			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			—
2.98% note, due December 20, 2034	70,000			—
Term Note due January 21, 2020	—			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligations	—			1,310
Less: debt issuance costs	(822		)	(567		)
Total long-term debt	485,768			327,955
Less: current maturities	(45,600		)	(11,935		)
Total long-term debt, net of current maturities	$	440,168		$	316,020

Annual maturities

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

Year	2020		2021		2022		2023		2024		Thereafter		Total
(in thousands)
Payments	$	45,600	$	13,600	$	25,100	$	20,600	$	17,600	$	364,100	$	486,600

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL who are under no obligation to purchase any unsecured debt. The Prudential Shelf Agreement totaling $150.0 million was entered into in October 2015 and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was amended in September 2018 to increase the borrowing capacity back to $150.0 million, and in August 2019, we issued $100.0 million of 3.98% unsecured debt. In January 2020, we submitted a request for Prudential to purchase $50 million of our unsecured debt which was accepted and confirmed by Prudential. The Shelf notes will bear interest at the rate of 3.00% per annum and the proceeds received from the issuance will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the issuance of the Shelf Notes is expected to occur on or before July 15, 2020.

The NYL Shelf Agreement totaling $100.0 million was entered into in March 2017 and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement was amended in November 2018 to provide additional borrowing capacity of $50.0 million. As of December 31, 2019, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement, which we entered into in March 2017. In February 2020, we submitted a request for NYL to purchase $40.0 million of our unsecured debt which was accepted and confirmed by NYL. The Shelf notes will bear interest at the rate of 2.96% per annum and the proceeds received from the issuance will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the issuance of the Shelf Notes is expected to occur on or before August 14, 2020.

Chesapeake Utilities Corporation 2019 Form 10-K Page 74

Notes to the Consolidated Financial Statements

The following table summarizes our shelf agreements at December 31, 2019:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	220,000	$	(170,000	)	$	—	$	50,000
MetLife Shelf Agreement	150,000		—			—		150,000
NYL Shelf Agreement (2)	150,000		(100,000		)	—		50,000
Total	$	520,000	$	(270,000	)	$	—	$	250,000

⁽¹⁾ As described above, in January 2020, we requested and Prudential accepted our request to purchase $50.0 million of our unsecured debt.

⁽²⁾ As described above, in February 2020, we requested and NYL accepted our request to purchase $40.0 million of our unsecured debt.

The Uncollateralized 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 December 2018, we issued a $30 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. This note was paid off in December 2019 utilizing the proceeds from the issuance of uncollateralized senior notes discussed below. 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. The interest rate, at December 31, 2019, was 2.46%, which equals the one-month LIBOR rate plus 75 basis points. As of December 31, 2019, this term note is included in the current maturities of long-term debt.

Secured First Mortgage Bonds

We guaranteed FPU’s first mortgage bonds, which are secured by a lien covering all of FPU’s property. FPU’s first mortgage bonds contain a restriction that limits the payment of dividends by FPU to an amount less than the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2019, FPU’s cumulative net income base was $168.1 million, offset by restricted payments of $37.6 million, leaving $130.5 million of available dividend capacity.

The dividend restrictions in FPU’s first mortgage bonds resulted in approximately $38.8 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2019. This represents approximately 6.92% of our consolidated net assets. Other than the dividend restrictions associated with FPU’s first mortgage bonds, there are no legal, contractual or regulatory restrictions on the net assets of our subsidiaries.

Uncollateralized Senior Notes

In December 2019, we issued $70.0 million of 2.98% uncollateralized senior notes to four financial institutions.  We used the proceeds to pay off the $30 million PNC Term Note described above, reduce our short-term borrowing amount and to finance our purchase of certain propane operating assets of Boulden.

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, 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% 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, 2019, the cumulative consolidated net income base was $509.5 million, offset by restricted payments of $227.5 million, leaving $282.0 million of cumulative net income free of restrictions. As of December 31, 2019, we are in compliance with all of our debt covenants.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 75

Notes to the Consolidated Financial Statements

14. SHORT-TERM BORROWINGS

At December 31, 2019 and 2018, we had $247.4 million and $294.5 million, respectively, of short-term borrowings outstanding at the weighted average interest rates of 2.62 percent and 3.44 percent, respectively. We have an aggregate of $370.0 million in credit lines comprised of four unsecured bank credit facilities with four financial institutions, with $220.0 million in total available credit, and a Revolver with five participating Lenders totaling $150.0 million. All of these facilities expire in October 2020. We incurred commitment fees of $0.1 million in 2019, 2018 and 2017. The following table summarizes our short-term borrowing facilities information at December 31, 2019 and 2018.

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2019		December 31, 2018		Available at December 31, 2019
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 0.75 percent	$	55,000	$	25,000	$	—
Committed revolving credit facility B	80,000		plus 0.75 percent	57,150		65,431		22,850
Committed revolving credit facility C	45,000		plus 0.75 percent	42,040		34,672		2,960
Committed revolving credit facility D	40,000		plus 0.85 percent	40,000		40,000		—
Committed revolving credit facility E(2)	150,000		plus 1.125 percent	50,000		125,000		100,000
Total short term credit facilities	$	370,000		$	244,190	$	290,103	$	125,810
Book overdrafts(1)				3,181		4,355
Total short-term borrowing				$	247,371	$	294,458

⁽¹⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

⁽²⁾ This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving credit facility, shall not exceed $250.0 million.

We are authorized by our Board of Directors to borrow up to $370.0 million of short-term debt, as required, from these short-term lines of credit. These bank credit facilities are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, 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 our revolving credit facilities to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2019, we are in compliance with all of our debt covenants.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 76

Notes to the Consolidated Financial Statements

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, 2019, 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, 2019, 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	2019		2018
Operating lease cost (1)	Operations expense	$	2,577	$	3,339
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	650		1,451
Interest on lease liabilities	Interest expense	5		49
Net lease cost		$	3,232	$	4,839

⁽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, 2019:

(in thousands)	Balance sheet classification	Amount
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,896
Total lease liabilities		$	11,601

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

	December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.88
Weighted-average discount rate
Operating leases	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 as of December 31, 2019 and 2018:

	Year Ended December 31,
(in thousands)	2019		2018
Operating cash flows from operating leases	$	2,230	$	2,759
Operating cash flows from finance leases	$	5	$	49
Financing cash flows from finance leases	$	650	$	1,451

Chesapeake Utilities Corporation 2019 Form 10-K     Page 77

Notes to the Consolidated Financial Statements

The following table presents the future undiscounted maturities of our operating leases at December 31, 2019 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2020	$	2,104
2021	1,866
2022	1,716
2023	1,719
2024	1,463
Thereafter	4,916
Total lease payments	13,784
Less: Interest	2,183
Present value of lease liabilities	$	11,601

⁽¹⁾  Operating lease payments include $3.7 million related to options to extend lease terms that are reasonably certain of being exercised.

16. STOCKHOLDERS' EQUITY

Accumulated Other Comprehensive (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures and swap contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). In 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contract cash flow hedges. The following table presents the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2019 and 2018. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	(602		)	(3,130		)	(3,732		)
Amounts reclassified from accumulated other comprehensive income	439			1,759			2,198
Net current-period other comprehensive loss	(163		)	(1,371		)	(1,534		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
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	)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2019, 2018 and 2017. Deferred gains and losses of our commodity contracts cash flow hedges are recognized in earnings upon settlement.

Chesapeake Utilities Corporation 2019 Form 10-K Page 78

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
(in thousands)	2019			2018			2017
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(2,600		)	(579		)	(636		)
Total before income taxes	(2,523		)	(502		)	(559		)
Income tax benefit (4)	656			63			223
Net of tax	$	(1,867	)	$	(439	)	$	(336	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	1,520		$	(647	)	$	1,607
Natural gas swaps (2)(3)	7			197			(822		)
Natural gas futures (2)(3)	2,096			(2,010		)	(456		)
Total before income taxes	3,623			(2,460		)	329
Income tax impact (4)	(1,028		)	701			(159		)
Net of tax	$	2,595		$	(1,759	)	$	170
Total reclassifications for the period	$	728		$	(2,198	)	$	(166	)

⁽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 Pension Plan, the FPU Pension Plan and the Chesapeake unfunded supplemental executive retirement pension plan ("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-

Chesapeake Utilities Corporation 2019 Form 10-K     Page 79

Notes to the Consolidated Financial Statements

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, 2019 and 2018, 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, 2019 and 2018 and the net periodic cost for the years ended December 31, 2019, 2018 and 2017 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2019			2018			2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	10,712		$	11,443		$	59,377		$	64,664		$	2,285		$	2,428
Interest cost	375			384			2,452			2,339			74			83
Actuarial loss (gain)	1,443			(610		)	6,508			(4,739		)	159			(74		)
Effect of settlement	(5,833		)	—			—			—			—			—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Benefit obligation — end of year	6,214			10,712			65,304			59,377			2,157			2,285
Change in plan assets:
Fair value of plan assets — beginning of year	8,649			9,350			43,601			48,396			—			—
Actual return on plan assets	1,180			(647		)	7,978			(3,113		)	—			—
Employer contributions	1,117			451			1,157			1,205			361			152
Effect of settlement	(5,833		)	—			—			—						—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Fair value of plan assets — end of year	4,630			8,649			49,703			43,601			—			—
Reconciliation:
Funded status	(1,584		)	(2,063		)	(15,601		)	(15,776		)	(2,157		)	(2,285		)
Accrued pension cost	$	(1,584	)	$	(2,063	)	$	(15,601	)	$	(15,776	)	$	(2,157	)	$	(2,285	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%	3.00		%	4.00		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%	—		%	—		%

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2019 (1)			2018			2017			2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic pension cost:
Interest cost	$	375		$	384		$	402		$	2,452		$	2,339		$	2,482		$	74		$	83		$	89
Expected return on assets	(487		)	(542		)	(495		)	(2,770		)	(3,091		)	(2,779		)	—			—			—
Amortization of actuarial loss	391			343			399			505			404			513			85			101			87
Settlement expense	1,982			—			—			—			—			—			58			—			—
Net periodic pension cost	2,261			185			306			187			(348		)	216			217			184			176
Amortization of pre-merger regulatory asset	—			—			—			543			761			761			—			—			—
Total periodic cost	$	2,261		$	185		$	306		$	730		$	413		$	977		$	217		$	184		$	176
Assumptions:
Discount rate	3.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	6.50		%	—		%	—		%	—		%

Chesapeake Utilities Corporation 2019 Form 10-K Page 80

Notes to the Consolidated Financial Statements

⁽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 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, 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 trustee 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, 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, 2019, 2018 and 2017:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2019		2018		2017		2019		2018		2017
Asset Category
Equity securities	—	%	49	%	53	%	53	%	50	%	55	%
Debt securities	92	%	41	%	38	%	37	%	41	%	37	%
Other	8	%	10	%	9	%	10	%	9	%	8	%
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 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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 81

Notes to the Consolidated Financial Statements

At December 31, 2019 and 2018, 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, 2019								At December 31, 2018
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)	$	3,553	$	—	$	—	$	3,553	$	3,399	$	—	$	—	$	3,399
U.S. Mid Cap (1)	1,604		—		—		1,604		1,478		—		—		1,478
U.S. Small Cap (1)	726		—		—		726		670		—		—		670
International (2)	9,855		—		—		9,855		9,226		—		—		9,226
Alternative Strategies (3)	4,739		—		—		4,739		5,726		—		—		5,726
	20,477		—		—		20,477		20,499		—		—		20,499
Mutual Funds - Debt securities
Fixed income (4)	19,220		—		—		19,220		18,630		—		—		18,630
High Yield (4)	2,476		—		—		2,476		2,818		—		—		2,818
	21,696		—		—		21,696		21,448		—		—		21,448
Mutual Funds - Other
Commodities (5)	1,708		—		—		1,708		1,902		—		—		1,902
Real Estate (6)	2,288		—		—		2,288		2,216		—		—		2,216
Guaranteed deposit (7)	—		—		1,147		1,147		—		—		627		627
	3,996		—		1,147		5,143		4,118		—		627		4,745
Total Pension Plan Assets in fair value hierarchy	$	46,169	$	—	$	1,147	47,316		$	46,065	$	—	$	627	46,692
Investments measured at net asset value (8)							7,017								5,558
Total Pension Plan Assets							$	54,333							$	52,250

⁽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, 2019 and 2018, all of the 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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 82

Notes to the Consolidated Financial Statements

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Balance, beginning of year	$	627		$	436
Purchases	2,274			1,674
Transfers in	3,090			2,375
Disbursements	(4,907		)	(3,872		)
Investment income	63			14
Balance, end of year	$	1,147		$	627

Other Postretirement Benefits Plans

We sponsor two defined benefit postretirement health plans: the Chesapeake Postretirement Plan and the FPU Medical Plan. The following table sets forth the funded status at December 31, 2019 and 2018:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,002		$	1,128		$	1,187		$	1,287
Interest cost	39			38			48			47
Plan participants contributions	149			136			38			41
Actuarial loss (gain)	73			(131		)	47			(89		)
Benefits paid	(163		)	(169		)	(96		)	(99		)
Benefit obligation — end of year	1,100			1,002			1,224			1,187
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	14			33			58			58
Plan participants contributions	149			136			38			41
Benefits paid	(163		)	(169		)	(96		)	(99		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,100		)	(1,002		)	(1,224		)	(1,187		)
Accrued postretirement cost	$	(1,100	)	$	(1,002	)	$	(1,224	)	$	(1,187	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%

⁽¹⁾ The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 83

Notes to the Consolidated Financial Statements

Net periodic postretirement benefit costs for 2019, 2018, and 2017 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	39		$	38		$	41		$	48		$	47		$	50
Amortization of actuarial loss	46			58			53			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	8			19			17			48			47			50
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost	$	8		$	19		$	17		$	56		$	55		$	58
Assumptions
Discount rate	4.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%

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, 2019:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(447	)	$	—		$	(447	)
Net loss (gain)	2,241		19,339		575		604			(32		)	22,727
Total	$	2,241	$	19,339	$	575	$	157		$	(32	)	$	22,280
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,241	$	3,674	$	575	$	157		$	(6	)	$	6,641
Post-merger regulatory asset	—		15,665		—		—			(26		)	15,639
Subtotal	2,241		19,339		575		157			(32		)	22,280
Pre-merger regulatory asset	—		—		—		—			6			6
Total unrecognized cost	$	2,241	$	19,339	$	575	$	157		$	(26	)	$	22,286

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2019 is net of income tax benefits of $1.7 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. FPU continues to maintain and amortize a portion of the unrecognized postretirement benefit costs prior to the merger with Chesapeake Utilities related to its regulated operations, which is shown as a pre-merger regulatory asset. The portion of the regulatory asset related to the FPU Pension was fully amortized at December 31, 2019.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2019, 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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 84

Notes to the Consolidated Financial Statements

The health care inflation rate for 2019 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 2020, we expect to contribute $0.3 million and $3.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $0.2 million to the Chesapeake SERP. We also expect to contribute $0.1 million to both the Chesapeake Postretirement Plan and FPU Medical Plan, in 2020.

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)
2020	$	115	$	3,281	$	151	$	90	$	86
2021	$	368	$	3,348	$	150	$	87	$	90
2022	$	106	$	3,424	$	148	$	85	$	91
2023	$	927	$	3,498	$	146	$	67	$	79
2024	$	111	$	3,549	$	144	$	64	$	80
Years 2025 through 2029	$	2,300	$	18,429	$	748	$	264	$	389

⁽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, 2019, 2018 and 2017, 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 $5.7 million, $5.5 million, and $5.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019, there were 831,183 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

Chesapeake Utilities Corporation 2019 Form 10-K     Page 85

Notes to the Consolidated Financial Statements

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 $9.2 million and $6.7 million at December 31, 2019 and 2018, 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 $4.5 million and $3.9 million at December 31, 2019 and 2018, 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 449,868 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, 2019, 2018 and 2017:

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Awards to non-employee directors	$	620		$	539		$	540
Awards to key employees	3,659			2,871			1,950
Total compensation expense	4,279			3,410			2,490
Less: tax benefit	(1,117		)	(934		)	(1,003		)
Share-based compensation amounts included in net income	$	3,162		$	2,476		$	1,487

Stock Options

There were no stock options outstanding or issued during the years 2017 through 2019.

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 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for board service through the 2019 Annual Meeting of Stockholders; accordingly, 7,128 shares, with a weighted average fair value of $75.70 per share, were issued and vested in 2018. In May 2019, each of our non-employee directors received an annual retainer of 751 shares of common stock under the SICP for service as a director 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 January 2020, a newly appointed member of the 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 will be recognized over the remaining service period ending on the 2020 Annual Meeting of Stockholders.

At December 31, 2019, there was $0.2 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 2020 Annual Meeting of Stockholders.

Our former President and Chief Executive Officer, Michael P. McMasters, retired as an executive officer on December 31, 2018 but continued as a member of the Board of Directors until the 2019 Annual Meeting of Stockholders. Mr. McMasters received a pro-rated grant of 276 shares of common stock under the SICP for service as a non-employee director from January 1, 2019 through May 8, 2019. The shares awarded to Mr. McMasters vested immediately upon issuance in January 2019, had a weighted average fair value of $81.30 per share, and were fully expensed as of the 2019 Annual Meeting of Stockholders.

Chesapeake Utilities Corporation 2019 Form 10-K Page 86

Notes to the Consolidated Financial Statements

Key Employees

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

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 or 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 Black-Scholes pricing model 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, 2017	132,642		$	59.31
Granted	49,494		67.76
Vested	(29,786	)	47.39
Vested - Accelerated pursuant to separation agreement	(16,676	)	75.78
Expired	(3,933	)	49.66
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

⁽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 $15.1 million, $10.7 million and $10.4 million in 2019, 2018 and 2017, respectively. At December 31, 2019, there was $4.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2021.

In June 2018, we entered into a separation agreement and release (the "Separation Agreement") with a former executive officer. Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock previously granted to the executive officer under the SICP, immediately vested at the time of separation; 2,569 shares were forfeited, and we recognized $1.1 million as share-based compensation expense.

In 2019, 2018 and 2017, 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, amounts remitted to taxing authorities and the tax benefits associated with these obligations:

	For the Year Ended December 31,
	2019		2018		2017
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	7,635		16,918		10,269
Amounts remitted to tax authorities to satisfy obligations	$	692	$	1,210	$	692
Tax benefit associated with settlement of share based payments	$	—	$	—	$	349

Chesapeake Utilities Corporation 2019 Form 10-K     Page 87

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, our intrastate pipeline subsidiary, is subject to regulation (excluding cost of service) by the Florida PSC.

Delaware

Effect of the TCJA on Customers: In January 2019, the Delaware PSC approved the as-filed Delaware Division Delivery Service Rates reflecting the impact of the TCJA.  The new rates went into effect in March 2019. The refunds, which were retroactive to February 2018, were completed prior to the mandated deadline of June 2019.  The order also provided for a line item billing credit that went into effect in April 2019, for the return of the excess accumulated deferred income taxes ("ADIT"). 

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 propose to acquire each CGS one at a time and to pay replacement cost for each CGS system. In addition, we are requesting 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. In September 2019, the Delaware PSC issued an order to open a docket for the purpose of reviewing our application and to conduct evidentiary hearings on the matter. We are currently responding to discovery requests and an evidentiary hearing is scheduled for the second quarter of 2020.

Maryland

Approval of the Elkton Gas Company Acquisition: In December 2019, we entered into an agreement with SJI to acquire its subsidiary, Elkton Gas Company, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Upon completion of the transaction, Elkton Gas Company will become our wholly-owned subsidiary. The acquisition, which is expected to close in the second half of 2020, is subject to approval by the Maryland PSC. Elkton Gas Company's territory is contiguous to our franchised service territory in Cecil County, Maryland and it will continue to operate out of its existing office with the same local personnel.

Florida

Electric Limited Proceeding-Storm Recovery (Pre-Hurricane Michael): In February 2018, FPU filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of the storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and, at the time of filing the petition, had a deficit of $0.8 million. This matter went to hearing in December 2018 and was subsequently approved at the March 2019 Agenda with the Final Order issued on March 25, 2019. FPU received approval to begin a surcharge on customer bills for two years beginning in April 2019, to recover storm-related costs and replenish the storm reserve.

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, amounts currently being reviewed by the Florida PSC for regulatory asset treatment have been recorded as receivables and other deferred charges. In December 2018 and January 2019, we executed two 13-month unsecured term loans as temporary financing for the Hurricane Michael-related expenditures, each in the amount of $30.0 million. The interest cost associated with these loans is the one-month LIBOR rate plus 75 basis points. In December 2019, we utilized the proceeds from the issuance of uncollateralized senior notes to repay the term notes issued in December 2018.

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 the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC in November 2019 and temporary rate increases were implemented effective January 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 2020.

Chesapeake Utilities Corporation 2019 Form 10-K Page 88

Notes to the Consolidated Financial Statements

Effect of the TCJA on Customers: In February 2018, the Florida PSC opened dockets to consider the impacts associated with the TCJA. In May 2018, FPU’s natural gas divisions filed petitions and supporting testimony regarding the disposition of the related impacts of the TCJA. Hearings on this matter took place in November 2018, and the staff's recommendation was approved by the Florida PSC at the February 2019 Agenda and final orders were issued on February 25, 2019. Staff’s recommendations are summarized in the table at the end of this section.

Electric Depreciation Study: In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The new rates will be effective January 1, 2020. The petition has not been scheduled for approval by the Florida PSC.

Natural Gas Depreciation Study: In March 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated natural gas depreciation rates. The petition was approved by the Florida PSC at Agenda on October 3, 2019. The new rates were effective retroactive to January 1, 2019, and are expected to decrease depreciation expense by approximately $0.9 million annually.

Auburndale Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with the Florida Division of Chesapeake Utilities. Peninsula Pipeline will purchase an existing pipeline owned by the Florida Division of Chesapeake Utilities and Calpine and construct pipeline facilities in Polk County, Florida. Peninsula Pipeline will provide transportation service to the Florida Division of Chesapeake Utilities increasing both delivery capacity and downstream pressure as well as introducing a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. The petition was approved by the Florida PSC at the August 6, 2019 Agenda. The project was placed in service in the third quarter of 2019.

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.

Callahan Pipeline Project, Nassau County: In July 2019, Peninsula Pipeline filed a petition for approval of the firm transportation service agreement with FPU and the restructuring of the business and operational agreements between Peoples Gas, FPU and Seacoast Gas Transmission. Peninsula Pipeline will construct and jointly own 26 miles of 16 inch steel pipeline with Seacoast Gas Transmission and interconnect to the Cypress Pipeline interstate system in western Nassau County. The Callahan pipeline will terminate into the existing Peninsula Pipeline-Peoples Gas jointly owned pipeline, which serves Amelia Island and the Peoples Gas distribution system. Callahan pipeline will enhance FPU’s ability to expand service into Nassau County and will enable Peoples Gas to enhance its system pressure and reliability of its service in Duval County. This petition was approved by the Florida PSC at the December 10, 2019 Agenda. The project is expected to be placed in-service during the third quarter of 2020.

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. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021.

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 November 2019 after the end of 30 days of no opposing comments.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 89

Notes to the Consolidated Financial Statements

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)	$12,847	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)	$4,087	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)	$3,765	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)	$8,304	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)	$19,218	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$294	Same treatment on a net basis as Chesapeake 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 Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,769	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its 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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 90

Notes to the Consolidated Financial Statements

Regulatory Assets and Liabilities

At December 31, 2019 and 2018, 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,
	2019		2018
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	5,144	$	4,631
Under-recovered GRIP revenue (2)	—		165
Deferred postretirement benefits (3)	16,311		15,517
Deferred conversion and development costs (1)	20,881		16,727
Environmental regulatory assets and expenditures (4)	2,241		2,731
Acquisition adjustment (5)	30,329		33,255
Loss on reacquired debt (6)	869		942
Other	2,776		3,250
Total Regulatory Assets	$	78,551	$	77,218
Regulatory Liabilities
Self-insurance (7)	$	873	$	947
Over-recovered purchased fuel and conservation cost recovery (1)	2,724		5,856
Over-recovered GRIP revenue (2)	2,668		1,563
Storm reserve (7)	1,437		677
Accrued asset removal cost (8)	36,767		42,401
Deferred income taxes due to rate change (9)	89,191		91,236
Other	75		242
Total Regulatory Liabilities	$	133,735	$	142,922

⁽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. In 2019, we recorded as a regulatory asset 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 have self-insurance and storm reserves in our Florida 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.

⁽⁸⁾ See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

⁽⁹⁾ 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. 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 2019 Form 10-K     Page 91

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, 2019 and 2018, we had approximately $8.0 million and $9.1 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, 2019 and 2018, we have recovered approximately $11.9 million and $11.5 million, respectively, leaving approximately $2.1 million and $2.5 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)	Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. We expect to implement similar remedial actions on the site's west parcel in 2020.	Between $4.5 million to $15.4 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 2019 Form 10-K Page 92

Notes to the Consolidated Financial Statements

21. OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of the sale of PESCO's assets and contracts, effective October 1, 2019, these agreements are now managed by NJRES. See Note 4, Acquisitions and Divestitures for additional details regarding the sale of PESCO's assets and contracts.

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. Long-term agreements will commence on or about July 2020, and each has a 10-year term. Short-term agreements were entered for a one year term beginning July 2019 through July 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, 2019, 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. Eight Flags sells power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to our electric customers. Eight Flags also sells steam and heated water pursuant to a separate 20-year contract, to Rayonier 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	2020		2021-2022		2023-2024		Beyond 2024		Total
(in thousands)
Purchase Obligations	$	60,735	$	72,123	$	60,049	$	201,131	$	394,038

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, 2019 was $37.0 million. The aggregate amount guaranteed at December 31, 2019 was approximately $24.7 million, of which $16.3 million is related to the operations of PESCO, with the guarantees expiring on various dates through October 2020. The amounts related to PESCO will decrease as soon as those guarantees are transferred to the respective counterparties. See Note 4, Acquisitions and Divestitures, for additional details on the sale of assets and contracts for PESCO.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 13, Long-Term Debt, for further details).

As of December 31, 2019, we have issued letters of credit totaling approximately $5.4 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 August 22, 2020. There have been no draws on these letters of credit as of December 31, 2019. 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. The outstanding letters of credit as of December 31, 2019 also included those issued to support the operations of our divested

Chesapeake Utilities Corporation 2019 Form 10-K     Page 93

Notes to the Consolidated Financial Statements

subsidiary, PESCO. As a result of the sale of assets and contracts for PESCO, letters of credit related to PESCO will be terminated early or expire without being renewed in 2020.

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)
2019 (1)
Operating Revenues	$	160,464		$	94,541		$	92,626		$	131,973
Operating Income	$	44,123		$	18,164		$	14,358		$	29,642
Net Income:
Income from Continuing Operations	$	28,814		$	8,913		$	6,246		$	17,169
Loss from Discontinued Operations, Net of Tax	(149		)	(609		)	(624		)	(9		)
Gain on sale of Discontinued Operations, Net of Tax	—			—			—			5,402
	$	28,665		$	8,304		$	5,622		$	22,562
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
	$	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
	$	1.74		$	0.50		$	0.34		$	1.37
2018 (1)
Operating Revenues	$	168,831		$	93,872		$	93,400		$	134,214
Operating Income	$	40,853		$	12,238		$	12,879		$	28,873
Net Income:
Income from Continuing Operations	$	27,271		$	5,705		$	6,090		$	17,796
Income/(Loss) from Discontinued Operations	(415		)	680			(552		)	5
	$	26,856		$	6,385		$	5,538		$	17,801
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.67		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.03		)	0.04			(0.03		)	—
	$	1.64		$	0.39		$	0.34		$	1.09
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.66		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.02		)	0.04			(0.04		)	—
	$	1.64		$	0.39		$	0.33		$	1.09

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 94

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, 2019. 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, 2019.

CHANGE IN INTERNAL CONTROLS

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, 2019, 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, 2019. In addition, on June 7, 2019, 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, 2019.

Our independent auditors, Baker Tilly Virchow Krause, LLP, have audited the effectiveness of our internal control over financial reporting as of December 31, 2019, as stated in their report which appears under Part II, Item 8. Financial Statements and Supplementary Data. 

Chesapeake Utilities Corporation 2019 Form 10-K     Page 95

ITEM 9B. OTHER INFORMATION.

None.

PART III

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

In November 2019, we announced that Lila A. Jaber, Regional Managing Shareholder who leads the regulatory and legislative government affairs practice in Florida for Gunster Yoakley & Stewart, P.A., was appointed to serve as a member of our Board of Directors effective January 1, 2020.

We have adopted a Code of Ethics that applies to our Principal Executive Officer, President, Principal Financial Officer, Principal Accounting Officer, 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, Principal Accounting Officer or 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),” “Overview,” “Corporate Governance,” “Board of Directors and its Committees” and “Section 16(a) Beneficial Ownership Reporting Compliance.”

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.”

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.

Chesapeake Utilities Corporation 2019 Form 10-K Page 96

The following documents are filed as part of this report:

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

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

(a)(3) The Exhibits below.

•     Exhibit 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.
•     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 18, 2005, between Chesapeake Utilities Corporation, as issuer, and Prudential Investment Management, Inc., relating to the private placement of Chesapeake Utilities Corporation’s 5.5% Senior Notes due 2020, is incorporated herein by reference to Exhibit 4.1 of our Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590.
•     Exhibit 4.2	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 4.3	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 4.4	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 4.5	Form of Indenture of Mortgage and Deed of Trust dated September 1, 1942, between Florida Public Utilities Company and the trustee, for the First Mortgage Bonds, is incorporated herein by reference to Exhibit 7-A of Florida Public Utilities Company’s Registration No. 2-6087.
•      Exhibit 4.6	Seventeenth Supplemental Indenture dated April 12, 2011, between Chesapeake Utilities Corporation and Florida Public Utilities Company, pursuant to which Chesapeake Utilities Corporation guarantees the payment and performance obligations of Florida Public Utilities Company under the Indenture, is incorporated herein by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-11590.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 97

•       Exhibit 4.7	Sixteenth Supplemental Indenture dated December 1, 2009, between Chesapeake Utilities Corporation and Florida Public Utilities Company, pursuant to which Chesapeake Utilities Corporation guaranteed the secured First Mortgage Bonds of Florida Public Utilities Company under the Merger Agreement, is incorporated herein by reference to Exhibit 4.9 of our Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-11590.
•       Exhibit 4.8	Thirteenth Supplemental Indenture dated June 1, 1992, pursuant to which Florida Public Utilities, on May 1, 1992, privately placed $8,000,000 of its 9.08% First Mortgage Bonds due 2022, is incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1992.
•       Exhibit 4.9	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 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 4.10	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 4.11	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. †
•        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*	Executive Employment Agreement dated January 9, 2013, between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.10 of our Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-11590.
•        Exhibit 10.5*	Executive Employment Agreement dated January 1, 2015, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.15 of our Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-11590.
•        Exhibit 10.6*	Form of Performance Share Agreement, effective January 13, 2015 for the period 2015 to 2017, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.19 of our Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-11590.
•        Exhibit 10.7*	Form of Performance Share Agreement, dated March 6, 2015 for the period 2015 to 2017, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and 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 year ended September 30, 2015, File No. 001-11590.
•        Exhibit 10.8*	Form of Performance Share Agreement, dated January 12, 2016 for the period 2016 to 2018, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner, Jeffry M. Householder and James F. Moriarty, is incorporated herein by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-11590.

Chesapeake Utilities Corporation 2019 Form 10-K Page 98

•      Exhibit 10.9*	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 10.10*	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 10.11	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 10.12	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 10.13*	Executive Employment Agreement dated May 10, 2016, between Chesapeake Utilities Corporation 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, 2016, File No. 001-11590.
•     Exhibit 10.14*	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 Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner, 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 10.15	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 10.16*	Separation Agreement and Release, effective as of June 7, 2018, by and between Chesapeake Utilities Corporation and Elaine B. Bittner, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on June 8, 2018, File No. 001-11590.
•     Exhibit 10.17*	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 Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, 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 10.18	Term Note dated December 21, 2018 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is incorporated herein by reference to Exhibit 10.23 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.
•      Exhibit 10.19*	Form of Performance Share Agreement, effective February 25, 2019 for the period January 01, 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 10.20*	Executive Employment Agreement dated February 25, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.25 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.
•      Exhibit 10.21	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.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 99

•      Exhibit 10.22	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 10.23*	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 10.24	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 10.25*	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 filed herewith.
•      Exhibit 10.26*	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 filed herewith.
•      Exhibit 10.27*	Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Kevin Webber, is filed herewith.
•      Exhibit 10.28*	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 filed herewith.
•      Exhibit 10.29*	Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is filed herewith.
•      Exhibit 10.30*	Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.
•      Exhibit 10.31*	Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and James F. Moriarty, is filed herewith.
•       Exhibit 21	Subsidiaries of the Registrant is filed herewith.
•       Exhibit 23.1	Consent of Independent Registered Public Accounting Firm is filed herewith.
•       Exhibit 31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.
•       Exhibit 32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
•       Exhibit 32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.
•       Exhibit 101.INS XBRL Instance Document is filed herewith.
•       Exhibit 101.SCH XBRL Taxonomy Extension Schema Document is filed herewith.
•       Exhibit 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document is filed herewith.
•       Exhibit 101.DEF XBRL Taxonomy Extension Definition Linkbase Document is filed herewith.
•       Exhibit 101.LAB XBRL Taxonomy Extension Label Linkbase Document is filed herewith.

Chesapeake Utilities Corporation 2019 Form 10-K Page 100

•       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 2019 Form 10-K     Page 101

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 26, 2020

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 26, 2020	and Assistant Corporate Secretary
	(Principal Financial and Accounting Officer)
	February 26, 2020
/S/ JOHN R. SCHIMKAITIS	/S/ DENNIS S. HUDSON, III
John R. Schimkaitis	Dennis S. Hudson, III, Director
Chair of the Board and Director	February 26, 2020
February 26, 2020
/S/ EUGENE H. BAYARD, ESQ	/S/ LILA A. JABER
Eugene H. Bayard, Esq., Director	Lila A. Jaber, Director
February 26, 2020	February 26, 2020
/S/ THOMAS J. BRESNAN	/S/ PAUL L. MADDOCK, JR.
Thomas J. Bresnan, Director	Paul L. Maddock, Jr., Director
February 26, 2020	February 26, 2020
/S/ RONALD G. FORSYTHE, JR.	/S/ CALVERT A. MORGAN, JR.
Dr. Ronald G. Forsythe, Jr., Director	Calvert A. Morgan, Jr., Director
February 26, 2020	February 26, 2020
/S/ THOMAS P. HILL, JR.	/S/ DIANNA F. MORGAN
Thomas P. Hill, Jr., Director	Dianna F. Morgan, Director
February 26, 2020	February 26, 2020

Chesapeake Utilities Corporation 2019 Form 10-K Page 102

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
2019	1,058	$	1,392	$	278	$	(1,391	)	$	1,337
2018	876	1,119		133		(1,070		)	1,058
2017	897	541		339		(901		)	876

⁽¹⁾ Recoveries.

⁽²⁾ Uncollectible accounts charged off.

Chesapeake Utilities Corporation 2019 Form 10-K     Page 103

EX-10.25

TPERFORMANCE STOCK AWARD AGREEMENT

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

2013 STOCK AND INCENTIVE COMPENSATION PLAN

On December 3, 2019, (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 2019-2020 Transitional 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, 2019 to December 31, 2020 (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

(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 2019-2020 Performance Peer Group, Attachment A hereto and to the 2019-2020 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, 2019 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.

(b)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 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.

(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.

(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

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: Chief HR Officer

Grantee:

Printed Name: ____________

Attachment A

2019-2020 Performance Peer Group

The 2019-2020 Performance Peer Group consists of the following gas utility companies:

1. Atmos Energy Corporation

2. Black Hills Corporation

3. New Jersey Resources Corporation

4. NiSource, Inc.

5. NW Natural

6. Northwestern Corporation

7. OneGas, Inc.

8. RGC Resources, Inc.

9. South Jersey Industries, Inc.

10. Spire, Inc.

11. Unitil Corporation

EX-10.26

PERFORMANCE STOCK AWARD AGREEMENT

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

2013 STOCK AND INCENTIVE COMPENSATION PLAN

On December 3, 2019, (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 2019-2021 Transitional 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, 2019 to December 31, 2021 (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

(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 2019-2021 Performance Peer Group, Attachment A hereto and to the 2019-2021 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, 2019 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.

(b)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 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.

(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.

(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

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: Chief HR Officer

Grantee:

Printed Name: ________________

Attachment A

2019-2021 Performance Peer Group

The 2019-2021 Performance Peer Group consists of the following gas utility companies:

1. Atmos Energy Corporation

2. Black Hills Corporation

3. New Jersey Resources Corporation

4. NiSource, Inc.

5. NW Natural

6. Northwestern Corporation

7. OneGas, Inc.

8. RGC Resources, Inc.

9. South Jersey Industries, Inc.

10. Spire, Inc.

11. Unitil Corporation

EX-10.27

EXECUTIVE EMPLOYMENT AGREEMENT

This Executive Employment Agreement (the "Agreement") dated this 4^th day of December, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the "Company"), and Kevin J. Webber (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, Propane, Business Development, and Other Energy Delivery;

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, Propane, Business Development, and Other Energy Delivery; 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, Propane, Business Development, and Other Energy Delivery; 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 executive officer of the Company in the capacity of Senior Vice President, Propane, Business Development, and Other Energy Delivery, 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 Propane, Business Development, and Other Energy Delivery functions of the Company.

2.    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)).

(b)    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.

(c)    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").

(d)    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

(ii)    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

(iii)     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

(iv)    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 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:

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

(B)    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;

(C)    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

(D)    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 occur-red 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.

3.    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 with-held.

4.    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.

(b)    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 Fernandina, Florida, 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.

5.    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 $275,000 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.

(b)    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, 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.

(c)    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 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.

(ii)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.

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

(e)    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.

(f)    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.

(g)    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.

(h)    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.

(i)    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.

6.    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.

(b)    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;

(ii)    a willful or deliberate act or acts of dishonesty by Execu-tive resulting or intended to result directly or indirectly in material gain to or personal enrichment of Executive at the Company's expense;

(iii)    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

(iv)    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.

(c)    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");

(ii)    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

(iii)    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 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).

(d)    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

(ii)    Termination by Executive of his employ-ment following the occurrence of any of the following events:

(A)    failure to elect or re-elect Execu-tive 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 immedi-ately prior to a Change in Control of the Company;

(B)    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 Para-graph 5, which change or reduction is not remedied within thirty (30) days after notice to the Company by the Executive;

(C)    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

(D)    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.

(e)    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.

7.    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.

(b)    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.

8.    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.

9.    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.

(b)    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;

(ii) in the performance of Executive’s duties to the Company;

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

(iv) 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.

(c)    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

(ii) 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.

(d)    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

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

(e)    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.

(f)    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:

(A)    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

(B)    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.

(ii)    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.

(iii)    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.

(g)    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

(ii) 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.

(h)    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.

(i)    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

(ii)    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:

(i)    files any document containing trade secrets under seal; and

(ii)    does not disclose trade secrets, except pursuant to court order.

(j)    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.

(k)    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.

10.    Indemnification. The Company shall indemnify Executive to the fullest extent permitted by applicable Delaware law (as may be amended from time to time), includ-ing 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 (iii) 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

11.    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 subse-quently to insist upon strict performance of such provision or any other provision of this Agreement.

12.    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.

13.    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.

14.    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 Asso-ciation, which right shall be invoked by serving upon the Company a notice to arbitrate, stating the place of arbi-tration, 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 dis-pute, 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 indemni-fy 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.

15.    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.

16.    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.

17.    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.

18.    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.

19.    Governing Law. This Agreement shall be interpret-ed 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.

20.    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.

21.    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.

22.    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.

23.    Nature of Payments Upon Termination. All payments to Executive pursuant to Paragraph 6 of this Agree-ment 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.

24.    Prior Agreement. The Company and the Executive are parties to an Executive Employment Agreement executed on July, 2010 (the "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.

25.    Acknowledgment. The parties hereto each acknowl-edge 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:                        

__________________________

EXECUTIVE:

Louis J. Anatrella

Chief Human Resources Officer

Kevin J. Webber

EX-10.28

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, 2020 to December 31, 2022 (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

(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 2020-2022 Performance Peer Group, Attachment A hereto and to the 2020-2022 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.

(b)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 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.

(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.

(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

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:                 

Attachment A

2020-2022 Performance Peer Group

The 2020-2022 Performance Peer Group consists of the following gas utility companies:

1. Atmos Energy Corporation

2. Black Hills Corporation

3. New Jersey Resources Corporation

4. NiSource, Inc.

5. NW Natural

6. Northwestern Corporation

7. OneGas, Inc.

8. RGC Resources, Inc.

9. South Jersey Industries, Inc.

10. Spire, Inc.

11. Unitil Corporation

EX-10.29

AMENDMENT TO EXECUTIVE EMPLOYMENT AGREEMENT

This Amendment to     the Executive     Employment Agreement (the “Amendment”) effective as of December 4, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), and Jeffry M. Householder (the “Executive”).

Background Information

The parties to this Amendment (the “Parties”) entered into an Executive Employment Agreement dated as of February 25, 2019 (the “Agreement”), regarding the Executive's employment relationship with the Company. The Parties desire to amend the Agreement to memorialize a future extension of the Current Term through December 31, 2020.

Agreement

In consideration of the mutual promises and covenants contained herein, the Company and Executive hereby agree that the Current Term under the Agreement shall expire on December 31, 2020, subject to further extensions of the Current Term as provided under and in accordance with the terms of the Agreement. All other provisions of the Agreement shall remain unchanged.

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL]               By:     ______________________________

Title: ______________________________

ATTEST:                         

                      Date: ______________________________

__________________________

EXECUTIVE:

                                Name: _____________________________

                                 Date: _____________________________

EX-10.30

AMENDMENT TO EXECUTIVE EMPLOYMENT AGREEMENT

This Amendment to     the Executive     Employment Agreement (the “Amendment”) effective as of December 4, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), and Beth W. Cooper (the “Executive”).

Background Information

The parties to this Amendment (the “Parties”) entered into an Executive Employment Agreement dated as of January 9, 2013 (the “Agreement”), regarding the Executive's employment relationship with the Company and previously extended the Current Term (as defined in the Agreement) through December 31, 2019. The Parties desire to amend the Agreement to memorialize a future extension of the Current Term through December 31, 2020.

Agreement

In consideration of the mutual promises and covenants contained herein, the Company and Executive hereby agree that the Current Term under the Agreement shall expire on December 31, 2020, subject to further extensions of the Current Term as provided under and in accordance with the terms of the Agreement. All other provisions of the Agreement shall remain unchanged.

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL]               By:     ______________________________

Title: ______________________________

ATTEST:                         

                      Date: ______________________________

__________________________

EXECUTIVE:

                                Name: _____________________________

                                 Date: _____________________________                   

EX-10.31

AMENDMENT TO EXECUTIVE EMPLOYMENT AGREEMENT

This Amendment to     the Executive     Employment Agreement (the “Amendment”) effective as of December 4, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), and James F. Moriarty (the “Executive”).

Background Information

The parties to this Amendment (the “Parties”) entered into an Executive Employment Agreement dated as of June 22, 2016 (the “Agreement”), regarding the Executive's employment relationship with the Company and previously extended the Current Term (as defined in the Agreement) through December 31, 2019. The Parties desire to amend the Agreement to memorialize a future extension of the Current Term through December 31, 2020.

Agreement

In consideration of the mutual promises and covenants contained herein, the Company and Executive hereby agree that the Current Term under the Agreement shall expire on December 31, 2020, subject to further extensions of the Current Term as provided under and in accordance with the terms of the Agreement. All other provisions of the Agreement shall remain unchanged.

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL]               By:     ______________________________

Title: ______________________________

ATTEST:                         

                      Date: ______________________________

__________________________

EXECUTIVE:

                                Name: _____________________________

                                 Date: _____________________________

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
Xeron, Inc.	Mississippi
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, LLC	Florida
Aspire Energy Express, LLC	Delaware
Marlin Gas Services, LLC	Delaware
Chesapeake Elkton, LLC	Delaware
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

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 and 333-221835), Form S-8 (No. 333-192198) and Form S-4 (No. 333-201992) of Chesapeake Utilities Corporation of our report dated February 26, 2020, 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, 2019.

/s/ Baker Tilly Virchow Krause, LLP

Philadelphia, Pennsylvania

February 26, 2020

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, 2019 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 26, 2020

/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, 2019 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 26, 2020

/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, 2019, 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 26, 2020

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, 2019, 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 26, 2020

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

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands		Dec. 31, 2019		Dec. 31, 2018
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 12,365		$ 7,316
Finite-Lived Intangible Assets, Accumulated Amortization		4,236		3,466
Goodwill		32,668		21,568
Boulden [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill	[1]	11,200
Florida Natural Gas Distribution [Member] | Regulated Energy
Goodwill [Line Items]
Goodwill	[2]	3,353		3,353
Mid-Atlantic Propane Operations [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		13,299	[1]	2,147
Florida Propane Operations [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		1,188		1,188
Aspire Energy | Unregulated Energy
Goodwill [Line Items]
Goodwill		10,120		10,120
Marlin Gas Services [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		4,708		4,760
Customer Lists [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		9,391		4,801
Finite-Lived Intangible Assets, Accumulated Amortization		3,463		3,066
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		2,252		1,793
Finite-Lived Intangible Assets, Accumulated Amortization		451		202
Patents [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		452		452
Finite-Lived Intangible Assets, Accumulated Amortization		118		0
Other Intangible Assets [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		270		270
Finite-Lived Intangible Assets, Accumulated Amortization		$ 204		$ 198

[1] ⁽³⁾ Mid-Atlantic Propane Operations goodwill balance includes $11.2 million recognized as a result of the purchase of the operating assets of Boulden in December 2019.

[2] ⁽¹⁾ Florida Natural Gas Distribution includes Chesapeake Utilities' Central Florida Gas division, FPU and FPU's Indiantown and Fort Meade divisions.

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Restricted Payment	$ 227,500
Long-term Debt	486,600	$ 327,200
Capital lease obligation	0	1,310
Less: debt issuance costs	(822)	(567)
Long-term Debt and Lease Obligation	485,768	327,955
Less: current maturities	(45,600)	(11,935)
Total long-term debt, net of current maturities	440,168	316,020
Unrestricted Payment	282,000
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Restricted Payment	(37,600)
Long-term Debt	$ 7,990	7,986
Debt Instrument, Interest Rate, Stated Percentage	9.08%
Unrestricted Payment	$ 130,500
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	6.64%
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term Debt	$ 2,000	4,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	$ 12,000	15,000
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 20,300	23,200
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 6,300	7,000
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 18,000	20,000
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	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
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]
Long-term Debt	$ 100,000
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 January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 0	30,000
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate	0.75%
Debt Instrument, Interest Rate, Stated Percentage	3.23%
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%
Promissory note
Debt Instrument [Line Items]
Long-term Debt	$ 0	$ 26
Electric Limited Proceedings [Member]
Debt Instrument [Line Items]
Basis Plus LIBOR for Term Notes to Finance Hurricane Michael Costs	75

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current		$ 1,844	$ 1,604
Gain (Loss) on derivatives		910	(2,701)	$ 1,715
Revenue | Derivatives not designated as hedging instruments | Forward Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]	0	0	112
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	(13)	8
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		0	0	(9)
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		1,520	(647)	1,607
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(294)	532	(1,476)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(253)	(2,773)	487
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(63)	200	$ 986
2017 [Member] | Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current		$ 1,844	$ 1,604

[1] All of the realized and unrealized gain (loss) on forward contracts represented the effect of trading activities for Xeron on our consolidated statement of income.

XML

Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax	$ (3,000)	$ (12,200)
Deferred Tax Assets, Operating Loss Carryforwards	$ 5,523	2,010
Deferred tax asset related to state net operating loss carry-forwards		$ 2,000
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	35.00%
State
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax	$ 54,700	$ 60,100

XML

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 4,700	$ 3,500	$ 900

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, 2019	Dec. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	$ (29)	$ (41)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	686	648
Purchases and adjustments	131	68
Investment income	15	11
Ending Balance	$ 803	$ 686

XML

Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	95,329	97,053	90,961
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	7,635	16,918	10,269

XML

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) mi	Dec. 31, 2018 USD ($) mi
Property, Plant and Equipment [Line Items]
Contributions in Aid of Construction	$ 2,100	$ 2,800
Public Utilities, Allowance for Funds Used During Construction, Description	$ 700	1,900
Number of Months to Establish ROU Asset and Liability	12 months
Property, plant and equipment
Total property, plant and equipment	$ 1,746,532	1,568,441
Less: Accumulated depreciation and amortization	(336,876)	(294,089)
Plus: Construction work in progress	54,141	79,168
Net property, plant and equipment	1,463,797	1,353,520
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	705,095	657,630
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	608,727	537,654
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	73,658	70,225
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	127,651	102,133
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	141,841	123,632
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	35,436	35,239
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	14,014	7,240
Other unregulated energy | Other [Member]
Property, plant and equipment
Total property, plant and equipment	104	104
Other
Property, plant and equipment
Total property, plant and equipment	40,006	34,584
Natural Gas Operations [Member]
Property, plant and equipment
Less: Accumulated depreciation and amortization	(1,500)	$ (1,400)
Net property, plant and equipment	$ 6,700
Miles Of Natural Gas Pipeline | mi	26	16

XML

Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Activities
Net Income	$ 65,153	$ 56,580	$ 58,124
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	45,900	40,802	36,599
Depreciation and accretion included in operations expenses	8,752	8,535	8,122
Deferred income taxes, net	24,476	21,226	11,085
Gain on sale of discontinued operations	(7,344)	0	0
Realized gain (loss) on sale of assets/commodity contracts	(4,135)	5,497	3,179
Unrealized loss (gain) on investments/commodity contracts	(1,595)	429	(1,001)
Employee benefits and compensation	1,985	856	1,577
Share-based compensation	4,279	2,813	2,490
Other, net	0	0	(750)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	36,489	(16,311)	(19,506)
Propane inventory, storage gas and other inventory	8,227	2,107	(9,036)
Regulatory assets/liabilities, net	(7,812)	2,250	(2,855)
Prepaid expenses and other current assets	11,115	(7,421)	(7,001)
Accounts payable and other accrued liabilities	(62,021)	35,907	15,596
Income taxes receivable (payable)	(4,750)	(522)	8,110
Customer deposits and refunds	(1,811)	(596)	5,513
Accrued compensation	2,120	708	2,488
Other assets and liabilities, net	(16,064)	(35,498)	(2,645)
Net cash provided by operating activities	102,964	117,362	110,089
Investing Activities
Property, plant and equipment expenditures	(184,727)	(240,351)	(175,329)
Proceeds from sale of assets	427	782	708
Acquisitions, net of cash acquired	(23,988)	(16,654)	(11,945)
Proceeds from the sale of discontinued operations	22,871
Environmental expenditures	(1,170)	(625)	(329)
Net cash used in investing activities	(186,587)	(256,848)	(186,895)
Financing Activities
Common stock dividends	(24,693)	(22,043)	(19,928)
Issuance of stock for Dividend Reinvestment Plan	(721)	(706)	89
Proceeds from issuance of common stock, net of expenses	0	0	(10)	[1]
Payment, Tax Withholding, Share-based Payment Arrangement	(692)	(1,210)	(692)
Change in cash overdrafts due to outstanding checks	(1,174)	(5,943)	1,738
Net borrowings (repayments) under line of credit agreements	(45,913)	49,432	39,338
Proceeds from issuance of long-term debt	199,648	154,819	69,807
Repayment of long-term debt and finance lease obligation	(41,936)	(34,388)	(12,100)
Net cash provided by financing activities	84,519	139,961	78,242
Net Increase in Cash and Cash Equivalents	896	475	1,436
Cash and Cash Equivalents — Beginning of Period	6,089	5,614	4,178
Cash and Cash Equivalents — End of Period	$ 6,985	$ 6,089	$ 5,614

[1] Represents capitalized legal fees associated with our September 22, 2016 public offering.

XML

Document and Entity Information - USD ($)
$ in Billions

12 Months Ended

Dec. 31, 2019

Feb. 20, 2020

Jun. 30, 2019

Cover page.

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2019

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

$ 1.5

Entity Common Stock, Shares Outstanding

16,407,017

Documents Incorporated by Reference

Portions of the Proxy Statement for the 2020 Annual Meeting of Stockholders are incorporated by reference in Part II and Part III, which Proxy Statement shall be filed with the Securities and Exchange Commission within 120 days after the end of registrant's fiscal year ended December 31, 2019.

Entity Central Index Key

0000019745

Current Fiscal Year End Date

--12-31

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Amendment Flag

false

XML

Rates and Other Regulatory Activities Regulatory assets and liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Regulated Operations [Abstract]

Schedule of Regulatory Assets [Table Text Block]

At December 31, 2019 and 2018, 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,
	2019		2018
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	5,144	$	4,631
Under-recovered GRIP revenue (2)	—		165
Deferred postretirement benefits (3)	16,311		15,517
Deferred conversion and development costs (1)	20,881		16,727
Environmental regulatory assets and expenditures (4)	2,241		2,731
Acquisition adjustment (5)	30,329		33,255
Loss on reacquired debt (6)	869		942
Other	2,776		3,250
Total Regulatory Assets	$	78,551	$	77,218
Regulatory Liabilities
Self-insurance (7)	$	873	$	947
Over-recovered purchased fuel and conservation cost recovery (1)	2,724		5,856
Over-recovered GRIP revenue (2)	2,668		1,563
Storm reserve (7)	1,437		677
Accrued asset removal cost (8)	36,767		42,401
Deferred income taxes due to rate change (9)	89,191		91,236
Other	75		242
Total Regulatory Liabilities	$	133,735	$	142,922

⁽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. In 2019, we recorded as a regulatory asset 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 have self-insurance and storm reserves in our Florida 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.

⁽⁸⁾ See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

⁽⁹⁾ 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. 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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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Summary of Accounting poliicies [Abstract]

Property, Plant and Equipment [Table Text Block]

A summary of property, plant and equipment for continuing operations by classification as of December 31, 2019 and 2018 is provided in the following table:

	As of December 31,
(in thousands)	2019			2018
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	705,095		$	657,630
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	608,727			537,654
Electric distribution	127,651			102,133
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	141,841			123,632
Natural gas transmission and supply – Ohio	73,658			70,225
Electricity and steam generation	35,436			35,239
Mobile CNG and pipeline solutions	14,014			7,240
Other unregulated energy	104			104
Other	40,006			34,584
Total property, plant and equipment	1,746,532			1,568,441
Less: Accumulated depreciation and amortization	(336,876		)	(294,089		)
Plus: Construction work in progress	54,141			79,168
Net property, plant and equipment	$	1,463,797		$	1,353,520

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, 2019, 2018 and 2017:

	2019	2018	2017
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.6%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.6%	2.7%	2.8%
Natural gas transmission – Florida	2.4%	2.3%	3.5%
Electric distribution	3.4%	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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Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31, 2019												For the Year Ended December 31, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	62,659		$	—		$	—		$	62,659		$	70,338		$	—		$	—		$	70,338
Florida natural gas division	28,485			—			—			28,485			25,341			—			—			25,341
FPU electric distribution	77,416			—			—			77,416			79,803			—			—			79,803
FPU natural gas distribution	82,418			—			—			82,418			81,118			—			—			81,118
Maryland natural gas division	22,517			—			—			22,517			24,172			—			—			24,172
Sandpiper natural gas/propane operations	19,068			—			—			19,068			22,088			—			—			22,088
Total energy distribution	292,563			—			—			292,563			302,860			—			—			302,860
Energy transmission
Aspire Energy	—			32,493			—			32,493			—			35,407			—			35,407
Eastern Shore	72,924			—			—			72,924			64,248			—			—			64,248
Peninsula Pipeline	16,453			—			—			16,453			11,927			—			—			11,927
Total energy transmission	89,377			32,493			—			121,870			76,175			35,407			—			111,582
Energy generation
Eight Flags	—			16,749			—			16,749			—			17,302			—			17,302
Propane operations
Propane delivery operations	—			107,964			—			107,964			—			123,603			—			123,603
Energy delivery services
Marlin Gas Services	—			5,702			—			5,702			—			121			—			121
Other and eliminations
Eliminations	(38,934		)	(10,407		)	(18,080		)	(67,421		)	(33,754		)	(16,486		)	(17,522		)	(67,762		)
Other	—			1,649			528			2,177			—			1,957			653			2,610
Total other and eliminations	(38,934		)	(8,758		)	(17,552		)	(65,244		)	(33,754		)	(14,529		)	(16,869		)	(65,152		)
Total operating revenues (1)	$	343,006		$	154,150		$	(17,552	)	$	479,604		$	345,281		$	161,904		$	(16,869	)	$	490,316

⁽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, and $0.2 million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, for the year ended December 31, 2018. 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, 2019 and 2018 were as follows:

	Trade Receivables			Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2018	$	52,140		$	2,614	$	480
Balance at 12/31/2019	47,430			3,465		589
Increase (decrease)	$	(4,710	)	$	851	$	109

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]

Revenue for these businesses for the remaining performance obligations at December 31, 2019 are expected to be recognized as follows:

(in thousands)	2020		2021		2022		2023		2024		2025 and thereafter
Eastern Shore and Peninsula Pipeline	$	37,307	$	34,000	$	27,034	$	21,608	$	19,385	$	194,868
Natural gas distribution operations	3,996		4,058		5,100		4,916		4,681		37,149
FPU electric distribution	566		566		566		566		566		1,100
Total revenue contracts with remaining performance obligations	$	41,869	$	38,624	$	32,700	$	27,090	$	24,632	$	233,117

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Share-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares shares		Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) shares
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 | $	$ 4,300
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	14,107
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Forfeitures and Expirations	2,569
Shares reserved for issuance	831,183
Number of Shares, Granted	751		792
Number of shares withheld	7,635		16,918	10,269
Payments of employees' tax obligations to taxing authorities	3
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount | $	$ 1,100
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
Unrecognized compensation expense related to the awards to Non employee directors | $	$ 200
Weighted average grant-date fair value of awards granted | $ / shares	$ 93.14		$ 75.70
Total [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Granted	6,759		7,128
Awards to non-employee director [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of Shares, Granted	254		276
Weighted average grant-date fair value of awards granted | $ / shares	$ 95.83		$ 81.30
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 | $ / shares	$ 67,080.00		$ 47.39
Number of Shares, Granted	88,048	[1]	49,494
Weighted average grant-date fair value of awards granted | $ / shares	$ 92,740	[1]	$ 67.76
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested | $	$ 15,100		$ 10,700	$ 10,400
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	449,868

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

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

REVENUE RECOGNITION

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays revenue from continuing operations by major source based on product and service type for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31, 2019												For the Year Ended December 31, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	62,659		$	—		$	—		$	62,659		$	70,338		$	—		$	—		$	70,338
Florida natural gas division	28,485			—			—			28,485			25,341			—			—			25,341
FPU electric distribution	77,416			—			—			77,416			79,803			—			—			79,803
FPU natural gas distribution	82,418			—			—			82,418			81,118			—			—			81,118
Maryland natural gas division	22,517			—			—			22,517			24,172			—			—			24,172
Sandpiper natural gas/propane operations	19,068			—			—			19,068			22,088			—			—			22,088
Total energy distribution	292,563			—			—			292,563			302,860			—			—			302,860
Energy transmission
Aspire Energy	—			32,493			—			32,493			—			35,407			—			35,407
Eastern Shore	72,924			—			—			72,924			64,248			—			—			64,248
Peninsula Pipeline	16,453			—			—			16,453			11,927			—			—			11,927
Total energy transmission	89,377			32,493			—			121,870			76,175			35,407			—			111,582
Energy generation
Eight Flags	—			16,749			—			16,749			—			17,302			—			17,302
Propane operations
Propane delivery operations	—			107,964			—			107,964			—			123,603			—			123,603
Energy delivery services
Marlin Gas Services	—			5,702			—			5,702			—			121			—			121
Other and eliminations
Eliminations	(38,934		)	(10,407		)	(18,080		)	(67,421		)	(33,754		)	(16,486		)	(17,522		)	(67,762		)
Other	—			1,649			528			2,177			—			1,957			653			2,610
Total other and eliminations	(38,934		)	(8,758		)	(17,552		)	(65,244		)	(33,754		)	(14,529		)	(16,869		)	(65,152		)
Total operating revenues (1)	$	343,006		$	154,150		$	(17,552	)	$	479,604		$	345,281		$	161,904		$	(16,869	)	$	490,316

⁽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, and $0.2 million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, for the year ended December 31, 2018. 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 Rayonier, produces three sources of energy: electricity, steam and heated water. Rayonier purchases the steam (unfired and fired) and heated water, which are used in Rayonier’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, 2019 and 2018 were as follows:

	Trade Receivables			Contract Assets (Noncurrent)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2018	$	52,140		$	2,614	$	480
Balance at 12/31/2019	47,430			3,465		589
Increase (decrease)	$	(4,710	)	$	851	$	109

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 years ended December 31, 2019 and 2018, we recognized revenue of $1.0 million and $0.7 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, 2019 are expected to be recognized as follows:

(in thousands)	2020		2021		2022		2023		2024		2025 and thereafter
Eastern Shore and Peninsula Pipeline	$	37,307	$	34,000	$	27,034	$	21,608	$	19,385	$	194,868
Natural gas distribution operations	3,996		4,058		5,100		4,916		4,681		37,149
FPU electric distribution	566		566		566		566		566		1,100
Total revenue contracts with remaining performance obligations	$	41,869	$	38,624	$	32,700	$	27,090	$	24,632	$	233,117

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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Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Components of net periodic cost:
Interest cost		$ 74	$ 83	$ 89
Expected Amortization Of Pre Merger Regulatory Asset		0
Assumptions
Defined Benefit Plan, Plan Assets, Amount		54,333	52,250
Chesapeake Postretirement Plan
Components of net periodic cost:
Interest cost		39	38	41
Amortization of prior service cost		(77)	(77)	(77)
Actuarial (gain) loss		46	58	53
Net periodic pension cost		8	19	17
Expected Amortization Of Pre Merger Regulatory Asset			0	0
Net periodic postretirement cost		$ 8	$ 19	$ 17
Assumptions
Discount rate		4.00%	3.50%	3.75%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 149	$ 136
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		73	(131)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(163)	(169)
Defined Benefit Plan, Plan Assets, Amount		0	0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	[1]	14	33
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		149	136
Defined Benefit Plan, Plan Assets, Benefits Paid		(163)	(169)
Funded status		(1,100)	(1,002)
Accrued pension cost		$ (1,100)	$ (1,002)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.00%	4.00%
FPU Medical Plan
Components of net periodic cost:
Interest cost		$ 48	$ 47	50
Amortization of prior service cost		0	0	0
Actuarial (gain) loss		0	0	0
Net periodic pension cost		48	47	50
Amortization of pre-merger regulatory asset		8	8	8
Net periodic postretirement cost		$ 56	$ 55	$ 58
Assumptions
Discount rate		4.25%	3.75%	4.00%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 38	$ 41
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		47	(89)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(96)	(99)
Defined Benefit Plan, Plan Assets, Amount		0	0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	[1]	58	58
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		38	41
Defined Benefit Plan, Plan Assets, Benefits Paid		(96)	(99)
Funded status		(1,224)	(1,187)
Accrued pension cost		$ (1,224)	$ (1,187)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.25%	4.25%
Chesapeake SERP
Components of net periodic cost:
Interest cost		$ 74	$ 83
Actuarial (gain) loss		85	101	87
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		58
Net periodic postretirement cost		$ 217	$ 184	$ 176
Assumptions
Discount rate		4.00%	3.50%	3.75%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ 159	$ (74)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(361)	(152)
Defined Benefit Plan, Plan Assets, Contributions by Employer		361	152
Defined Benefit Plan, Plan Assets, Benefits Paid		(361)	(152)
Funded status		(2,157)	(2,285)
Accrued pension cost		$ (2,157)	$ (2,285)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.00%	4.00%
Chesapeake Pension Plan
Components of net periodic cost:
Interest cost		$ 375	$ 384	$ 402
Expected return on assets		(487)	(542)	(495)
Actuarial (gain) loss		391	343	399
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		1,982	0	0
Net periodic pension cost		2,261	185	306
Amortization of pre-merger regulatory asset		0	0	0
Net periodic postretirement cost		$ 2,261	$ 185	$ 306
Assumptions
Discount rate		3.00%	3.50%	3.75%
Expected return on plan assets		6.00%	6.00%	6.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ 1,443	$ (610)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(483)	(505)
Defined Benefit Plan, Plan Assets, Amount		4,630	8,649	$ 9,350
Defined Benefit Plan, Plan Assets, Contributions by Employer		1,117	451
Defined Benefit Plan, Plan Assets, Benefits Paid		(483)	(505)
Funded status		(1,584)	(2,063)
Accrued pension cost		$ (1,584)	$ (2,063)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.00%	4.00%
FPU Pension Plan
Components of net periodic cost:
Interest cost		$ 2,452	$ 2,339	2,482
Expected return on assets		(2,770)	(3,091)	(2,779)
Actuarial (gain) loss		505	404	513
Net periodic pension cost		187	(348)	216
Amortization of pre-merger regulatory asset		543	761	761
Net periodic postretirement cost		$ 730	$ 413	$ 977
Assumptions
Discount rate		4.25%	3.75%	4.00%
Expected return on plan assets		6.50%	6.50%	6.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ 6,508	$ (4,739)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(3,033)	(2,887)
Defined Benefit Plan, Plan Assets, Amount		49,703	43,601	$ 48,396
Defined Benefit Plan, Plan Assets, Contributions by Employer		1,157	1,205
Defined Benefit Plan, Plan Assets, Benefits Paid		(3,033)	(2,887)
Funded status		(15,601)	(15,776)
Accrued pension cost		$ (15,601)	$ (15,776)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		3.25%	4.25%

[1] The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2019

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 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 connection with this strategy, during the third and fourth quarter of 2019, we reached agreements with four entities to sell PESCO's assets and contracts. These transactions closed during the fourth quarter of 2019. As a result of the sale, 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. Refer to Note 4, Acquisitions and Divestitures for further information.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2019

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 and 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, 2019 and 2018, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2018	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets (1)	82		—		82		—
Total assets	$	6,793	$	6,025	$	82	$	686
Liabilities:
Derivative liabilities (1)	$	1,604	$	—	$	1,604	$	—

⁽¹⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018.

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Beginning Balance	$	686		$	648
Purchases and adjustments	131			68
Transfers/disbursements	(29		)	(41		)
Investment income	15			11
Ending Balance	$	803		$	686

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

At December 31, 2019 and 2018, 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 short maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2019, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $486.6 million, compared to the estimated fair value of $505.0 million. At December 31, 2018, long-term debt, which includes the current maturities but excludes finance lease obligations and debt issuance costs, had a carrying value of $327.2 million, compared to a fair value of $323.8 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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Share-Based Compensation Plans Shares Withheld and Tax Benefits Associated With Share-Based Payments (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation	7,635	16,918	10,269
Payment, Tax Withholding, Share-based Payment Arrangement	$ 692	$ 1,210	$ 692
Proceeds and Excess Tax Benefit from Share-based Compensation	$ 0		$ 349

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2019

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 Pension Plan, the FPU Pension Plan and the Chesapeake unfunded supplemental executive retirement pension plan ("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, 2019 and 2018, 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, 2019 and 2018 and the net periodic cost for the years ended December 31, 2019, 2018 and 2017 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2019			2018			2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	10,712		$	11,443		$	59,377		$	64,664		$	2,285		$	2,428
Interest cost	375			384			2,452			2,339			74			83
Actuarial loss (gain)	1,443			(610		)	6,508			(4,739		)	159			(74		)
Effect of settlement	(5,833		)	—			—			—			—			—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Benefit obligation — end of year	6,214			10,712			65,304			59,377			2,157			2,285
Change in plan assets:
Fair value of plan assets — beginning of year	8,649			9,350			43,601			48,396			—			—
Actual return on plan assets	1,180			(647		)	7,978			(3,113		)	—			—
Employer contributions	1,117			451			1,157			1,205			361			152
Effect of settlement	(5,833		)	—			—			—						—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Fair value of plan assets — end of year	4,630			8,649			49,703			43,601			—			—
Reconciliation:
Funded status	(1,584		)	(2,063		)	(15,601		)	(15,776		)	(2,157		)	(2,285		)
Accrued pension cost	$	(1,584	)	$	(2,063	)	$	(15,601	)	$	(15,776	)	$	(2,157	)	$	(2,285	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%	3.00		%	4.00		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%	—		%	—		%

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2019 (1)			2018			2017			2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic pension cost:
Interest cost	$	375		$	384		$	402		$	2,452		$	2,339		$	2,482		$	74		$	83		$	89
Expected return on assets	(487		)	(542		)	(495		)	(2,770		)	(3,091		)	(2,779		)	—			—			—
Amortization of actuarial loss	391			343			399			505			404			513			85			101			87
Settlement expense	1,982			—			—			—			—			—			58			—			—
Net periodic pension cost	2,261			185			306			187			(348		)	216			217			184			176
Amortization of pre-merger regulatory asset	—			—			—			543			761			761			—			—			—
Total periodic cost	$	2,261		$	185		$	306		$	730		$	413		$	977		$	217		$	184		$	176
Assumptions:
Discount rate	3.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	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 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, 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 trustee 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, 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, 2019, 2018 and 2017:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2019		2018		2017		2019		2018		2017
Asset Category
Equity securities	—	%	49	%	53	%	53	%	50	%	55	%
Debt securities	92	%	41	%	38	%	37	%	41	%	37	%
Other	8	%	10	%	9	%	10	%	9	%	8	%
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 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, 2019 and 2018, 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, 2019								At December 31, 2018
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)	$	3,553	$	—	$	—	$	3,553	$	3,399	$	—	$	—	$	3,399
U.S. Mid Cap (1)	1,604		—		—		1,604		1,478		—		—		1,478
U.S. Small Cap (1)	726		—		—		726		670		—		—		670
International (2)	9,855		—		—		9,855		9,226		—		—		9,226
Alternative Strategies (3)	4,739		—		—		4,739		5,726		—		—		5,726
	20,477		—		—		20,477		20,499		—		—		20,499
Mutual Funds - Debt securities
Fixed income (4)	19,220		—		—		19,220		18,630		—		—		18,630
High Yield (4)	2,476		—		—		2,476		2,818		—		—		2,818
	21,696		—		—		21,696		21,448		—		—		21,448
Mutual Funds - Other
Commodities (5)	1,708		—		—		1,708		1,902		—		—		1,902
Real Estate (6)	2,288		—		—		2,288		2,216		—		—		2,216
Guaranteed deposit (7)	—		—		1,147		1,147		—		—		627		627
	3,996		—		1,147		5,143		4,118		—		627		4,745
Total Pension Plan Assets in fair value hierarchy	$	46,169	$	—	$	1,147	47,316		$	46,065	$	—	$	627	46,692
Investments measured at net asset value (8)							7,017								5,558
Total Pension Plan Assets							$	54,333							$	52,250

⁽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, 2019 and 2018, all of the 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.

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Balance, beginning of year	$	627		$	436
Purchases	2,274			1,674
Transfers in	3,090			2,375
Disbursements	(4,907		)	(3,872		)
Investment income	63			14
Balance, end of year	$	1,147		$	627

Other Postretirement Benefits Plans

We sponsor two defined benefit postretirement health plans: the Chesapeake Postretirement Plan and the FPU Medical Plan. The following table sets forth the funded status at December 31, 2019 and 2018:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,002		$	1,128		$	1,187		$	1,287
Interest cost	39			38			48			47
Plan participants contributions	149			136			38			41
Actuarial loss (gain)	73			(131		)	47			(89		)
Benefits paid	(163		)	(169		)	(96		)	(99		)
Benefit obligation — end of year	1,100			1,002			1,224			1,187
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	14			33			58			58
Plan participants contributions	149			136			38			41
Benefits paid	(163		)	(169		)	(96		)	(99		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,100		)	(1,002		)	(1,224		)	(1,187		)
Accrued postretirement cost	$	(1,100	)	$	(1,002	)	$	(1,224	)	$	(1,187	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%

⁽¹⁾ The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Net periodic postretirement benefit costs for 2019, 2018, and 2017 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	39		$	38		$	41		$	48		$	47		$	50
Amortization of actuarial loss	46			58			53			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	8			19			17			48			47			50
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost	$	8		$	19		$	17		$	56		$	55		$	58
Assumptions
Discount rate	4.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%

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, 2019:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(447	)	$	—		$	(447	)
Net loss (gain)	2,241		19,339		575		604			(32		)	22,727
Total	$	2,241	$	19,339	$	575	$	157		$	(32	)	$	22,280
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,241	$	3,674	$	575	$	157		$	(6	)	$	6,641
Post-merger regulatory asset	—		15,665		—		—			(26		)	15,639
Subtotal	2,241		19,339		575		157			(32		)	22,280
Pre-merger regulatory asset	—		—		—		—			6			6
Total unrecognized cost	$	2,241	$	19,339	$	575	$	157		$	(26	)	$	22,286

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2019 is net of income tax benefits of $1.7 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. FPU continues to maintain and amortize a portion of the unrecognized postretirement benefit costs prior to the merger with Chesapeake Utilities related to its regulated operations, which is shown as a pre-merger regulatory asset. The portion of the regulatory asset related to the FPU Pension was fully amortized at December 31, 2019.

 Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2019, 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 2019 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 2020, we expect to contribute $0.3 million and $3.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $0.2 million to the Chesapeake SERP. We also expect to contribute $0.1 million to both the Chesapeake Postretirement Plan and FPU Medical Plan, in 2020.

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)
2020	$	115	$	3,281	$	151	$	90	$	86
2021	$	368	$	3,348	$	150	$	87	$	90
2022	$	106	$	3,424	$	148	$	85	$	91
2023	$	927	$	3,498	$	146	$	67	$	79
2024	$	111	$	3,549	$	144	$	64	$	80
Years 2025 through 2029	$	2,300	$	18,429	$	748	$	264	$	389

⁽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, 2019, 2018 and 2017, 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 $5.7 million, $5.5 million, and $5.0 million for the years ended December 31, 2019, 2018 and 2017, respectively. As of December 31, 2019, there were 831,183 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 $9.2 million and $6.7 million at December 31, 2019 and 2018, 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 $4.5 million and $3.9 million at December 31, 2019 and 2018, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheet.

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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	$ 876	$ 897
Additions, Charged to Income	1,392	541
Additions, Other Accounts	278	339
Deductions	(1,391)	(901)
Balance at End of Year	$ 1,337	$ 876

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,990		$	7,986
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	2,000			4,000
5.93% note, due October 31, 2023	12,000			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			7,000
3.73% note, due December 16, 2028	18,000			20,000
3.88% note, due May 15, 2029	50,000			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			—
2.98% note, due December 20, 2034	70,000			—
Term Note due January 21, 2020	—			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligations	—			1,310
Less: debt issuance costs	(822		)	(567		)
Total long-term debt	485,768			327,955
Less: current maturities	(45,600		)	(11,935		)
Total long-term debt, net of current maturities	$	440,168		$	316,020

Annual maturities

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

Year	2020		2021		2022		2023		2024		Thereafter		Total
(in thousands)
Payments	$	45,600	$	13,600	$	25,100	$	20,600	$	17,600	$	364,100	$	486,600

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL who are under no obligation to purchase any unsecured debt. The Prudential Shelf Agreement totaling $150.0 million was entered into in October 2015 and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was amended in September 2018 to increase the borrowing capacity back to $150.0 million, and in August 2019, we issued $100.0 million of 3.98% unsecured debt. In January 2020, we submitted a request for Prudential to purchase $50 million of our unsecured debt which was accepted and confirmed by Prudential. The Shelf notes will bear interest at the rate of 3.00% per annum and the proceeds received from the issuance will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the issuance of the Shelf Notes is expected to occur on or before July 15, 2020.

The NYL Shelf Agreement totaling $100.0 million was entered into in March 2017 and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement was amended in November 2018 to provide additional borrowing capacity of $50.0 million. As of December 31, 2019, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement, which we entered into in March 2017. In February 2020, we submitted a request for NYL to purchase $40.0 million of our unsecured debt which was accepted and confirmed by NYL. The Shelf notes will bear interest at the rate of 2.96% per annum and the proceeds received from the issuance will be used to reduce short-term borrowings under our revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the issuance of the Shelf Notes is expected to occur on or before August 14, 2020.

The following table summarizes our shelf agreements at December 31, 2019:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	220,000	$	(170,000	)	$	—	$	50,000
MetLife Shelf Agreement	150,000		—			—		150,000
NYL Shelf Agreement (2)	150,000		(100,000		)	—		50,000
Total	$	520,000	$	(270,000	)	$	—	$	250,000

⁽¹⁾ As described above, in January 2020, we requested and Prudential accepted our request to purchase $50.0 million of our unsecured debt.

⁽²⁾ As described above, in February 2020, we requested and NYL accepted our request to purchase $40.0 million of our unsecured debt.

The Uncollateralized 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 December 2018, we issued a $30 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. This note was paid off in December 2019 utilizing the proceeds from the issuance of uncollateralized senior notes discussed below. 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. The interest rate, at December 31, 2019, was 2.46%, which equals the one-month LIBOR rate plus 75 basis points. As of December 31, 2019, this term note is included in the current maturities of long-term debt.

Secured First Mortgage Bonds

We guaranteed FPU’s first mortgage bonds, which are secured by a lien covering all of FPU’s property. FPU’s first mortgage bonds contain a restriction that limits the payment of dividends by FPU to an amount less than the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2019, FPU’s cumulative net income base was $168.1 million, offset by restricted payments of $37.6 million, leaving $130.5 million of available dividend capacity.

The dividend restrictions in FPU’s first mortgage bonds resulted in approximately $38.8 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2019. This represents approximately 6.92% of our consolidated net assets. Other than the dividend restrictions associated with FPU’s first mortgage bonds, there are no legal, contractual or regulatory restrictions on the net assets of our subsidiaries.

Uncollateralized Senior Notes

In December 2019, we issued $70.0 million of 2.98% uncollateralized senior notes to four financial institutions.  We used the proceeds to pay off the $30 million PNC Term Note described above, reduce our short-term borrowing amount and to finance our purchase of certain propane operating assets of Boulden.

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, 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% 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, 2019, the cumulative consolidated net income base was $509.5 million, offset by restricted payments of $227.5 million, leaving $282.0 million of cumulative net income free of restrictions. As of December 31, 2019, we are in compliance with all of our debt covenants.

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Environmental Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019 USD ($) site	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Environmental Commitments And Contingencies [Line Items]
Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 6,468,000	$ 7,638,000
Amount paid for funding requirements	1,170,000	625,000	$ 329,000
West Palm Beach Florida | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	15,400,000
West Palm Beach Florida | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	4,500,000
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	465,000
Seaford | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	273,000
FPU
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	8,000,000.0	9,100,000
Approval of recovery of environmental costs	14,000,000.0
Environmental costs recovered	11,900,000	11,500,000
FPU | Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	$ 2,100,000	$ 2,500,000

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Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2019
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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Stockholders' Equity Additional Details (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	[1]
Stockholders' Equity Attributable to Parent [Abstract]
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Proceeds from issuance of common stock, net of expenses	$ 0	$ 0	$ (10)

[1] Represents capitalized legal fees associated with our September 22, 2016 public offering.

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Change in benefit obligation:
Interest cost		$ 74	$ 83	$ 89
Change in plan assets:
Balance, beginning of year		52,250
Balance, end of year		54,333	52,250
Chesapeake Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year		10,712	11,443
Interest cost		375	384	402
Actuarial loss		1,443	(610)
Defined Benefit Plan, Benefit Obligation, Payment for Settlement		(5,833)
Benefits paid		(483)	(505)
Benefit obligation - end of year		6,214	10,712	11,443
Change in plan assets:
Balance, beginning of year		8,649	9,350
Actual return on plan assets		1,180	(647)
Employer contributions		1,117	451
Defined Benefit Plan, Plan Assets, Payment for Settlement		(5,833)
Benefits paid		(483)	(505)
Balance, end of year		4,630	8,649	$ 9,350
Reconciliation:
Funded status		(1,584)	(2,063)
Accrued pension cost		$ (1,584)	$ (2,063)
Assumptions:
Discount rate		3.00%	4.00%
Expected return on plan assets		6.00%	6.00%	6.00%
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 59,377	$ 64,664
Interest cost		2,452	2,339	$ 2,482
Actuarial loss		6,508	(4,739)
Benefits paid		(3,033)	(2,887)
Benefit obligation - end of year		65,304	59,377	64,664
Change in plan assets:
Balance, beginning of year		43,601	48,396
Actual return on plan assets		7,978	(3,113)
Employer contributions		1,157	1,205
Benefits paid		(3,033)	(2,887)
Balance, end of year		49,703	43,601	$ 48,396
Reconciliation:
Funded status		(15,601)	(15,776)
Accrued pension cost		$ (15,601)	$ (15,776)
Assumptions:
Discount rate		3.25%	4.25%
Expected return on plan assets		6.50%	6.50%	6.50%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year		$ 2,285	$ 2,428
Interest cost		74	83
Actuarial loss		159	(74)
Benefits paid		(361)	(152)
Benefit obligation - end of year		2,157	2,285	$ 2,428
Change in plan assets:
Employer contributions		361	152
Benefits paid		(361)	(152)
Reconciliation:
Funded status		(2,157)	(2,285)
Accrued pension cost		$ (2,157)	$ (2,285)
Assumptions:
Discount rate		3.00%	4.00%
Chesapeake Postretirement Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 1,002	$ 1,128
Interest cost		39	38	41
Plan participants contributions		149	136
Actuarial loss		73	(131)
Benefits paid		(163)	(169)
Benefit obligation - end of year		1,100	1,002	1,128
Change in plan assets:
Balance, beginning of year		0	0
Employer contributions	[1]	14	33
Plan participants contributions		149	136
Benefits paid		(163)	(169)
Balance, end of year		0	0	0
Reconciliation:
Funded status		(1,100)	(1,002)
Accrued pension cost		$ (1,100)	$ (1,002)
Assumptions:
Discount rate		3.00%	4.00%
FPU Medical Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 1,187	$ 1,287
Interest cost		48	47	50
Plan participants contributions		38	41
Actuarial loss		47	(89)
Benefits paid		(96)	(99)
Benefit obligation - end of year		1,224	1,187	1,287
Change in plan assets:
Balance, beginning of year		0	0
Employer contributions	[1]	58	58
Plan participants contributions		38	41
Benefits paid		(96)	(99)
Balance, end of year		0	0	$ 0
Reconciliation:
Funded status		(1,224)	(1,187)
Accrued pension cost		$ (1,224)	$ (1,187)
Assumptions:
Discount rate		3.25%	4.25%

[1] The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

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Revenue Recognition Disaggregation of Revenue (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Revenues	$ 131,973,000	$ 92,626,000	$ 94,541,000	$ 160,464,000	$ 134,214,000	$ 93,400,000	$ 93,872,000	$ 168,831,000	$ 479,604,000	$ 490,316,000	$ 449,646,000
Revenue from Contract with Customer, Excluding Assessed Tax									479,604,000	490,316,000
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									2,177,000	2,610,000
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									121,870,000	111,582,000
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(67,421,000)	(67,762,000)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									343,006,000	345,281,000
Regulated Energy | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									0
Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									292,563,000	302,860,000
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									89,377,000	76,175,000
Regulated Energy | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(38,934,000)	(33,754,000)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									154,150,000	161,904,000
Unregulated Energy | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									1,649,000	1,957,000
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									32,493,000	35,407,000
Unregulated Energy | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(10,407,000)	(16,486,000)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(17,552,000)	(16,869,000)
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(17,552,000)	(16,869,000)
Other Segments And Intersegments Eliminations [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									528,000	653,000
Other Segments And Intersegments Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(18,080,000)	(17,522,000)
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(65,244,000)	(65,152,000)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues									(100,000)	200,000
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues									300,000	300,000
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									62,659,000	70,338,000
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									28,485,000	25,341,000
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									77,416,000	79,803,000
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									82,418,000	81,118,000
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									22,517,000	24,172,000
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									19,068,000	22,088,000
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									32,493,000	35,407,000
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									72,924,000	64,248,000
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									16,453,000	11,927,000
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									16,749,000	17,302,000
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									107,964,000	123,603,000
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									5,702,000	121,000
Eliminations [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(38,934,000)	(33,754,000)
Eliminations [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									$ (8,758,000)	$ (14,529,000)

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Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Short-term Debt [Line Items]
Short-term Debt, Maximum Amount Outstanding During Period		$ 250,000
Line of Credit Facility, Maximum Borrowing Capacity		370,000
Long-term Line of Credit		244,190	$ 290,103
Line of Credit Facility, Remaining Borrowing Capacity		125,810
Bank Overdrafts	[1]	3,181	4,355
Short-term borrowing		$ 247,371	294,458
Number Of Unsecured Bank Credit Facilities		4
Committed Line of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 55,000
Long-term Line of Credit		55,000	25,000
Line of Credit Facility, Remaining Borrowing Capacity		$ 0
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]
Line of Credit Facility, Maximum Borrowing Capacity		$ 45,000
Long-term Line of Credit		42,040	34,672
Line of Credit Facility, Remaining Borrowing Capacity		$ 2,960
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]
Line of Credit Facility, Maximum Borrowing Capacity		$ 40,000
Long-term Line of Credit		40,000	40,000
Line of Credit Facility, Remaining Borrowing Capacity		$ 0
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]
Line of Credit Facility, Maximum Borrowing Capacity	[2]	$ 150,000
Long-term Line of Credit		50,000	125,000
Line of Credit Facility, Remaining Borrowing Capacity	[2]	$ 100,000
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]
Line of Credit Facility, Maximum Borrowing Capacity		$ 80,000
Long-term Line of Credit		57,150	$ 65,431
Line of Credit Facility, Remaining Borrowing Capacity		$ 22,850
Debt Instrument, Description of Variable Rate Basis		LIBOR rate, plus 0.75 percent

[1] ⁽¹⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

[2] This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving credit facility, shall not exceed $250.0 million.

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Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2019
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
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt Instrument, Maturity Date	Oct. 31, 2017
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]
Long-term debt, interest percentage	3.25%
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 January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.23%
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate	0.75%
Debt Instrument, Maturity Date	Jan. 21, 2020
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

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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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	$ 17,169	$ 6,246	$ 8,913	$ 28,814	$ 17,796	$ 6,090	$ 5,705	$ 27,271	$ 61,142	$ 56,862	$ 60,326
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax									$ 4,011	$ (282)	$ (2,202)
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.05	$ 0.38	$ 0.54	$ 1.76	$ 1.09	$ 0.37	$ 0.35	$ 1.67	$ 3.73	$ 3.48	$ 3.69
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$ 0.33	$ (0.04)	$ (0.03)	$ (0.01)	$ 0	$ (0.03)	$ 0.04	$ (0.03)	$ 0.24	$ (0.02)	$ (0.13)
Calculation of Basic Earnings Per Share:
Net Income	$ 22,562	$ 5,622	$ 8,304	$ 28,665	$ 17,801	$ 5,538	$ 6,385	$ 26,856	$ 65,153	$ 56,580	$ 58,124
Weighted shares outstanding - Basic (in shares)									16,398,443	16,369,616	16,336,789
Basic Earnings Per Share (in usd per share)	$ 1.38	$ 0.34	$ 0.51	$ 1.75	$ 1.09	$ 0.34	$ 0.39	$ 1.64	$ 3.97	$ 3.46	$ 3.56
Calculation of Diluted Earnings Per Share:
Net Income	$ 22,562	$ 5,622	$ 8,304	$ 28,665	$ 17,801	$ 5,538	$ 6,385	$ 26,856	$ 65,153	$ 56,580	$ 58,124
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									16,398,443	16,369,616	16,336,789
Share-based Compensation									50,043	50,254	46,563
Adjusted denominator — Diluted									16,448,486	16,419,870	16,383,352
Income (Loss) from Continuing Operations, Per Diluted Share	$ 1.37	$ 0.38	$ 0.54	$ 1.75	$ 1.09	$ 0.37	$ 0.35	$ 1.66	$ 3.72	$ 3.47	$ 3.68
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share	1.04	(0.04)	(0.04)	(0.01)	0	(0.04)	0.04	(0.02)	0.24	(0.02)	(0.13)
Diluted (in usd per share)	$ 0.33	$ 0.34	$ 0.50	$ 1.74	$ 1.09	$ 0.33	$ 0.39	$ 1.64	$ 3.96	$ 3.45	$ 3.55

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Leases Weighted Average Remaining Lease Term Additional Information (Details)	Dec. 31, 2019
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	8 years 10 months 17 days
Operating Lease, Weighted Average Discount Rate, Percent	3.80%

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Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	$ 13,470	$ 39,402	$ 15,457
Performance Incentive Plan	1,691	2,006	1,127
Capital Lease Obligation	$ 0	$ 1,310	$ 2,070

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Schedule of Carrying Value of Goodwill

The carrying value of goodwill from continuing operations as of December 31, 2019 and 2018 was as follows:

	As of December 31,
(in thousands)	2019		2018
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy(2)
Mid-Atlantic Propane Operations(3)	13,299		2,147
Florida Propane Operations	1,188		1,188
Aspire Energy	10,120		10,120
Marlin Gas Services	4,708		4,760
Total Goodwill	$	32,668	$	21,568

⁽¹⁾ Florida Natural Gas Distribution includes Chesapeake Utilities' Central Florida Gas division, FPU and FPU's Indiantown and Fort Meade divisions.

⁽²⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. The goodwill balance for PESCO is reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018.

⁽³⁾ Mid-Atlantic Propane Operations goodwill balance includes $11.2 million recognized as a result of the purchase of the operating assets of Boulden in December 2019.

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, 2019 and 2018 are as follows:

	As of December 31,
	2019				2018
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	9,391	$	3,463	$	4,801	$	3,066
Non-Compete agreements (1) (2)	2,252		451		1,793		202
Patents	452		118		452		—
Other	270		204		270		198
Total	$	12,365	$	4,236	$	7,316	$	3,466

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Leases Leases (Tables)

12 Months Ended

Dec. 31, 2019

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	2019		2018
Operating lease cost (1)	Operations expense	$	2,577	$	3,339
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	650		1,451
Interest on lease liabilities	Interest expense	5		49
Net lease cost		$	3,232	$	4,839

⁽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, 2019:

(in thousands)	Balance sheet classification	Amount
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,896
Total lease liabilities		$	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, 2019:

	December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.88
Weighted-average discount rate
Operating leases	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 as of December 31, 2019 and 2018:

	Year Ended December 31,
(in thousands)	2019		2018
Operating cash flows from operating leases	$	2,230	$	2,759
Operating cash flows from finance leases	$	5	$	49
Financing cash flows from finance leases	$	650	$	1,451

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, 2019 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2020	$	2,104
2021	1,866
2022	1,716
2023	1,719
2024	1,463
Thereafter	4,916
Total lease payments	13,784
Less: Interest	2,183
Present value of lease liabilities	$	11,601

⁽¹⁾  Operating lease payments include $3.7 million related to options to extend lease terms that are reasonably certain of being exercised.

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Share-Based Compensation Plans

12 Months Ended

Dec. 31, 2019

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 449,868 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, 2019, 2018 and 2017:

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Awards to non-employee directors	$	620		$	539		$	540
Awards to key employees	3,659			2,871			1,950
Total compensation expense	4,279			3,410			2,490
Less: tax benefit	(1,117		)	(934		)	(1,003		)
Share-based compensation amounts included in net income	$	3,162		$	2,476		$	1,487

Stock Options

There were no stock options outstanding or issued during the years 2017 through 2019.

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 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for board service through the 2019 Annual Meeting of Stockholders; accordingly, 7,128 shares, with a weighted average fair value of $75.70 per share, were issued and vested in 2018. In May 2019, each of our non-employee directors received an annual retainer of 751 shares of common stock under the SICP for service as a director 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 January 2020, a newly appointed member of the 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 will be recognized over the remaining service period ending on the 2020 Annual Meeting of Stockholders.

At December 31, 2019, there was $0.2 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 2020 Annual Meeting of Stockholders.

Our former President and Chief Executive Officer, Michael P. McMasters, retired as an executive officer on December 31, 2018 but continued as a member of the Board of Directors until the 2019 Annual Meeting of Stockholders. Mr. McMasters received a pro-rated grant of 276 shares of common stock under the SICP for service as a non-employee director from January 1, 2019 through May 8, 2019. The shares awarded to Mr. McMasters vested immediately upon issuance in January 2019, had a weighted average fair value of $81.30 per share, and were fully expensed as of the 2019 Annual Meeting of Stockholders.

Key Employees

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

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 or 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 Black-Scholes pricing model 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, 2017	132,642		$	59.31
Granted	49,494		67.76
Vested	(29,786	)	47.39
Vested - Accelerated pursuant to separation agreement	(16,676	)	75.78
Expired	(3,933	)	49.66
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

⁽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 $15.1 million, $10.7 million and $10.4 million in 2019, 2018 and 2017, respectively. At December 31, 2019, there was $4.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2021.

In June 2018, we entered into a separation agreement and release (the "Separation Agreement") with a former executive officer. Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock previously granted to the executive officer under the SICP, immediately vested at the time of separation; 2,569 shares were forfeited, and we recognized $1.1 million as share-based compensation expense.

In 2019, 2018 and 2017, 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, amounts remitted to taxing authorities and the tax benefits associated with these obligations:

	For the Year Ended December 31,
	2019		2018		2017
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	7,635		16,918		10,269
Amounts remitted to tax authorities to satisfy obligations	$	692	$	1,210	$	692
Tax benefit associated with settlement of share based payments	$	—	$	—	$	349

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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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Quarterly Financial Data Schedule Of Quarterly Financial Information [Abstract]
Revenues	$ 131,973	$ 92,626	$ 94,541	$ 160,464	$ 134,214	$ 93,400	$ 93,872	$ 168,831	$ 479,604	$ 490,316	$ 449,646
Operating Income	29,642	14,358	18,164	44,123	28,873	12,879	12,238	40,853	106,287	94,843	89,730
Net Income	22,562	5,622	8,304	28,665	17,801	5,538	6,385	26,856	65,153	56,580	58,124
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	17,169	6,246	8,913	28,814	17,796	6,090	5,705	27,271	61,142	56,862	60,326
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(9)	(624)	(609)	(149)	$ 5	$ (552)	$ 680	$ (415)	(1,391)	$ (282)	$ (2,202)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	$ 5,402	$ 0	$ 0	$ 0					$ 5,402
Income (Loss) from Continuing Operations, Per Basic Share	$ 1.05	$ 0.38	$ 0.54	$ 1.76	$ 1.09	$ 0.37	$ 0.35	$ 1.67	$ 3.73	$ 3.48	$ 3.69
Earnings per share:
Basic (in usd per share)	1.38	0.34	0.51	1.75	1.09	0.34	0.39	1.64	3.97	3.46	3.56
Income (Loss) from Continuing Operations, Per Diluted Share	1.37	0.38	0.54	1.75	1.09	0.37	0.35	1.66	3.72	3.47	3.68
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax, Per Diluted Share	1.04	(0.04)	(0.04)	(0.01)	0	(0.04)	0.04	(0.02)	0.24	(0.02)	(0.13)
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0.33	(0.04)	(0.03)	(0.01)	0	(0.03)	0.04	(0.03)	0.24	(0.02)	(0.13)
Diluted (in usd per share)	$ 0.33	$ 0.34	$ 0.50	$ 1.74	$ 1.09	$ 0.33	$ 0.39	$ 1.64	$ 3.96	$ 3.45	$ 3.55

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Short-Term Borrowing

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Short-Term Borrowing

SHORT-TERM BORROWINGS

At December 31, 2019 and 2018, we had $247.4 million and $294.5 million, respectively, of short-term borrowings outstanding at the weighted average interest rates of 2.62 percent and 3.44 percent, respectively. We have an aggregate of $370.0 million in credit lines comprised of four unsecured bank credit facilities with four financial institutions, with $220.0 million in total available credit, and a Revolver with five participating Lenders totaling $150.0 million. All of these facilities expire in October 2020. We incurred commitment fees of $0.1 million in 2019, 2018 and 2017. The following table summarizes our short-term borrowing facilities information at December 31, 2019 and 2018.

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2019		December 31, 2018		Available at December 31, 2019
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 0.75 percent	$	55,000	$	25,000	$	—
Committed revolving credit facility B	80,000		plus 0.75 percent	57,150		65,431		22,850
Committed revolving credit facility C	45,000		plus 0.75 percent	42,040		34,672		2,960
Committed revolving credit facility D	40,000		plus 0.85 percent	40,000		40,000		—
Committed revolving credit facility E(2)	150,000		plus 1.125 percent	50,000		125,000		100,000
Total short term credit facilities	$	370,000		$	244,190	$	290,103	$	125,810
Book overdrafts(1)				3,181		4,355
Total short-term borrowing				$	247,371	$	294,458

⁽¹⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

⁽²⁾ This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving credit facility, shall not exceed $250.0 million.

We are authorized by our Board of Directors to borrow up to $370.0 million of short-term debt, as required, from these short-term lines of credit. These bank credit facilities are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures.

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, 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 our revolving credit facilities to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2019, we are in compliance with all of our debt covenants.

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Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 133,735	$ 142,922
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	12,847
Maryland Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	4,087
Sandpiper [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,765
Central Florida Gas Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	8,304
Florida Public Utilities Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	19,218
Fort Meade and Indiantown Divisions [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	294
FPU electric division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 5,769

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Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (4,272)	$ (6,713)	$ (4,272)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(3,732)	1,289
Amounts reclassified from accumulated other comprehensive income/(loss)	2,198	(728)
Net current-period other comprehensive income/(loss)	(1,534)	561
Accumulated other comprehensive loss at end of period		(6,267)	(6,713)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(907)
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	(4,743)	(5,928)	(4,743)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(602)	(872)
Amounts reclassified from accumulated other comprehensive income/(loss)	439	1,867
Net current-period other comprehensive income/(loss)	(163)	995
Accumulated other comprehensive loss at end of period		(4,933)	(5,928)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(1,022)
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	471	(785)	471
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(3,130)	2,161
Amounts reclassified from accumulated other comprehensive income/(loss)	1,759	(2,595)
Net current-period other comprehensive income/(loss)	(1,371)	(434)
Accumulated other comprehensive loss at end of period		(1,334)	$ (785)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 115	$ (115)

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		$ 74	$ 83	$ 89
Prior service cost (credit)		(447)
Net loss		22,727
Total		22,280
Accumulated other comprehensive loss pre-tax		6,641
Post-merger regulatory asset		15,639
Subtotal		22,280
Pre-merger regulatory asset		6
Total unrecognized cost		22,286
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		375	384	402
Prior service cost (credit)		0
Net loss		2,241
Total		2,241
Accumulated other comprehensive loss pre-tax	[1]	2,241
Post-merger regulatory asset		0
Subtotal		2,241
Pre-merger regulatory asset		0
Total unrecognized cost		2,241
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		487	542	495
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(391)	(343)	(399)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		(1,982)	0	0
Net Periodic Cost Benefit		2,261	185	306
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		2,261	185	306
Amortization Of Pre Merger Regulatory Asset		$ 0	$ 0	$ 0
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		3.00%	3.50%	3.75%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		6.00%	6.00%	6.00%
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		$ 2,452	$ 2,339	$ 2,482
Prior service cost (credit)		0
Net loss		19,339
Total		19,339
Accumulated other comprehensive loss pre-tax	[1]	3,674
Post-merger regulatory asset		15,665
Subtotal		19,339
Pre-merger regulatory asset		0
Total unrecognized cost		19,339
Defined Benefit Plan, Expected Return (Loss) on Plan Assets		2,770	3,091	2,779
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(505)	(404)	(513)
Net Periodic Cost Benefit		187	(348)	216
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		730	413	977
Amortization Of Pre Merger Regulatory Asset		$ 543	$ 761	$ 761
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.25%	3.75%	4.00%
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Expected Long-term Rate of Return on Plan Assets		6.50%	6.50%	6.50%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		$ 74	$ 83
Prior service cost (credit)		0
Net loss		575
Total		575
Accumulated other comprehensive loss pre-tax	[1]	575
Post-merger regulatory asset		0
Subtotal		575
Pre-merger regulatory asset		0
Total unrecognized cost		575
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(85)	(101)	$ (87)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		(58)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 217	$ 184	$ 176
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.00%	3.50%	3.75%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		$ 39	$ 38	$ 41
Prior service cost (credit)		(447)
Net loss		604
Total		157
Accumulated other comprehensive loss pre-tax	[1]	157
Post-merger regulatory asset		0
Subtotal		157
Pre-merger regulatory asset		0
Total unrecognized cost		157
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		(46)	(58)	(53)
Net Periodic Cost Benefit		8	19	17
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		$ 8	$ 19	$ 17
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.00%	3.50%	3.75%
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Interest Cost		$ 48	$ 47	$ 50
Prior service cost (credit)		0
Net loss		(32)
Total		(32)
Accumulated other comprehensive loss pre-tax	[1]	(6)
Post-merger regulatory asset		(26)
Subtotal		(32)
Pre-merger regulatory asset		6
Total unrecognized cost		(26)
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year		0	0	0
Net Periodic Cost Benefit		48	47	50
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)		56	55	58
Amortization Of Pre Merger Regulatory Asset		$ 8	$ 8	$ 8
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate		4.25%	3.75%	4.00%

[1] The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2019 is net of income tax benefits of $1.7 million.

XML

Employee Benefit Plans - Summary of Pension Plan Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 54,333	$ 52,250
Total Pension Plan Assets, excluding investments measured at net asset value		47,316	46,692
Investments measured at net asset value	[1]	7,017	5,558
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		20,477	20,499
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	3,553	3,399
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1,604	1,478
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	726	670
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	9,855	9,226
Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	4,739	5,726
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		21,696	21,448
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	19,220	18,630
Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	2,476	2,818
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		5,143	4,745
Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	1,708	1,902
Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,288	2,216
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	1,147	627
Quoted Prices in Active Markets (Level 1)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		46,169	46,065
Quoted Prices in Active Markets (Level 1) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		20,477	20,499
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]	3,553	3,399
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]	1,604	1,478
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]	726	670
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]	9,855	9,226
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]	4,739	5,726
Quoted Prices in Active Markets (Level 1) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		21,696	21,448
Quoted Prices in Active Markets (Level 1) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	19,220	18,630
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]	2,476	2,818
Quoted Prices in Active Markets (Level 1) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		3,996	4,118
Quoted Prices in Active Markets (Level 1) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	1,708	1,902
Quoted Prices in Active Markets (Level 1) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,288	2,216
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		1,147	627	$ 436
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		1,147	627
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]	$ 1,147	$ 627

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

[2] Includes funds that invest primarily in United States common stocks.

[3] Includes funds that invest primarily in foreign equities and emerging markets equities.

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

[5] Includes funds that invest in investment grade and fixed income securities.

[6] Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

[7] Includes funds that invest primarily in real estate.

[8] Includes investment in a group annuity product issued by an insurance company.

XML

Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Leases Cash Flows [Abstract]
Operating Lease, Payments	$ 2,230	$ 2,759
Finance Lease, Interest Expense	5	49
Finance Lease, Right-of-Use Asset, Amortization	$ 650	$ 1,451

XML

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 1,844	$ 1,604
Derivative assets, at fair value	0	82
Unrealized Gain (Loss) on Derivatives	910	(2,701)	$ 1,715
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Put Option
Derivative [Line Items]
Derivative assets, at fair value	0	71
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	0	11
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	(1,500)
Other Receivables from Broker-Dealers and Clearing Organizations	2,317	2,173
2017 [Member] | Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	1,844	1,604
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(294)	532	(1,476)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(63)	200	986
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(253)	(2,773)	487
Cost of Sales [Member] | Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(13)	8
Cost of Sales [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 1,520	$ (647)	$ 1,607

XML

Revenue Recognition Remaining performance obligations (Details) $ in Thousands	Dec. 31, 2019 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	$ 37,307
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	3,996
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, Start Date [Axis]: 2020-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	41,869
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	34,000
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	4,058
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, 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	38,624
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	27,034
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,100
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, 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	32,700
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	21,608
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	4,916
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, 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	27,090
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	19,385
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	4,681
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	566
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	24,632
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	194,868
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	37,149
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	1,100
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	$ 233,117

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Leases Schedule of Future Minimum Rental Payment for Operating Leases (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2,104
Lessee Future Operating Lease Option Payments	3,700
Lessee, Operating Lease, Liability, Payments, Due Year Two	1,866
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,716
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,719
Lessee, Operating Lease, Liability, Payments, Due Year Five	1,463
Lessee, Operating Lease, Liability, Payments, Due after Year Five	4,916
Lessee, Operating Lease, Liability, Payments, Due	13,784
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	2,183
Operating Lease, Liability	$ 11,601

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Long-Term Debt Annual Maturities (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 45,600
Long-term Debt, Maturities, Repayments of Principal in Year Two	13,600
Long-term Debt, Maturities, Repayments of Principal in Year Three	25,100
Long-term Debt, Maturities, Repayments of Principal in Year Four	20,600
Long-term Debt, Maturities, Repayments of Principal in Year Five	17,600
Long-term Debt, Maturities, Repayments of Principal after Year Five	364,100
Total Future Repayments	$ 486,600

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Acquisitions - Additional Information (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) Dekatherm	Dec. 31, 2017 USD ($)
Cash paid for acquisition									$ 23,988	$ 16,654	$ 11,945
Revenues	$ 131,973	$ 92,626	$ 94,541	$ 160,464	$ 134,214	$ 93,400	$ 93,872	$ 168,831	479,604	490,316	449,646
Operating Income (Loss)	29,642	14,358	18,164	44,123	28,873	12,879	12,238	40,853	106,287	94,843	89,730
Net Income	22,562	$ 5,622	$ 8,304	$ 28,665	17,801	$ 5,538	$ 6,385	$ 26,856	65,153	$ 56,580	58,124
Marlin Gas Services [Member]
Revenues									5,702
Operating Income (Loss)									1,500
Additional Compressed Natural Gas Deliverability | Dekatherm										7,000
Boulden [Member]
Revenues									550
Operating Income (Loss)									239
Business Combination, Consideration Transferred									24,600
Marlin and Ohl [Member]
Business Combination, Consideration Transferred										$ 18,200
ARM Energy [Member]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized									2,500
Ohl [Member]
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments					$ 200					200
Regulated Energy [Member]
Operating Income (Loss)									$ 86,584	79,215	74,584
Regulated Energy [Member] | Elkton Gas [Member]
Number of customers acquired through acquisition									7,000
Unregulated Energy
Operating Income (Loss)									$ 19,939	17,124	$ 14,941
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 | Marlin [Member]
Goodwill, Acquired During Period										$ 4,800
Unregulated Energy | Ohl [Member]
Revenues									1,662
Operating Income (Loss)									$ 385
Number of customers acquired through acquisition										2,500
Goodwill, Acquired During Period										$ 1,500

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Investments (Tables)

12 Months Ended

Dec. 31, 2019

Investments [Abstract]

Investments schedule [Table Text Block]

	As of December 31,
(in thousands)	2019		2018
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	9,202	$	6,689
Investments in equity securities	27		22
Total	$	9,229	$	6,711

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Short-Term Borrowing Short-Term Borrowing (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Short-term Debt

The following table summarizes our short-term borrowing facilities information at December 31, 2019 and 2018.

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2019		December 31, 2018		Available at December 31, 2019
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 0.75 percent	$	55,000	$	25,000	$	—
Committed revolving credit facility B	80,000		plus 0.75 percent	57,150		65,431		22,850
Committed revolving credit facility C	45,000		plus 0.75 percent	42,040		34,672		2,960
Committed revolving credit facility D	40,000		plus 0.85 percent	40,000		40,000		—
Committed revolving credit facility E(2)	150,000		plus 1.125 percent	50,000		125,000		100,000
Total short term credit facilities	$	370,000		$	244,190	$	290,103	$	125,810
Book overdrafts(1)				3,181		4,355
Total short-term borrowing				$	247,371	$	294,458

⁽¹⁾ If presented, these book overdrafts would be funded through the bank revolving credit facilities.

⁽²⁾ This committed revolving credit facility includes a restriction that our short-term borrowings, excluding any borrowings under the committed revolving credit facility, shall not exceed $250.0 million.

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Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 0	$ 82
Energy Marketing Contract Liabilities, Current	1,844	1,604
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	11
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Put Option
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	71
2017 [Member] | Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 1,844	$ 1,604

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Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 12,365	$ 7,316
Accumulated Amortization	4,236	3,466
Customer Lists [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	9,391	4,801
Accumulated Amortization	3,463	3,066
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	2,252	1,793
Accumulated Amortization	451	202
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	452	452
Accumulated Amortization	118	0
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	270
Accumulated Amortization	$ 204	$ 198

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Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 4,700	$ 3,500	$ 900
Deferred income tax liabilities:
Property, plant and equipment	173,466	153,423
Acquisition adjustment	6,969	8,896
Deferred Tax Liabilities Loss On Reacquired Debt	220	32
Deferred Income Tax Liability - Deferred Gas Costs	1,223	1,139
Deferred Income Tax Liability, Natural Gas Conversion Costs	4,956	3,987
Deferred Income Tax Liability, Storm Reserve	10,316	97
Other	1,456	2,544
Total deferred income tax liabilities	198,606	170,118
Deferred income tax assets:
Pension and other employee benefits	3,818	3,711
Environmental costs	1,486	1,710
Net operating loss carryforwards	5,523	2,010
Self-insurance	146	151
Storm reserve liability	96	0
Other	6,881	5,716
Total deferred income tax assets	17,950	13,298
Deferred Income Tax Liabilities, Net	$ 180,656	$ 156,820

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Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Assets:
Investments	$ 9,229	$ 6,711
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	8,426	6,025
Fair Value, Inputs, Level 1 [Member] | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0
Significant Other Observable Inputs (Level 2)
Assets:
Assets, Fair Value Disclosure	0	82
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,844	1,604	[1]
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	803	686
Significant Unobservable Inputs (Level 3) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	27	22
Equity Securities [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0
Equity Securities [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0
Guaranteed Income Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	0
Guaranteed Income Fund [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0
Guaranteed Income Fund [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	803	686
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	8,399	6,003
Other Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0
Other Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0
Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	8,426	6,025
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	803	686
Mark-to-market energy assets, including put option | Fair Value, Inputs, Level 1 [Member]
Assets:
Mark-to-market energy assets, including put option	0
Mark-to-market energy assets, including put option | Significant Other Observable Inputs (Level 2)
Assets:
Mark-to-market energy assets, including put option	0	82	[1]
Mark-to-market energy assets, including put option | Significant Unobservable Inputs (Level 3)
Assets:
Mark-to-market energy assets, including put option	0
Fair Value
Assets:
Assets, Fair Value Disclosure	9,229	6,793
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,844	1,604	[1]
Fair Value | Equity Securities [Member]
Assets:
Investments	27	22
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	803	686
Fair Value | Other Investments [Member]
Assets:
Investments	8,399	6,003
Fair Value | Investments [Member]
Assets:
Investments	9,229	6,711
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 0	$ 82	[1]

[1] ⁽¹⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018

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Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 12,365,000	$ 7,316,000
Acquired finite-lived intangible assets, weighted average useful life		11 years
Goodwill		$ 32,668,000	21,568,000
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		800,000
Amortization of intangible assets		400,000
Finite-Lived Intangible Assets, Amortization Expense, Year Four		900,000
Amortization of intangible assets, 2019		1,200,000
Amortization of intangible assets, 2020		1,153,466
Amortization of intangible assets, 2022		800,000
Customer list
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 9,391,000	4,801,000
Customer list | Minimum
Goodwill [Line Items]
Amortized period of acquired intangible assets		5 years
Customer list | Boulden [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 4,600,000
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		2,252,000	$ 1,793,000
Noncompete Agreements [Member] | Boulden [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		500,000
Boulden [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill	[1]	$ 11,200,000

[1] ⁽³⁾ Mid-Atlantic Propane Operations goodwill balance includes $11.2 million recognized as a result of the purchase of the operating assets of Boulden in December 2019.

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Long-Term Debt - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Long-term debt maturities repayment of principal in next twelve months	$ 45,600,000
Long-term debt maturities repayment of principal in year two	13,600,000
Long-term debt maturities repayment of principal in year three	25,100,000
Long-term debt maturities repayment of principal in year four	20,600,000
Long-term debt maturities repayment of principal in year five	17,600,000
Long-term debt maturities repayment of principal in year five thereafter	364,100,000
Debt Instrument, Unused Borrowing Capacity, Amount	$ 250,000,000
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	$ 10,000,000.0
Cumulative consolidated net income base	509,500,000
Cumulative net income with restrictions	227,500,000
Cumulative net income free of restrictions	282,000,000.0
Restricted net assets of consolidated subsidiaries	$ 38,800,000
Percentage of restricted net assets	6.92%
Long-term debt including current maturities	$ 486,600,000	$ 327,200,000
Term Note Due January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.23%
Long-term debt including current maturities	$ 0	30,000,000
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Long-term debt including current maturities	$ 20,300,000	23,200,000
First Mortgage Bond Due On Two Thousand Twenty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Cumulative consolidated net income base	$ 168,100,000
Cumulative net income with restrictions	(37,600,000)
Cumulative net income free of restrictions	130,500,000
Long-term debt including current maturities	$ 7,990,000	7,986,000
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	$ 70,000,000
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	$ 6,300,000	7,000,000
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	$ 18,000,000	20,000,000
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	$ 50,000,000	50,000,000
Uncollateralized Senior Note One Due On Two Thousand Seventeen [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
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	$ 2,000,000	4,000,000
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	$ 12,000,000	$ 15,000,000
Florida Public Utilities Company [Member]
Debt Instrument [Line Items]
Cumulative net income with restrictions	$ 2,500,000

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($) utility mi	Dec. 31, 2018 USD ($) mi	Dec. 31, 2017 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Operating Lease, Liability	$ 11,601
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	$ 2,100	$ 2,800
Net property, plant and equipment	1,463,797	1,353,520
Accumulated depreciation	336,876	294,089
Depreciation and accretion reported in operations expenses	8,800	8,500	$ 8,100
Gain from a settlement	(130)	$ (130)	$ (130)
Operating Lease, Right-of-Use Asset	11,563
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	$ 6,700
Length of pipeline | mi	26	16
Ownership interest	45.00%
Accumulated depreciation	$ 1,500	$ 1,400
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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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ (20,000)	$ (22,000)	$ (31,000)
Tax expense recognized on the net gain (loss)	368,000	(49,000)	432,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (176,000)	$ (555,000)	$ (8,000)

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Environmental Commitments and Contingencies Environmental Remediation Status (Tables)

12 Months Ended

Dec. 31, 2019

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)	Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. We expect to implement similar remedial actions on the site's west parcel in 2020.	Between $4.5 million to $15.4 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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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]
Beginning Balances at Dec. 31, 2016		$ 446,086	[1]	$ 7,935	$ 250,967		$ 192,062	$ (4,878)	$ 2,416	$ (2,416)
Beginning Balances, shares at Dec. 31, 2016	[1],[2]			16,303,499
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		58,124					58,124
Other comprehensive loss		606						606
Dividends		(21,045)					21,045
Proceeds from issuance of common stock, net of expenses		(10)	[3]	$ 0	(10)
Stock Issued During Period, Shares, New Issues				0
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		735		$ 5	730
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				10,771
Share-based compensation		1,798	[4],[5]	$ 15	1,783
Share-based compensation, shares				30,172
Treasury stock activities		0							979	(979)
Ending Balances at Dec. 31, 2017		486,294	[1]	$ 7,955	253,470		229,141	(4,272)	3,395	(3,395)
Ending Balances, shares at Dec. 31, 2017	[1],[2]			16,344,442
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		56,580					56,580
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		(1,498)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect							907	(907)
Other comprehensive loss		(1,534)						(1,534)
Dividends		(23,600)					23,600
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan		(3)		$ 0	(3)
Proceeds from issuance of common stock, net of expenses		0
Share-based compensation		2,200	[4],[5]	$ 16	2,184	[4],[5]
Share-based compensation, shares	[4],[5]			34,103
Treasury stock activities									459	(459)
Ending Balances at Dec. 31, 2018		518,439		$ 7,971	255,651		261,530	(6,713)	3,854	(3,854)
Ending Balances, shares at Dec. 31, 2018	[1],[2]			16,378,545
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		65,153
Prior Period Reclassification Adjustment							115	(115)
Other comprehensive loss		561						561
Dividends		(26,191)					26,191
Stock Issued During Period, Value, Dividend Reinvestment Plan		(3)			(3)
Proceeds from issuance of common stock, net of expenses		0
Share-based compensation		3,618	[4],[5]	$ 13	3,605	[4],[5]
Share-based compensation, shares	[4],[5]			25,231
Treasury stock activities									689	(689)
Ending Balances at Dec. 31, 2019		$ 561,577		$ 7,984	$ 259,253		$ 300,607	$ (6,267)	$ 4,543	$ (4,543)
Ending Balances, shares at Dec. 31, 2019	[1],[2]			16,403,776

[1] Includes 95,329, 97,053 and 90,961 shares at December 31, 2019, 2018 and 2017, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan

[2] 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.

[3] Represents capitalized legal fees associated with our September 22, 2016 public offering.

[4] Includes amounts for shares issued for directors’ compensation.

[5] The shares issued under the SICP are net of shares withheld for employee taxes. For 2019, 2018 and 2017, we withheld 7,635, 16,918 and 10,269 shares, respectively, for taxes.

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Use of Estimates

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

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, 2019 and 2018 is provided in the following table:

	As of December 31,
(in thousands)	2019			2018
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	705,095		$	657,630
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	608,727			537,654
Electric distribution	127,651			102,133
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	141,841			123,632
Natural gas transmission and supply – Ohio	73,658			70,225
Electricity and steam generation	35,436			35,239
Mobile CNG and pipeline solutions	14,014			7,240
Other unregulated energy	104			104
Other	40,006			34,584
Total property, plant and equipment	1,746,532			1,568,441
Less: Accumulated depreciation and amortization	(336,876		)	(294,089		)
Plus: Construction work in progress	54,141			79,168
Net property, plant and equipment	$	1,463,797		$	1,353,520

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, 2019 and 2018, the non-refundable contributions totaled $2.1 million and $2.8 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, 2019 and 2018, AFUDC totaled $0.7 million and $1.9 million, respectively, which was reflected as a reduction of interest charges. During the year ended December 31, 2017, AFUDC was not material.

Leases

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets.

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 also included $6.7 million of assets, at December 31, 2019 and 2018, which consist of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned with Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. 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 $1.5 million and $1.4 million, at December 31, 2019 and 2018, respectively.

In May 2018, Peninsula Pipeline announced a plan to construct a jointly-owned 26-mile intrastate transmission pipeline in Nassau County, Florida with Seacoast Gas Transmission.  Peninsula Pipeline's ownership will be 50 percent. The pipeline is expected to be placed in-service during the third quarter of 2020.

Asset Impairment Evaluations

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, 2019, 2018 and 2017:

	2019	2018	2017
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.6%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.6%	2.7%	2.8%
Natural gas transmission – Florida	2.4%	2.3%	3.5%
Electric distribution	3.4%	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, 2019, 2018 and 2017, we reported $8.8 million, $8.5 million and $8.1 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 Doubtful Accounts

Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and general economic conditions. Accounts 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 during 2019, 2018 or 2017.

Goodwill and Other Intangible Assets

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We 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 2019, 2018 and 2017 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

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

Asset Retirement Obligation [Policy Text Block]

Asset Removal Cost

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

Pension and Other Postretirement Plans

Pension and Other Postretirement Plans

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

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

as the Prudential curve index and the FTSE Pension Discount curve, formerly the Citigroup yield curve, 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

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.

Recently Adopted Accounting Standards

Recently Adopted Accounting Standards

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a right of use model that requires a lessee to recognize a right of use asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; ASU No. 2018-11, Targeted Improvements; and ASU No. 2019-01, Codification Improvements. We adopted ASU 2016-02 and the related amendments on January 1, 2019, and used the optional transition method for all existing leases. The optional transition method enabled us to adopt the new standard as of the beginning of the period of adoption and did not require

restatement of prior period financial information. As a result, prior period financial information was not recast and continues to be reported under the accounting guidance effective during those periods.

At adoption, we elected the following practical expedients: (1) the ‘package of practical expedients,’ pursuant to which we did not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs, (2) the ‘use-of-hindsight’ practical expedient, which allowed us to use hindsight in assessing impairment of our existing land easements, (3) the creation of an accounting policy for short-term leases resulting in lease payments being recorded as an expense on a straight-line basis over the lease term, and (4) the aggregation, rather than separation, of the lease and non-lease components for all leases.

See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease accounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted ASU 2018-07 on January 1, 2019. Implementation of this new standard did not have a material impact on our financial position or results of operations

Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]

Recent Accounting Standards Yet to be Adopted

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. ASU 2016-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and is not expected to have a material impact on our financial position or results of operations.

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 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively, and are not expected to have a material impact on our financial position or results of operations.

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. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020, and since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

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Acquisitions Divestitures (Tables)

12 Months Ended

Dec. 31, 2019

Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]

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)	2019			2018			2017
Operating revenues(1)	$	161,289		$	258,713		$	184,519
Cost of sales(1)	157,646			252,111			182,307
Other operating expenses	5,222			6,825			4,522
Operating loss	(1,579		)	(223		)	(2,310		)
Interest and other expense	315			297			253
Loss from Discontinued Operations before income taxes	(1,894		)	(520		)	(2,563		)
Gain on sale of Discontinued Operations	7,344			—			—
Income tax (benefit) / expense	1,439			(238		)	(361		)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	4,011		$	(282	)	$	(2,202	)

⁽¹⁾ Included in operating revenues and cost of sales for the years ended December 31, 2019, 2018 and 2017, is $19.8 million, $31.5 million and $16.6 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity that will continue with the buyers after the disposition of the assets of PESCO.

Disclosure of Long Lived Assets Held-for-sale [Table Text Block]

The assets and liabilities of the discontinued operations classified as held for sale in the consolidated balance sheet at December 31, 2018 include the following:

	As of
(in thousands)	December 31, 2018
Property, plant and equipment	$	1,242
Less: accumulated depreciation	(206		)
Net property, plant and equipment (1)	1,036
Current assets (2)	52,681
Deferred charges and other assets (1)	6,626
Assets of Discontinued Operations held for sale	$	60,343
Current liabilities (3)	$	48,672
Liabilities of Discontinued Operations held for sale	$	48,672
Net assets	$	11,671

⁽¹⁾ These balances have been combined within the consolidated balance sheets to arrive at noncurrent assets held for sale.

⁽²⁾ At December 31, 2018, current assets were primarily comprised of $31.1 million of accounts receivable, $13.1 million of derivative assets at fair value, $4.9 million of accrued revenue and $3.2 million of storage gas prepayments.

⁽³⁾ At December 31, 2018, current liabilities were primarily comprised of $31.1 million of accounts payable, $13.3 million of derivative liabilities at fair value and $2.7 million of other accrued liabilities.

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		2017
Depreciation and amortization	$	477		$	582	$	213
Property, plant and equipment expenditures	—			115		11,766
Deferred income taxes	(125		)	1,088		(1,515		)
Realized / (loss) gain on commodity contracts	(2,161		)	5,002		4,911

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Investments

12 Months Ended

Dec. 31, 2019

Investments [Abstract]

Investments

INVESTMENTS

The investment balances at December 31, 2019 and 2018, consisted of the following:

	As of December 31,
(in thousands)	2019		2018
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	9,202	$	6,689
Investments in equity securities	27		22
Total	$	9,229	$	6,711

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2019, 2018 and 2017, we recorded net unrealized gains of $1.6 million, net unrealized losses of $0.4 million, and net unrealized gains of $1.0 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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Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2019		Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted		751		792
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number		14,107
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance		131,741		132,642
Number of Shares, Granted		88,048	[1]	49,494
Number of Shares, Vested		(25,831)		(29,786)
Number of Shares, Expired		(15,086)		(3,933)
Number of Shares, Outstanding Ending Balance		157,817		131,741
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		$ 67.24		$ 59.31
Weighted Average Grant Date Fair Value, Granted		92,740	[1]	67.76
Weighted Average Grant Date Fair Value, Vested		67,080.00		47.39
Weighted Average Grant Date Fair Value, Expired		69,280		49.66
Weighted Average Grant Date Fair Value, Outstanding Ending Balance		$ 80,280		67.24
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]	$ 71,670
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				$ 75.78
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number				16,676

[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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Employee Benefit Plans Employee benefit plans phantoms (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Funded status	$ (1,584)	$ (2,063)

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Segment Information

12 Months Ended

Dec. 31, 2019

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 our mobile compressed natural gas and pipeline solutions subsidiary. 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, PESCO's results, previously reported in the Unregulated Energy segment, are reflected in discontinued operations. See Note 4, Acquisitions and Divestitures for additional details regarding the divestiture of PESCO.

The remainder of our operations is 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,
	2019			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	340,857		$	343,313		$	323,972
Unregulated Energy	138,747			147,003			125,674
Total operating revenues, unaffiliated customers	$	479,604		$	490,316		$	449,646
Intersegment Revenues (1)
Regulated Energy	$	2,149		$	1,968		$	2,338
Unregulated Energy	15,403			14,902			14,402
Other businesses	528			652			774
Total intersegment revenues	$	18,080		$	17,522		$	17,514
Operating Income
Regulated Energy	$	86,584		$	79,215		$	74,584
Unregulated Energy	19,939			17,124			14,941
Other businesses and eliminations	(236		)	(1,496		)	205
Operating Income	106,287			94,843			89,730
Other expense, net	(1,830		)	(603		)	(2,204		)
Interest charges	22,224			16,146			12,530
Income from Continuing Operations before Income Taxes	$	82,233		$	78,094		$	74,996
Income Taxes on Continuing Operations	21,091			21,232			14,670
Income from Continuing Operations	61,142			56,862			60,326
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)
Gain on sale of Discontinued Operations, Net of tax	5,402			—			—
Net Income	$	65,153		$	56,580		$	58,124
Depreciation and Amortization
Regulated Energy	$	35,227		$	31,876		$	28,554
Unregulated Energy	10,129			8,263			7,741
Other businesses and eliminations	67			81			91
Total depreciation and amortization	$	45,423		$	40,220		$	36,386
Capital Expenditures
Regulated Energy	$	130,604		$	235,912		$	159,011
Unregulated Energy	60,034			38,585			14,424
Other businesses	8,348			8,364			5,902
Total capital expenditures	$	198,986		$	282,861		$	179,337

 

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

	As of December 31,
	2019		2018
Identifiable Assets (1)
Regulated Energy segment	$	1,434,066	$	1,345,805
Unregulated Energy segment (1)	296,810		245,702
Other businesses and eliminations	52,322		41,821
Total identifiable assets (1)	$	1,783,198	$	1,633,328

⁽¹⁾ 2018 balance excludes assets held for sale related to the sale of assets and contracts for PESCO.

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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, 2019	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments		$ 47,316	$ 46,692
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		52,250
Balance, end of year		54,333	52,250
Defined Benefit Plan, Alternative Investments, Fair Value of Plan Assets	[1]	7,017	5,558
Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		46,065
Balance, end of year		46,169	46,065
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		627	436
Purchases		2,274	1,674
Transfers in		3,090	2,375
Disbursements		(4,907)	(3,872)
Investment Income		63	14
Balance, end of year		1,147	627
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		20,499
Balance, end of year		20,477	20,499
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		20,499
Balance, end of year		20,477	20,499
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		21,448
Balance, end of year		21,696	21,448
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		21,448
Balance, end of year		21,696	21,448
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		4,745
Balance, end of year		5,143	4,745
Other Investments [Member] | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		4,118
Balance, end of year		3,996	4,118
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		627
Balance, end of year		1,147	627
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]	3,399
Balance, end of year	[2]	3,553	3,399
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]	3,399
Balance, end of year	[2]	3,553	3,399
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]	1,478
Balance, end of year	[2]	1,604	1,478
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]	1,478
Balance, end of year	[2]	1,604	1,478
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]	670
Balance, end of year	[2]	726	670
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]	670
Balance, end of year	[2]	726	670
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]	9,226
Balance, end of year	[3]	9,855	9,226
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]	9,226
Balance, end of year	[3]	9,855	9,226
International All Cap Equity | Investments in equity securities | Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	0
Balance, end of year	[3]	0	0
International All Cap Equity | Investments in equity securities | Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	0
Balance, end of year	[3]	0	0
Alternative Strategies | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	5,726
Balance, end of year	[4]	4,739	5,726
Alternative Strategies | Investments in equity securities | Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[4]	5,726
Balance, end of year	[4]	4,739	5,726
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]	18,630
Balance, end of year	[5]	19,220	18,630
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]	18,630
Balance, end of year	[5]	19,220	18,630
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]	2,818
Balance, end of year	[5]	2,476	2,818
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]	2,818
Balance, end of year	[5]	2,476	2,818
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]	1,902
Balance, end of year	[6]	1,708	1,902
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]	1,902
Balance, end of year	[6]	1,708	1,902
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]	2,216
Balance, end of year	[7]	2,288	2,216
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]	2,216
Balance, end of year	[7]	2,288	2,216
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]	627
Balance, end of year	[8]	1,147	627
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]	627
Balance, end of year	[8]	$ 1,147	$ 627

[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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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Text Block [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, 2019 and 2018 is provided in the following table:

	As of December 31,
(in thousands)	2019			2018
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	705,095		$	657,630
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	608,727			537,654
Electric distribution	127,651			102,133
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	141,841			123,632
Natural gas transmission and supply – Ohio	73,658			70,225
Electricity and steam generation	35,436			35,239
Mobile CNG and pipeline solutions	14,014			7,240
Other unregulated energy	104			104
Other	40,006			34,584
Total property, plant and equipment	1,746,532			1,568,441
Less: Accumulated depreciation and amortization	(336,876		)	(294,089		)
Plus: Construction work in progress	54,141			79,168
Net property, plant and equipment	$	1,463,797		$	1,353,520

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, 2019 and 2018, the non-refundable contributions totaled $2.1 million and $2.8 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, 2019 and 2018, AFUDC totaled $0.7 million and $1.9 million, respectively, which was reflected as a reduction of interest charges. During the year ended December 31, 2017, AFUDC was not material.

Leases

We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets.

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 also included $6.7 million of assets, at December 31, 2019 and 2018, which consist of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned with Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. 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 $1.5 million and $1.4 million, at December 31, 2019 and 2018, respectively.

In May 2018, Peninsula Pipeline announced a plan to construct a jointly-owned 26-mile intrastate transmission pipeline in Nassau County, Florida with Seacoast Gas Transmission.  Peninsula Pipeline's ownership will be 50 percent. The pipeline is expected to be placed in-service during the third quarter of 2020.

Asset Impairment Evaluations

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, 2019, 2018 and 2017:

	2019	2018	2017
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.6%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.6%	2.7%	2.8%
Natural gas transmission – Florida	2.4%	2.3%	3.5%
Electric distribution	3.4%	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, 2019, 2018 and 2017, we reported $8.8 million, $8.5 million and $8.1 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 Doubtful Accounts

Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and general economic conditions. Accounts 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 during 2019, 2018 or 2017.

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 2019, 2018 and 2017 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 primarily 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 Pension Discount curve, formerly the Citigroup yield curve, 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

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.

Recently Adopted Accounting Standards

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a right of use model that requires a lessee to recognize a right of use asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; ASU No. 2018-11, Targeted Improvements; and ASU No. 2019-01, Codification Improvements. We adopted ASU 2016-02 and the related amendments on January 1, 2019, and used the optional transition method for all existing leases. The optional transition method enabled us to adopt the new standard as of the beginning of the period of adoption and did not require

restatement of prior period financial information. As a result, prior period financial information was not recast and continues to be reported under the accounting guidance effective during those periods.

At adoption, we elected the following practical expedients: (1) the ‘package of practical expedients,’ pursuant to which we did not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs, (2) the ‘use-of-hindsight’ practical expedient, which allowed us to use hindsight in assessing impairment of our existing land easements, (3) the creation of an accounting policy for short-term leases resulting in lease payments being recorded as an expense on a straight-line basis over the lease term, and (4) the aggregation, rather than separation, of the lease and non-lease components for all leases.

See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease accounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted ASU 2018-07 on January 1, 2019. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

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. ASU 2016-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and is not expected to have a material impact on our financial position or results of operations.

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 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively, and are not expected to have a material impact on our financial position or results of operations.

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. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020, and since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

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Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2019 USD ($) plan shares	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans | plan		3
Income tax benefits		$ 1,700
Pre-merger regulatory asset		6
Total unrecognized cost		22,286
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%
Maximum percentage of eligible compensation		6.00%
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		$ 5,700	$ 5,500	$ 5,000
Shares reserved to fund future contributions | shares		831,183
Investments, Fair Value Disclosure		$ 9,229	6,711
Deferred compensation obligation		$ 4,543	$ 3,854
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			10.00%
Number Of Years to Collect Benefits		15 years
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		$ 0
Total unrecognized cost		2,241
Unfunded accumulated benefit obligation		(1,584)	$ (2,063)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		300
Expected contribution	[1]	115
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		19,339
Unfunded accumulated benefit obligation		(15,601)	(15,776)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		3,200
Expected contribution	[1]	3,281
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		575
Unfunded accumulated benefit obligation		(2,157)	(2,285)
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]
Pre-merger regulatory asset		$ 0
Total unrecognized cost		157
Unfunded accumulated benefit obligation		$ (1,100)	(1,002)
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]	90
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		6
Total unrecognized cost		(26)
Unfunded accumulated benefit obligation		$ (1,224)	(1,187)
Health care inflation rate		5.00%
Expected contribution	[2]	$ 86
Rabbi Trust Associated With Deferred Compensation [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure		$ 9,202	6,689
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		$ 9,200	6,700
Deferred Compensation Equity		$ 4,500	$ 3,900

[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 Assets by Investment Type (Detail)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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%	49.00%	53.00%
Chesapeake Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	92.00%	41.00%	38.00%
Chesapeake Pension Plan | Other
Asset Category
Percentage of assets by investment type	8.00%	10.00%	9.00%
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	53.00%	50.00%	55.00%
FPU Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	37.00%	41.00%	37.00%
FPU Pension Plan | Other
Asset Category
Percentage of assets by investment type	10.00%	9.00%	8.00%

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Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Subsequent Event [Line Items]
Intercompany Agreements, Description	P3Y
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	$ 60,735
Total purchase obligations for 2019 - 2020	72,123
Total purchase obligations for 2021 - 2022	60,049
Total purchase obligations thereafter	201,131
Aggregate guaranteed amount	37,000
Guarantor Obligations, Current Carrying Value	24,700
Guarantor Obligations, Current Carrying Value, PESCO	16,300
Amount of letter of credit to our current primary insurance company	$ 5,400
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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Stockholders' Equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

STOCKHOLDERS' EQUITY

Accumulated Other Comprehensive (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures and swap contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). In 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contract cash flow hedges. The following table presents the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2019 and 2018. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	(602		)	(3,130		)	(3,732		)
Amounts reclassified from accumulated other comprehensive income	439			1,759			2,198
Net current-period other comprehensive loss	(163		)	(1,371		)	(1,534		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
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	)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2019, 2018 and 2017. 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)	2019			2018			2017
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(2,600		)	(579		)	(636		)
Total before income taxes	(2,523		)	(502		)	(559		)
Income tax benefit (4)	656			63			223
Net of tax	$	(1,867	)	$	(439	)	$	(336	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	1,520		$	(647	)	$	1,607
Natural gas swaps (2)(3)	7			197			(822		)
Natural gas futures (2)(3)	2,096			(2,010		)	(456		)
Total before income taxes	3,623			(2,460		)	329
Income tax impact (4)	(1,028		)	701			(159		)
Net of tax	$	2,595		$	(1,759	)	$	170
Total reclassifications for the period	$	728		$	(2,198	)	$	(166	)

⁽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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Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019 USD ($) mi	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($)	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2019 USD ($) dekatherm / d mi	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Rates and Other Regulatory Activities [Line Items]
Restricted Payment	$ 227,500								$ 227,500
Regulatory Assets	78,551				$ 77,218				78,551	$ 77,218
Revenues	$ 131,973	$ 92,626	$ 94,541	$ 160,464	$ 134,214	$ 93,400	$ 93,872	$ 168,831	479,604	$ 490,316	$ 449,646
Depreciation Expense Decrease from Depreciation Study Rate Change									$ 900
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Years to Recover Storm Related Costs									2 years
Extent of Customers Losing Service									100.00%
Amounts Spent to Restore Service									$ 65,000
Number of Term Notes Issued for Hurricane Michael	2								2
Number of Months for Term Notes to Finance Hurricane Michael									13 months
Dollar Amount of Term Notes to Finance Hurricane Michael Costs									$ 30,000
Asset Recovery Damaged Property Costs, Noncurrent	$ 1,500								1,500
Deferred Storm and Property Reserve Deficiency, Noncurrent	$ 800								$ 800
Basis Plus LIBOR for Term Notes to Finance Hurricane Michael Costs	75								75
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 | 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
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Restricted Payment	$ 2,500								$ 2,500
Business Acquisition Premium Paid	$ 34,200								$ 34,200
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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Income Taxes

12 Months Ended

Dec. 31, 2019

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 2014 are subject to examination. At December 31, 2019, the 2015 through 2018 federal income tax returns are under examination, and no report has been issued at this time.

We had a net operating loss for federal income tax purposes as of December 31, 2019 totaling $3.0 million. We will have a federal net operating loss totaling $12.2 million for 2018 upon the settlement of the Internal Revenue Service audit described above. We did not have a federal net operating loss for tax year 2017. For state income tax purposes, we had net operating losses in various

states of $54.7 million and $60.1 million as of December 31, 2019 and 2018, respectively, almost all of which will expire in 2038. Excluding net operating losses from discontinued operations we have recorded deferred tax assets of $5.5 million and $2.0 million related to state net operating loss carry-forwards at December 31, 2019 and 2018, respectively, but we have not recorded a valuation allowance to reduce the future benefit of the tax net operating losses because we believe they will be fully utilized.

Federal Tax Reform

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.

In 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flow hedges.

The following tables provide: (a) the components of income tax expense in 2019, 2018, and 2017; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2019, 2018, and 2017 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2019 and 2018.

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Current Income Tax Expense
Federal	$	(2,271	)	$	48		$	2,046
State	(492		)	581			610
Other	(47		)	(47		)	(71		)
Total current income tax expense (benefit)	(2,810		)	582			2,585
Deferred Income Tax Expense (1)
Property, plant and equipment	25,910			19,189			8,181
Deferred gas costs	79			(1,435		)	2,002
Pensions and other employee benefits	(454		)	446			180
FPU merger-related premium cost and deferred gain	(278		)	(528		)	(1,148		)
Net operating loss carryforwards	(3,776		)	(183		)	193
Other	2,420			3,161			2,677
Total deferred income tax expense	23,901			20,650			12,085
Income Tax Expense from Continuing Operations	21,091			21,232			14,670
Income Tax Expense (benefit) from Discontinued Operations	1,439			(238		)	(361		)
Total Income Tax	$	22,530		$	20,994		$	14,309

⁽¹⁾ Includes $4.7 million, $3.5 million, and $0.9 million of deferred state income taxes for the years 2019, 2018 and 2017, respectively.

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	17,246		$	16,491		$	26,249
State income taxes, net of federal benefit	5,088			4,057			2,000
ESOP dividend deduction	(173		)	(158		)	(257		)
Revaluation of deferred tax assets and liabilities	—			—			(14,299		)
Other	(1,070		)	842			977
Total Income Tax Expense for Continuing Operations	$	21,091		$	21,232		$	14,670
Effective Income Tax Rate for Continuing Operations (2)	25.65		%	27.19		%	19.56		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2019 and 2018 and 35 percent for 2017.

⁽²⁾The effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA.

	As of December 31,
	2019		2018
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	173,466	$	153,423
Acquisition adjustment	6,969		8,896
Loss on reacquired debt	220		32
Deferred gas costs	1,223		1,139
Natural gas conversion costs	4,956		3,987
Storm reserve liability	10,316		97
Other	1,456		2,544
Total deferred income tax liabilities	198,606		170,118
Deferred income tax assets:
Pension and other employee benefits	3,818		3,711
Environmental costs	1,486		1,710
Net operating loss carryforwards	5,523		2,010
Self-insurance	146		151
Storm reserve liability	96		—
Other	6,881		5,716
Total deferred income tax assets	17,950		13,298
Deferred Income Taxes Per Consolidated Balance Sheets	$	180,656	$	156,820

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Environmental Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018, we had approximately $8.0 million and $9.1 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, 2019 and 2018, we have recovered approximately $11.9 million and $11.5 million, respectively, leaving approximately $2.1 million and $2.5 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)	Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. We expect to implement similar remedial actions on the site's west parcel in 2020.	Between $4.5 million to $15.4 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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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018. All amounts in the following tables are presented net of tax.

 

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	(602		)	(3,130		)	(3,732		)
Amounts reclassified from accumulated other comprehensive income	439			1,759			2,198
Net current-period other comprehensive loss	(163		)	(1,371		)	(1,534		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
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	)

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, 2019, 2018 and 2017. 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)	2019			2018			2017
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(2,600		)	(579		)	(636		)
Total before income taxes	(2,523		)	(502		)	(559		)
Income tax benefit (4)	656			63			223
Net of tax	$	(1,867	)	$	(439	)	$	(336	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	1,520		$	(647	)	$	1,607
Natural gas swaps (2)(3)	7			197			(822		)
Natural gas futures (2)(3)	2,096			(2,010		)	(456		)
Total before income taxes	3,623			(2,460		)	329
Income tax impact (4)	(1,028		)	701			(159		)
Net of tax	$	2,595		$	(1,759	)	$	170
Total reclassifications for the period	$	728		$	(2,198	)	$	(166	)

⁽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.

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of December 31, 2019, 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)	9.9	Cash flows hedges	June 2022

Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]

(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Sharp	Other Current Assets	$	2,317	$	2,173

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, 2019 and 2018 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	71
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	—		11
Total Derivative Assets		$	—	$	82

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	$	1,844	$	1,604
Total Derivative Liabilities		$	1,844	$	1,604

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)		2019			2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	—		$	112
Propane swap agreements	Cost of sales	—			(13		)	8
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	1,520			(647		)	1,607
Propane swap agreements	Other comprehensive income (loss)	(253		)	(2,773		)	487
Natural gas swap contracts	Other comprehensive income (loss)	(63		)	200			986
Natural gas futures contracts	Other comprehensive income (loss)	(294		)	532			(1,476		)
Total		$	910		$	(2,701	)	$	1,715

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represented the effect of trading activities for Xeron on our consolidated statement of income.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

The following tables provide: (a) the components of income tax expense in 2019, 2018, and 2017; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2019, 2018, and 2017 from continuing operations; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2019 and 2018.

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Current Income Tax Expense
Federal	$	(2,271	)	$	48		$	2,046
State	(492		)	581			610
Other	(47		)	(47		)	(71		)
Total current income tax expense (benefit)	(2,810		)	582			2,585
Deferred Income Tax Expense (1)
Property, plant and equipment	25,910			19,189			8,181
Deferred gas costs	79			(1,435		)	2,002
Pensions and other employee benefits	(454		)	446			180
FPU merger-related premium cost and deferred gain	(278		)	(528		)	(1,148		)
Net operating loss carryforwards	(3,776		)	(183		)	193
Other	2,420			3,161			2,677
Total deferred income tax expense	23,901			20,650			12,085
Income Tax Expense from Continuing Operations	21,091			21,232			14,670
Income Tax Expense (benefit) from Discontinued Operations	1,439			(238		)	(361		)
Total Income Tax	$	22,530		$	20,994		$	14,309

⁽¹⁾ Includes $4.7 million, $3.5 million, and $0.9 million of deferred state income taxes for the years 2019, 2018 and 2017, respectively.

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Reconciliation of Effective Income Tax Rates for Continuing Operations
Federal income tax expense (1)	$	17,246		$	16,491		$	26,249
State income taxes, net of federal benefit	5,088			4,057			2,000
ESOP dividend deduction	(173		)	(158		)	(257		)
Revaluation of deferred tax assets and liabilities	—			—			(14,299		)
Other	(1,070		)	842			977
Total Income Tax Expense for Continuing Operations	$	21,091		$	21,232		$	14,670
Effective Income Tax Rate for Continuing Operations (2)	25.65		%	27.19		%	19.56		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2019 and 2018 and 35 percent for 2017.

⁽²⁾The effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA.

Schedule of Accumulated Deferred Income Tax Assets and Liabilities

	As of December 31,
	2019		2018
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	173,466	$	153,423
Acquisition adjustment	6,969		8,896
Loss on reacquired debt	220		32
Deferred gas costs	1,223		1,139
Natural gas conversion costs	4,956		3,987
Storm reserve liability	10,316		97
Other	1,456		2,544
Total deferred income tax liabilities	198,606		170,118
Deferred income tax assets:
Pension and other employee benefits	3,818		3,711
Environmental costs	1,486		1,710
Net operating loss carryforwards	5,523		2,010
Self-insurance	146		151
Storm reserve liability	96		—
Other	6,881		5,716
Total deferred income tax assets	17,950		13,298
Deferred Income Taxes Per Consolidated Balance Sheets	$	180,656	$	156,820

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Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 22,611	$ 16,741	$ 12,420
Cash paid for income taxes	$ 3,221	$ 477	$ (4,114)

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Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 11,563
Operating Lease, Liability, Current	1,705
Operating Lease, Liability, Noncurrent	9,896
Total Operating and Finance Lease Liabilities	$ 11,601

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Short-Term Borrowing - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Oct. 08, 2015 USD ($)
Short-term Debt [Line Items]
Short-term borrowings	$ 247,371,000	$ 294,458,000
Line of Credit Facility, Aggregate Borrowing Capacity	$ 370,000,000
Number Of Unsecured Bank Credit Facilities	4
Number Of Financial Institutions With Bank Credit Facilities	4
Line Of Available Credit Facility Borrowing Capacity	$ 220,000,000.0
ParticipatingLendersInTheRevolver	5
Short-term Debt, Weighted Average Interest Rate, at Point in Time	2.62%	3.44%
Line of Credit Facility, Commitment Fee Amount	$ 100,000
Ratio of Indebtedness to Net Capital	0.65
Uncommitted Line Of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Current Borrowing Capacity			$ 150,000,000.0
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity	$ 370,000,000.0
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
Line of Credit Facility, Aggregate Borrowing Capacity	$ 80,000,000
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
Line of Credit Facility, Aggregate Borrowing Capacity	$ 45,000,000

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Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 47,430	$ 52,140
Contract with Customer, Asset, Net, Noncurrent	3,465	2,614
Contract with Customer, Liability, Current	589	480
Increase (Decrease) in Receivables	(4,710)
Increase (Decrease) in Other Noncurrent Assets	851
Increase (Decrease) in Other Current Liabilities	109
Contract with Customer, Liability, Revenue Recognized	$ 1,000	$ 700

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2019

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)
2019 (1)
Operating Revenues	$	160,464		$	94,541		$	92,626		$	131,973
Operating Income	$	44,123		$	18,164		$	14,358		$	29,642
Net Income:
Income from Continuing Operations	$	28,814		$	8,913		$	6,246		$	17,169
Loss from Discontinued Operations, Net of Tax	(149		)	(609		)	(624		)	(9		)
Gain on sale of Discontinued Operations, Net of Tax	—			—			—			5,402
	$	28,665		$	8,304		$	5,622		$	22,562
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
	$	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
	$	1.74		$	0.50		$	0.34		$	1.37
2018 (1)
Operating Revenues	$	168,831		$	93,872		$	93,400		$	134,214
Operating Income	$	40,853		$	12,238		$	12,879		$	28,873
Net Income:
Income from Continuing Operations	$	27,271		$	5,705		$	6,090		$	17,796
Income/(Loss) from Discontinued Operations	(415		)	680			(552		)	5
	$	26,856		$	6,385		$	5,538		$	17,801
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.67		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.03		)	0.04			(0.03		)	—
	$	1.64		$	0.39		$	0.34		$	1.09
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.66		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.02		)	0.04			(0.04		)	—
	$	1.64		$	0.39		$	0.33		$	1.09

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

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Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Property, Plant and Equipment
Regulated Energy		$ 1,441,473	$ 1,297,416
Unregulated Energy		265,209	236,440
Other businesses and eliminations		39,850	34,585
Total property, plant and equipment		1,746,532	1,568,441
Less: Accumulated depreciation and amortization		(336,876)	(294,089)
Plus: Construction work in progress		54,141	79,168
Net property, plant and equipment		1,463,797	1,353,520
Current Assets
Cash and cash equivalents		6,985	6,089
Accounts receivable (less allowance for uncollectible accounts of $1,337 and $1,058, respectively)		49,562	53,837
Accrued revenue		20,846	22,640
Propane inventory, at average cost		5,824	9,791
Other inventory, at average cost		6,067	7,127
Regulatory assets		5,144	4,796
Storage gas prepayments		3,541	3,433
Income taxes receivable		20,050	15,300
Prepaid expenses		13,928	10,079
Derivative assets, at fair value		0	82
Other current assets		2,879	5,682
Disposal Group, Including Discontinued Operation, Assets, Current		0	52,681
Total current assets		134,826	191,537
Deferred Charges and Other Assets
Goodwill		32,668	21,568
Other intangible assets, net		8,129	3,850
Investments, at fair value		9,229	6,711
Operating Lease, Right-of-Use Asset		11,563
Regulatory assets		73,407	72,422
Receivables and other deferred charges		49,579	36,401
Disposal Group, Including Discontinued Operation, Assets, Noncurrent		0	7,662
Total deferred charges and other assets		184,575	148,614
Total Assets		1,783,198	1,693,671
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)		7,984	7,971
Additional paid-in capital		259,253	255,651
Retained earnings		300,607	261,530
Accumulated other comprehensive loss		(6,267)	(6,713)
Deferred compensation obligation		4,543	3,854
Treasury stock		(4,543)	(3,854)
Total stockholders’ equity		561,577	518,439
Long-term debt, net of current maturities		440,168	316,020
Total capitalization		1,001,745	834,459
Current Liabilities
Current portion of long-term debt		45,600	11,935
Short-term borrowing		247,371	294,458
Accounts payable		54,068	98,681
Customer deposits and refunds		30,939	32,620
Accrued interest		2,554	2,317
Dividends payable		6,644	6,060
Accrued compensation		16,236	13,923
Regulatory liabilities		5,991	7,883
Derivative liabilities, at fair value		1,844	1,604
Other accrued liabilities		12,077	10,081
Disposal Group, Including Discontinued Operation, Liabilities	[1]		48,672
Total current liabilities		423,324	528,234
Deferred Credits and Other Liabilities
Deferred income taxes		180,656	156,820
Regulatory liabilities		127,744	135,039
Environmental liabilities		6,468	7,638
Other pension and benefit costs		30,569	28,513
Operating Lease, Liability, Noncurrent		9,896
Operating Lease, Liability		11,601
Deferred investment tax credits and other liabilities		2,796	2,968
Total deferred credits and other liabilities		358,129	330,978
Commitments and Contingencies
Total Capitalization and Liabilities		$ 1,783,198	$ 1,693,671

[1] ⁽³⁾ At December 31, 2018, current liabilities were primarily comprised of $31.1 million of accounts payable, $13.3 million of derivative liabilities at fair value and $2.7 million of other accrued liabilities.

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Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues
Regulated Energy	$ 343,006	$ 345,281	$ 326,310
Unregulated Energy	154,150	161,904	140,076
Other	(17,552)	(16,869)	(16,740)
Total operating revenues	479,604	490,316	449,646
Operating Expenses
Regulated Energy cost of sales	102,803	121,828	118,769
Unregulated Energy and other cost of sales	51,697	68,342	53,420
Operations	137,844	132,523	121,949
Cost, Maintenance	15,679	14,387	12,701
Gain from a settlement	(130)	(130)	(130)
Depreciation and amortization	45,423	40,220	36,386
Other taxes	20,001	18,303	16,821
Total operating expenses	373,317	395,473	359,916
Operating Income	106,287	94,843	89,730
Other expense, net	(1,830)	(603)	(2,204)
Interest charges	22,224	16,146	12,530
Income from Continuing Operations Before Income Taxes	82,233	78,094	74,996
Income Taxes on Continuing Operations	21,091	21,232	14,670
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	61,142	56,862	60,326
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent	(1,391)	(282)	(2,202)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax	5,402
Net Income (Loss) Attributable to Parent	$ 65,153	$ 56,580	$ 58,124
Weighted Average Common Shares Outstanding:
Basic (in shares)	16,398,443	16,369,616	16,336,789
Diluted (in shares)	16,448,486	16,419,870	16,383,352
Basic Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share	$ 3.73	$ 3.48	$ 3.69
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0.24	(0.02)	(0.13)
Basic (in usd per share)	3.97	3.46	3.56
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share	3.72	3.47	3.68
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0.24	(0.02)
Diluted (in usd per share)	$ 3.96	$ 3.45	$ 3.55

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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, 2019

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)	$12,847	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)	$4,087	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)	$3,765	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)	$8,304	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)	$19,218	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$294	Same treatment on a net basis as Chesapeake 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 Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,769	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its 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.

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Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2019
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

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Derivative Instruments Volume of Derivative Activity (Details)	12 Months Ended
	Dec. 31, 2019 gal
Sharp Energy Inc [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	9,900,000

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Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Income Tax Expense
Federal		$ (2,271)	$ 48	$ 2,046
State		(492)	581	610
Other		(47)	(47)	(71)
Total current income tax expense (benefit)		(2,810)	582	2,585
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	23,901	20,650	12,085
Income Tax Expense from Continuing Operations		21,091	21,232	14,670
Discontinued Operation, Tax Effect of Gain (Loss) from Disposal of Discontinued Operation		(1,439)	(238)	(361)
Income Tax Expense (Benefit), Continuing Operations, Discontinued Operations		22,530	20,994	14,309
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		25,910	19,189	8,181
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		79	(1,435)	2,002
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		(454)	446	180
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense		(278)	(528)	(1,148)
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		(3,776)	(183)	193
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ 2,420	$ 3,161	$ 2,677

[1] ⁽¹⁾ Includes $4.7 million, $3.5 million, and $0.9 million of deferred state income taxes for the years 2019, 2018 and 2017, respectively.

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Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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%	21.00%	35.00%

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Investments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Investments [Abstract]
Unrealized gain, net of other expenses	$ 1,600	$ (400)	$ 1,000

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Derivative Instruments

12 Months Ended

Dec. 31, 2019

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. 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. Aspire Energy 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. As of December 31, 2019 and 2018, 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 to UET, NJRES, Gas South, and DFS and, therefore, no longer have natural gas futures and contracts recorded in our consolidated financial statements. The gains and losses associated with PESCO's financial instruments are reflected as discontinued operations in the consolidated statements of income and PESCO's assets and liabilities are reflected as held-for-sale in the consolidated balance sheets.

Volume of Derivative Activity

As of December 31, 2019, 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)	9.9	Cash flows hedges	June 2022

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased 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 2019 through June 2022) 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 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 $1.5 million from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2020.

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 MTM 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, 2019		December 31, 2018
Sharp	Other Current Assets	$	2,317	$	2,173

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. As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets and liabilities held-for-sale in the consolidated balance sheet as of December 31, 2018. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2019 and 2018 are as follows:

	Derivative Assets
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	71
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	—		11
Total Derivative Assets		$	—	$	82

 

	Derivative Liabilities
		Fair Value as of
(in thousands)	Balance Sheet Location	December 31, 2019		December 31, 2018
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	$	1,844	$	1,604
Total Derivative Liabilities		$	1,844	$	1,604

 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)		2019			2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	—		$	112
Propane swap agreements	Cost of sales	—			(13		)	8
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	1,520			(647		)	1,607
Propane swap agreements	Other comprehensive income (loss)	(253		)	(2,773		)	487
Natural gas swap contracts	Other comprehensive income (loss)	(63		)	200			986
Natural gas futures contracts	Other comprehensive income (loss)	(294		)	532			(1,476		)
Total		$	910		$	(2,701	)	$	1,715

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represented the effect of trading activities for Xeron on our consolidated statement of income.

As of December 31, 2019 and 2018, we did not have any material fair value hedges.

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 4,279	$ 3,410	$ 2,490
Less: tax benefit	(1,117)	(934)	(1,003)
Share-Based Compensation amounts included in net income	3,162	2,476	1,487
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	4,300
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	620	539	540
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	200
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	15,100	10,700	10,400
Total compensation expense	$ 3,659	$ 2,871	$ 1,950

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Acquisitions

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Acquisitions

ACQUISITIONS AND DIVESTITURES

Acquisition of Elkton Gas Company

In December 2019, we entered into an agreement with SJI to acquire its subsidiary, Elkton Gas Company, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Upon completion of the transaction, Elkton Gas Company will become our wholly-owned subsidiary. The acquisition, which is expected to close in the second half of 2020, is subject to approval by the Maryland PSC. Elkton Gas Company's territory is contiguous to our franchised service territory in Cecil County, Maryland and it will continue to operate out of its existing office with the same local personnel.

Acquisitions in 2019

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 contract through the first anniversary of the transaction closing. We accounted for the purchase of the operating assets of Boulden as a business combination within our Unregulated Energy segment. 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 are preliminary and subject to adjustment based on contractual provisions that will be finalized at the end of the measurement period. Contributions to our operating revenues and operating income as a result of this acquisition for the year ended December 31, 2019 can be found in the table below.

Acquisitions in 2018

In December 2018, Marlin Gas Services acquired certain operating assets of Marlin Gas Transport, a supplier of 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. 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 steel tube CNG trailers, composite CNG trailers, mobile compression equipment and an internally-developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas.

In December 2018, Sharp acquired certain propane operating assets and customers of Ohl, which provided propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania.

We accounted for the purchases of the operating assets of Marlin Gas Transport and Ohl, which totaled approximately $18.2 million, as business combinations within our Unregulated Energy segment. Goodwill of $4.8 million, related to the Marlin Gas Transport acquisition, and $1.5 million, associated with the Ohl acquisition, were initially recorded at the close of these transactions. In 2019, we recorded a reduction to the purchase price for Ohl of $0.2 million upon completing our verification of the assets purchased.  The purchase price adjustment was recorded as a reduction in our property, plant and equipment balance.  Due to the timing of these acquisitions, the revenue and operating income from these acquisitions in 2018 were immaterial. For the year ended December 31, 2019, these acquisitions generated the following operating revenue and income:

	For the Year Ended
	December 31, 2019
	Operating Revenues		Operating Income
(in thousands)
Marlin Gas Services	$	5,702	$	1,500
Ohl propane acquisition	$	1,662	$	385
Boulden acquisition	$	550	$	239

Divestiture of PESCO

In September of 2019, we initiated a plan to sell a majority of the assets of PESCO, our natural gas marketing subsidiary. This was done in an effort to enable us to focus on the strategies that support our core energy delivery business. During the fourth quarter of 2019, we executed four separate transactions associated with the sale of PESCO’s assets and contracts:

• PESCO’s Florida retail operations were sold to Gas South. The initial closing for the transaction was completed in November 2019 with subsequent closings occurring in December 2019.

• PESCO’s other non-Florida retail operations and contracts were sold to UET in October 2019.

• PESCO’s Mid-Atlantic wholesale contracts and Chesapeake Utilities’ Delaware division, Maryland division and Sandpiper Energy asset management agreements were sold to NJRES in October 2019.

• PESCO's producer services portfolio was sold to DFS in December 2019.

We received a total of $22.9 million in cash consideration from the aforementioned buyers that was inclusive of working capital of $8.0 million from UET. We recognized a pre-tax gain of $7.3 million in connection with the closing of these transactions during the fourth quarter of 2019. The final working capital true up associated with the sale of assets and contracts to UET will be finalized in the first quarter of 2020.

As a result of the sales agreements, 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. The assets and liabilities of PESCO are presented as current and noncurrent assets and liabilities of a business held for sale in the consolidated balance sheets.

Additionally, amounts for operating revenues and costs of sales which had previously been 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 all periods presented. We have recast these amounts because, upon completion of the sales transactions, we will continue to provide and receive services from the buyers.

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

	For the Year Ended December 31,
(in thousands)	2019			2018			2017
Operating revenues(1)	$	161,289		$	258,713		$	184,519
Cost of sales(1)	157,646			252,111			182,307
Other operating expenses	5,222			6,825			4,522
Operating loss	(1,579		)	(223		)	(2,310		)
Interest and other expense	315			297			253
Loss from Discontinued Operations before income taxes	(1,894		)	(520		)	(2,563		)
Gain on sale of Discontinued Operations	7,344			—			—
Income tax (benefit) / expense	1,439			(238		)	(361		)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	4,011		$	(282	)	$	(2,202	)

⁽¹⁾ Included in operating revenues and cost of sales for the years ended December 31, 2019, 2018 and 2017, is $19.8 million, $31.5 million and $16.6 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity that will continue with the buyers after the disposition of the assets of PESCO.

As a result of the disposition of the assets and contracts of PESCO, there were no assets or liabilities classified as held for sale at December 31, 2019. The assets and liabilities of the discontinued operations classified as held for sale in the consolidated balance sheet at December 31, 2018 include the following:

	As of
(in thousands)	December 31, 2018
Property, plant and equipment	$	1,242
Less: accumulated depreciation	(206		)
Net property, plant and equipment (1)	1,036
Current assets (2)	52,681
Deferred charges and other assets (1)	6,626
Assets of Discontinued Operations held for sale	$	60,343
Current liabilities (3)	$	48,672
Liabilities of Discontinued Operations held for sale	$	48,672
Net assets	$	11,671

⁽¹⁾ These balances have been combined within the consolidated balance sheets to arrive at noncurrent assets held for sale.

⁽²⁾ At December 31, 2018, current assets were primarily comprised of $31.1 million of accounts receivable, $13.1 million of derivative assets at fair value, $4.9 million of accrued revenue and $3.2 million of storage gas prepayments.

⁽³⁾ At December 31, 2018, current liabilities were primarily comprised of $31.1 million of accounts payable, $13.3 million of derivative liabilities at fair value and $2.7 million of other accrued liabilities.

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		2017
Depreciation and amortization	$	477		$	582	$	213
Property, plant and equipment expenditures	—			115		11,766
Deferred income taxes	(125		)	1,088		(1,515		)
Realized / (loss) gain on commodity contracts	(2,161		)	5,002		4,911

Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each expires on March 31, 2020. As a result of the sale of the assets of PESCO, effective October 1, 2019, these agreements are now managed by NJRES through the remainder of the contract term. 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 UET. Eastern Shore will continue to fulfill these arrangements throughout the remainder of their contractual term. These agreements currently have expiration dates of March 31, 2020 and November 30, 2021.

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 0	$ 0	$ 0
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	543	761	761
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 8	$ 8	$ 8

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Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2019

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,
	2019			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	340,857		$	343,313		$	323,972
Unregulated Energy	138,747			147,003			125,674
Total operating revenues, unaffiliated customers	$	479,604		$	490,316		$	449,646
Intersegment Revenues (1)
Regulated Energy	$	2,149		$	1,968		$	2,338
Unregulated Energy	15,403			14,902			14,402
Other businesses	528			652			774
Total intersegment revenues	$	18,080		$	17,522		$	17,514
Operating Income
Regulated Energy	$	86,584		$	79,215		$	74,584
Unregulated Energy	19,939			17,124			14,941
Other businesses and eliminations	(236		)	(1,496		)	205
Operating Income	106,287			94,843			89,730
Other expense, net	(1,830		)	(603		)	(2,204		)
Interest charges	22,224			16,146			12,530
Income from Continuing Operations before Income Taxes	$	82,233		$	78,094		$	74,996
Income Taxes on Continuing Operations	21,091			21,232			14,670
Income from Continuing Operations	61,142			56,862			60,326
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)
Gain on sale of Discontinued Operations, Net of tax	5,402			—			—
Net Income	$	65,153		$	56,580		$	58,124
Depreciation and Amortization
Regulated Energy	$	35,227		$	31,876		$	28,554
Unregulated Energy	10,129			8,263			7,741
Other businesses and eliminations	67			81			91
Total depreciation and amortization	$	45,423		$	40,220		$	36,386
Capital Expenditures
Regulated Energy	$	130,604		$	235,912		$	159,011
Unregulated Energy	60,034			38,585			14,424
Other businesses	8,348			8,364			5,902
Total capital expenditures	$	198,986		$	282,861		$	179,337

 

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

	As of December 31,
	2019		2018
Identifiable Assets (1)
Regulated Energy segment	$	1,434,066	$	1,345,805
Unregulated Energy segment (1)	296,810		245,702
Other businesses and eliminations	52,322		41,821
Total identifiable assets (1)	$	1,783,198	$	1,633,328

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Other Commitments and Contingencies

OTHER COMMITMENTS AND CONTINGENCIES

Natural Gas, Electric and Propane Supply

Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of the sale of PESCO's assets and contracts, effective October 1, 2019, these agreements are now managed by NJRES. See Note 4, Acquisitions and Divestitures for additional details regarding the sale of PESCO's assets and contracts.

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. Long-term agreements will commence on or about July 2020, and each has a 10-year term. Short-term agreements were entered for a one year term beginning July 2019 through July 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, 2019, 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. Eight Flags sells power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to our electric customers. Eight Flags also sells steam and heated water pursuant to a separate 20-year contract, to Rayonier 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	2020		2021-2022		2023-2024		Beyond 2024		Total
(in thousands)
Purchase Obligations	$	60,735	$	72,123	$	60,049	$	201,131	$	394,038

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, 2019 was $37.0 million. The aggregate amount guaranteed at December 31, 2019 was approximately $24.7 million, of which $16.3 million is related to the operations of PESCO, with the guarantees expiring on various dates through October 2020. The amounts related to PESCO will decrease as soon as those guarantees are transferred to the respective counterparties. See Note 4, Acquisitions and Divestitures, for additional details on the sale of assets and contracts for PESCO.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 13, Long-Term Debt, for further details).

As of December 31, 2019, we have issued letters of credit totaling approximately $5.4 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 August 22, 2020. There have been no draws on these letters of credit as of December 31, 2019. 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. The outstanding letters of credit as of December 31, 2019 also included those issued to support the operations of our divested

subsidiary, PESCO. As a result of the sale of assets and contracts for PESCO, letters of credit related to PESCO will be terminated early or expire without being renewed in 2020.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2019

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,
	2019		2018			2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	61,142	$	56,862		$	60,326
Income/(Loss) from Discontinued Operations	4,011		(282		)	(2,202		)
Net Income	$	65,153	$	56,580		$	58,124
Weighted average shares outstanding	16,398,443		16,369,616			16,336,789
Earnings Per Share from Continuing Operations	$	3.73	$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Basic Earnings Per Share	$	3.97	$	3.46		$	3.56
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,398,443		16,369,616			16,336,789
Effect of dilutive securities — Share-based compensation	50,043		50,254			46,563
Adjusted denominator — Diluted	16,448,486		16,419,870			16,383,352
Earnings Per Share from Continuing Operations	$	3.72	$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Diluted Earnings Per Share	$	3.96	$	3.45		$	3.55

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Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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	2.60%	2.90%	2.90%
Natural gas transmission | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.60%	2.70%	2.80%
Natural gas transmission | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.40%	2.30%	3.50%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	3.40%	3.40%	3.40%

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Other Commitments and Contingencies Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

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	2020		2021-2022		2023-2024		Beyond 2024		Total
(in thousands)
Purchase Obligations	$	60,735	$	72,123	$	60,049	$	201,131	$	394,038

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,337	$ 1,058
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 Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 65,153	$ 56,580	$ 58,124
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(20), $(22) and $(31), respectively	(57)	(55)	(46)
Net gain(loss), net of tax of $368, $(49), and $432, respectively	1,052	(108)	663
Cash Flow Hedges, net of tax:
Unrealized (loss) on commodity contract cash flow hedges, net of tax of $(176), $(555) and $(8), respectively	(434)	(1,371)	(11)
Total Other Comprehensive Income (Loss)	561	(1,534)	606
Comprehensive Income	$ 65,714	$ 55,046	$ 58,730

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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017:

	For the Year Ended December 31,
	2019			2018			2017
(in thousands)
Awards to non-employee directors	$	620		$	539		$	540
Awards to key employees	3,659			2,871			1,950
Total compensation expense	4,279			3,410			2,490
Less: tax benefit	(1,117		)	(934		)	(1,003		)
Share-based compensation amounts included in net income	$	3,162		$	2,476		$	1,487

Cash Proceeds Received and Tax Benefit from Share-based Payment Awards [Table Text Block]

The below table presents the number of shares withheld, amounts remitted to taxing authorities and the tax benefits associated with these obligations:

	For the Year Ended December 31,
	2019		2018		2017
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	7,635		16,918		10,269
Amounts remitted to tax authorities to satisfy obligations	$	692	$	1,210	$	692
Tax benefit associated with settlement of share based payments	$	—	$	—	$	349

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, 2017	132,642		$	59.31
Granted	49,494		67.76
Vested	(29,786	)	47.39
Vested - Accelerated pursuant to separation agreement	(16,676	)	75.78
Expired	(3,933	)	49.66
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

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Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 486.6	$ 327.2
Fair value of long-term debt	$ 505.0	$ 323.8

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Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
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%	21.00%	35.00%
Reconciliation of Effective Income Tax Rates Continuing Operations
Federal income tax expense (1)	[1]	$ 17,246	$ 16,491	$ 26,249
State income taxes, net of federal benefit		5,088	4,057	2,000
ESOP dividend deduction		(173)	(158)	(257)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0		(14,299)
Other		(1,070)	842	977
Income Tax Expense from Continuing Operations		$ 21,091	$ 21,232	$ 14,670
Effective Income Tax Rate for Continuing Operations (2)	[2]	25.65%	27.19%	19.56%

[1] Federal income taxes were calculated at 21 percent for 2019 and 2018 and 35 percent for 2017.

[2] The effective tax rate for 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA

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Income Taxes Federal Tax Reform (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	21.00%	35.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 0		$ (14,299)

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Investments - Schedule of Investment (Detail) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Investment [Line Items]
Investments, at fair value	$ 9,229	$ 6,711
Fair Value, Inputs, Level 1 [Member] | Investments in equity securities
Investment [Line Items]
Investments, at fair value	$ 27	$ 22

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Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2019, 2018 and 2017 were as follows:

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Cash paid for interest	$	22,611	$	16,741	$	12,420
Cash paid for income taxes, net of refunds	$	3,221	$	477	$	(4,114	)

Non-cash investing and financing activities during the years ended December 31, 2019, 2018, and 2017 were as follows: 

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	13,470	$	39,402	$	15,457
Common stock issued under the SICP	$	1,691	$	2,006	$	1,127
Capital lease obligation	$	—	$	1,310	$	2,070

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Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	751	792
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 4,300
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	$ 93.14	$ 75.70
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	$ 200

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Earnings Per Share

12 Months Ended

Dec. 31, 2019

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,
	2019		2018			2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	61,142	$	56,862		$	60,326
Income/(Loss) from Discontinued Operations	4,011		(282		)	(2,202		)
Net Income	$	65,153	$	56,580		$	58,124
Weighted average shares outstanding	16,398,443		16,369,616			16,336,789
Earnings Per Share from Continuing Operations	$	3.73	$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Basic Earnings Per Share	$	3.97	$	3.46		$	3.56
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,398,443		16,369,616			16,336,789
Effect of dilutive securities — Share-based compensation	50,043		50,254			46,563
Adjusted denominator — Diluted	16,448,486		16,419,870			16,383,352
Earnings Per Share from Continuing Operations	$	3.72	$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Diluted Earnings Per Share	$	3.96	$	3.45		$	3.55

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Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2019 USD ($)
Chesapeake Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	$ 115	[1]
2018	368	[1]
2019	106	[1]
2020	927	[1]
2021	111	[1]
Years 2022 through 2026	2,300	[1]
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	3,281	[1]
2018	3,348	[1]
2019	3,424	[1]
2020	3,498	[1]
2021	3,549	[1]
Years 2022 through 2026	18,429	[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	144	[2]
Years 2022 through 2026	748	[2]
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	90	[2]
2018	87	[2]
2019	85	[2]
2020	67	[2]
2021	64	[2]
Years 2022 through 2026	264	[2]
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	86	[2]
2018	90	[2]
2019	91	[2]
2020	79	[2]
2021	80	[2]
Years 2022 through 2026	$ 389	[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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Quarterly Financial Data

12 Months Ended

Dec. 31, 2019

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)
2019 (1)
Operating Revenues	$	160,464		$	94,541		$	92,626		$	131,973
Operating Income	$	44,123		$	18,164		$	14,358		$	29,642
Net Income:
Income from Continuing Operations	$	28,814		$	8,913		$	6,246		$	17,169
Loss from Discontinued Operations, Net of Tax	(149		)	(609		)	(624		)	(9		)
Gain on sale of Discontinued Operations, Net of Tax	—			—			—			5,402
	$	28,665		$	8,304		$	5,622		$	22,562
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
	$	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
	$	1.74		$	0.50		$	0.34		$	1.37
2018 (1)
Operating Revenues	$	168,831		$	93,872		$	93,400		$	134,214
Operating Income	$	40,853		$	12,238		$	12,879		$	28,873
Net Income:
Income from Continuing Operations	$	27,271		$	5,705		$	6,090		$	17,796
Income/(Loss) from Discontinued Operations	(415		)	680			(552		)	5
	$	26,856		$	6,385		$	5,538		$	17,801
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.67		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.03		)	0.04			(0.03		)	—
	$	1.64		$	0.39		$	0.34		$	1.09
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.66		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.02		)	0.04			(0.04		)	—
	$	1.64		$	0.39		$	0.33		$	1.09

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

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Acquisitions Acquisition (Tables)

12 Months Ended

Dec. 31, 2019

Acquisition Performance [Abstract]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

For the year ended December 31, 2019, these acquisitions generated the following operating revenue and income:

	For the Year Ended
	December 31, 2019
	Operating Revenues		Operating Income
(in thousands)
Marlin Gas Services	$	5,702	$	1,500
Ohl propane acquisition	$	1,662	$	385
Boulden acquisition	$	550	$	239

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Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2019, 2018 and 2017 were as follows:

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Cash paid for interest	$	22,611	$	16,741	$	12,420
Cash paid for income taxes, net of refunds	$	3,221	$	477	$	(4,114	)

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2019, 2018, and 2017 were as follows: 

	For the Year Ended December 31,
	2019		2018		2017
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	13,470	$	39,402	$	15,457
Common stock issued under the SICP	$	1,691	$	2,006	$	1,127
Capital lease obligation	$	—	$	1,310	$	2,070

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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, 2019	Dec. 31, 2018	Dec. 31, 2017
Amortization of defined benefit pension and postretirement plan items:
Income tax benefit		$ (21,091)	$ (21,232)	$ (14,670)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of defined benefit pension and postretirement plan items:
Net of tax		728	(2,198)	(166)
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]	(2,600)	(579)	(636)
Total before income taxes		(2,523)	(502)	(559)
Income tax benefit	[2]	656	63	223
Net of tax		(1,867)	(439)	(336)
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		3,623	(2,460)	329
Income tax benefit	[2]	(1,028)	701	(159)
Net of tax		2,595	(1,759)	170
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]	1,520	(647)	1,607
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]	2,096	(2,010)	(456)
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]	$ 7	$ 197	$ (822)

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

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

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Employee Benefit Plans - 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, 2019 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	$ 1.7

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Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2019

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, our intrastate pipeline subsidiary, is subject to regulation (excluding cost of service) by the Florida PSC.

Delaware

Effect of the TCJA on Customers: In January 2019, the Delaware PSC approved the as-filed Delaware Division Delivery Service Rates reflecting the impact of the TCJA.  The new rates went into effect in March 2019. The refunds, which were retroactive to February 2018, were completed prior to the mandated deadline of June 2019.  The order also provided for a line item billing credit that went into effect in April 2019, for the return of the excess accumulated deferred income taxes ("ADIT"). 

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 propose to acquire each CGS one at a time and to pay replacement cost for each CGS system. In addition, we are requesting 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. In September 2019, the Delaware PSC issued an order to open a docket for the purpose of reviewing our application and to conduct evidentiary hearings on the matter. We are currently responding to discovery requests and an evidentiary hearing is scheduled for the second quarter of 2020.

Maryland

Approval of the Elkton Gas Company Acquisition: In December 2019, we entered into an agreement with SJI to acquire its subsidiary, Elkton Gas Company, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. Upon completion of the transaction, Elkton Gas Company will become our wholly-owned subsidiary. The acquisition, which is expected to close in the second half of 2020, is subject to approval by the Maryland PSC. Elkton Gas Company's territory is contiguous to our franchised service territory in Cecil County, Maryland and it will continue to operate out of its existing office with the same local personnel.

Florida

Electric Limited Proceeding-Storm Recovery (Pre-Hurricane Michael): In February 2018, FPU filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of the storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and, at the time of filing the petition, had a deficit of $0.8 million. This matter went to hearing in December 2018 and was subsequently approved at the March 2019 Agenda with the Final Order issued on March 25, 2019. FPU received approval to begin a surcharge on customer bills for two years beginning in April 2019, to recover storm-related costs and replenish the storm reserve.

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, amounts currently being reviewed by the Florida PSC for regulatory asset treatment have been recorded as receivables and other deferred charges. In December 2018 and January 2019, we executed two 13-month unsecured term loans as temporary financing for the Hurricane Michael-related expenditures, each in the amount of $30.0 million. The interest cost associated with these loans is the one-month LIBOR rate plus 75 basis points. In December 2019, we utilized the proceeds from the issuance of uncollateralized senior notes to repay the term notes issued in December 2018.

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 the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC in November 2019 and temporary rate increases were implemented effective January 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 2020.

Effect of the TCJA on Customers: In February 2018, the Florida PSC opened dockets to consider the impacts associated with the TCJA. In May 2018, FPU’s natural gas divisions filed petitions and supporting testimony regarding the disposition of the related impacts of the TCJA. Hearings on this matter took place in November 2018, and the staff's recommendation was approved by the Florida PSC at the February 2019 Agenda and final orders were issued on February 25, 2019. Staff’s recommendations are summarized in the table at the end of this section.

Electric Depreciation Study: In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The new rates will be effective January 1, 2020. The petition has not been scheduled for approval by the Florida PSC.

Natural Gas Depreciation Study: In March 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated natural gas depreciation rates. The petition was approved by the Florida PSC at Agenda on October 3, 2019. The new rates were effective retroactive to January 1, 2019, and are expected to decrease depreciation expense by approximately $0.9 million annually.

Auburndale Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with the Florida Division of Chesapeake Utilities. Peninsula Pipeline will purchase an existing pipeline owned by the Florida Division of Chesapeake Utilities and Calpine and construct pipeline facilities in Polk County, Florida. Peninsula Pipeline will provide transportation service to the Florida Division of Chesapeake Utilities increasing both delivery capacity and downstream pressure as well as introducing a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. The petition was approved by the Florida PSC at the August 6, 2019 Agenda. The project was placed in service in the third quarter of 2019.

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.

Callahan Pipeline Project, Nassau County: In July 2019, Peninsula Pipeline filed a petition for approval of the firm transportation service agreement with FPU and the restructuring of the business and operational agreements between Peoples Gas, FPU and Seacoast Gas Transmission. Peninsula Pipeline will construct and jointly own 26 miles of 16 inch steel pipeline with Seacoast Gas Transmission and interconnect to the Cypress Pipeline interstate system in western Nassau County. The Callahan pipeline will terminate into the existing Peninsula Pipeline-Peoples Gas jointly owned pipeline, which serves Amelia Island and the Peoples Gas distribution system. Callahan pipeline will enhance FPU’s ability to expand service into Nassau County and will enable Peoples Gas to enhance its system pressure and reliability of its service in Duval County. This petition was approved by the Florida PSC at the December 10, 2019 Agenda. The project is expected to be placed in-service during the third quarter of 2020.

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. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021.

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 November 2019 after the end of 30 days of no opposing comments.

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)	$12,847	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)	$4,087	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)	$3,765	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)	$8,304	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)	$19,218	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$294	Same treatment on a net basis as Chesapeake 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 Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,769	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its 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.

Regulatory Assets and Liabilities

At December 31, 2019 and 2018, 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,
	2019		2018
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	5,144	$	4,631
Under-recovered GRIP revenue (2)	—		165
Deferred postretirement benefits (3)	16,311		15,517
Deferred conversion and development costs (1)	20,881		16,727
Environmental regulatory assets and expenditures (4)	2,241		2,731
Acquisition adjustment (5)	30,329		33,255
Loss on reacquired debt (6)	869		942
Other	2,776		3,250
Total Regulatory Assets	$	78,551	$	77,218
Regulatory Liabilities
Self-insurance (7)	$	873	$	947
Over-recovered purchased fuel and conservation cost recovery (1)	2,724		5,856
Over-recovered GRIP revenue (2)	2,668		1,563
Storm reserve (7)	1,437		677
Accrued asset removal cost (8)	36,767		42,401
Deferred income taxes due to rate change (9)	89,191		91,236
Other	75		242
Total Regulatory Liabilities	$	133,735	$	142,922

⁽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. In 2019, we recorded as a regulatory asset 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 have self-insurance and storm reserves in our Florida 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.

⁽⁸⁾ See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

⁽⁹⁾ 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. 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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Other Commitments and Contingencies Purchase Obligations (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 60,735
Purchase Obligation, Due in Second and Third Year	72,123
Purchase Obligation, Due in Fourth and Fifth Year	60,049
Purchase Obligation, Due after Fifth Year	201,131
Purchase Obligation	$ 394,038

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Leases

12 Months Ended

Dec. 31, 2019

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, 2019, 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, 2019, 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	2019		2018
Operating lease cost (1)	Operations expense	$	2,577	$	3,339
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	650		1,451
Interest on lease liabilities	Interest expense	5		49
Net lease cost		$	3,232	$	4,839

⁽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, 2019:

(in thousands)	Balance sheet classification	Amount
Assets
Operating lease assets	Operating lease right-of-use assets	$	11,563
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	1,705
Noncurrent
Operating lease liabilities	Operating lease - liabilities	9,896
Total lease liabilities		$	11,601

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

	December 31, 2019
Weighted-average remaining lease term (in years)
Operating leases	8.88
Weighted-average discount rate
Operating leases	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 as of December 31, 2019 and 2018:

	Year Ended December 31,
(in thousands)	2019		2018
Operating cash flows from operating leases	$	2,230	$	2,759
Operating cash flows from finance leases	$	5	$	49
Financing cash flows from finance leases	$	650	$	1,451

The following table presents the future undiscounted maturities of our operating leases at December 31, 2019 and for each of the next five years and thereafter:

(in thousands)	Operating Leases (1)
2020	$	2,104
2021	1,866
2022	1,716
2023	1,719
2024	1,463
Thereafter	4,916
Total lease payments	13,784
Less: Interest	2,183
Present value of lease liabilities	$	11,601

⁽¹⁾  Operating lease payments include $3.7 million related to options to extend lease terms that are reasonably certain of being exercised.

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Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2019	Dec. 31, 2018
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 78,551	$ 77,218
Regulatory Liabilities		133,735	142,922
Self Insured Liabilities [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	873	947
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		2,724	5,856
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	1,437	677
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	36,767	42,401
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	89,191	91,236
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		75	242
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[4]	5,144	4,631
Under-recovered GRIP Revenue [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[5]	0	165
Regulatory Liabilities	[5]	2,668	1,563
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	16,311	15,517
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[4]	20,881	16,727
Environmental Regulatory Assets And Expenditures [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	2,241	2,731
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[8]	30,329	33,255
Loss on Reacquired Debt [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	869	942
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		2,776	$ 3,250
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34,200
Regulatory Liabilities		19,218
Indiantown Gas Company
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		$ 700

[1] We have self-insurance and storm reserves in our Florida 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] 9) 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. 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. In 2019, we recorded as a regulatory asset 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.

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018 was as follows:

	As of December 31,
(in thousands)	2019		2018
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy(2)
Mid-Atlantic Propane Operations(3)	13,299		2,147
Florida Propane Operations	1,188		1,188
Aspire Energy	10,120		10,120
Marlin Gas Services	4,708		4,760
Total Goodwill	$	32,668	$	21,568

⁽¹⁾ Florida Natural Gas Distribution includes Chesapeake Utilities' Central Florida Gas division, FPU and FPU's Indiantown and Fort Meade divisions.

⁽²⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. The goodwill balance for PESCO is reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018.

⁽³⁾ Mid-Atlantic Propane Operations goodwill balance includes $11.2 million recognized as a result of the purchase of the operating assets of Boulden in December 2019.

The annual impairment testing for 2019 and 2018 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2019 and 2018 are as follows:

	As of December 31,
	2019				2018
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer relationships (1)	$	9,391	$	3,463	$	4,801	$	3,066
Non-Compete agreements (1) (2)	2,252		451		1,793		202
Patents	452		118		452		—
Other	270		204		270		198
Total	$	12,365	$	4,236	$	7,316	$	3,466

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

⁽²⁾As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. Intangible assets for PESCO are reflected as assets held-for-sale in the consolidated balance sheet as of December 31, 2018 and amortization is reflected as discontinued operations in the consolidated statements of income.

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, 2019 was $0.8 million and $0.4 million for both years ended December 31, 2018 and 2017. Amortization expense of intangible assets is expected to be $1.2 million for the years 2020 and 2021, $0.9 million for the year 2022 and $0.8 million for the years 2023 and 2024.

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019 and 2018, respectively:

			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	$	—

			Fair Value Measurements Using:
As of December 31, 2018	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets (1)	82		—		82		—
Total assets	$	6,793	$	6,025	$	82	$	686
Liabilities:
Derivative liabilities (1)	$	1,604	$	—	$	1,604	$	—

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, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Beginning Balance	$	686		$	648
Purchases and adjustments	131			68
Transfers/disbursements	(29		)	(41		)
Investment income	15			11
Ending Balance	$	803		$	686

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,990		$	7,986
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	2,000			4,000
5.93% note, due October 31, 2023	12,000			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			7,000
3.73% note, due December 16, 2028	18,000			20,000
3.88% note, due May 15, 2029	50,000			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			—
2.98% note, due December 20, 2034	70,000			—
Term Note due January 21, 2020	—			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligations	—			1,310
Less: debt issuance costs	(822		)	(567		)
Total long-term debt	485,768			327,955
Less: current maturities	(45,600		)	(11,935		)
Total long-term debt, net of current maturities	$	440,168		$	316,020

Schedule of Maturities of Long-term Debt [Table Text Block]

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

Year	2020		2021		2022		2023		2024		Thereafter		Total
(in thousands)
Payments	$	45,600	$	13,600	$	25,100	$	20,600	$	17,600	$	364,100	$	486,600

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, 2019:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	220,000	$	(170,000	)	$	—	$	50,000
MetLife Shelf Agreement	150,000		—			—		150,000
NYL Shelf Agreement (2)	150,000		(100,000		)	—		50,000
Total	$	520,000	$	(270,000	)	$	—	$	250,000

⁽¹⁾ As described above, in January 2020, we requested and Prudential accepted our request to purchase $50.0 million of our unsecured debt.

⁽²⁾ As described above, in February 2020, we requested and NYL accepted our request to purchase $40.0 million of our unsecured debt.

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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2019

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, 2019, 2018 and 2017:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2019		2018		2017		2019		2018		2017
Asset Category
Equity securities	—	%	49	%	53	%	53	%	50	%	55	%
Debt securities	92	%	41	%	38	%	37	%	41	%	37	%
Other	8	%	10	%	9	%	10	%	9	%	8	%
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 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, 2019 and 2018, 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, 2019								At December 31, 2018
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)	$	3,553	$	—	$	—	$	3,553	$	3,399	$	—	$	—	$	3,399
U.S. Mid Cap (1)	1,604		—		—		1,604		1,478		—		—		1,478
U.S. Small Cap (1)	726		—		—		726		670		—		—		670
International (2)	9,855		—		—		9,855		9,226		—		—		9,226
Alternative Strategies (3)	4,739		—		—		4,739		5,726		—		—		5,726
	20,477		—		—		20,477		20,499		—		—		20,499
Mutual Funds - Debt securities
Fixed income (4)	19,220		—		—		19,220		18,630		—		—		18,630
High Yield (4)	2,476		—		—		2,476		2,818		—		—		2,818
	21,696		—		—		21,696		21,448		—		—		21,448
Mutual Funds - Other
Commodities (5)	1,708		—		—		1,708		1,902		—		—		1,902
Real Estate (6)	2,288		—		—		2,288		2,216		—		—		2,216
Guaranteed deposit (7)	—		—		1,147		1,147		—		—		627		627
	3,996		—		1,147		5,143		4,118		—		627		4,745
Total Pension Plan Assets in fair value hierarchy	$	46,169	$	—	$	1,147	47,316		$	46,065	$	—	$	627	46,692
Investments measured at net asset value (8)							7,017								5,558
Total Pension Plan Assets							$	54,333							$	52,250

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, 2019 and 2018:

	For the Year Ended December 31,
	2019			2018
(in thousands)
Balance, beginning of year	$	627		$	436
Purchases	2,274			1,674
Transfers in	3,090			2,375
Disbursements	(4,907		)	(3,872		)
Investment income	63			14
Balance, end of year	$	1,147		$	627

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, 2019:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(447	)	$	—		$	(447	)
Net loss (gain)	2,241		19,339		575		604			(32		)	22,727
Total	$	2,241	$	19,339	$	575	$	157		$	(32	)	$	22,280
Accumulated other comprehensive loss (gain) pre-tax(1)	$	2,241	$	3,674	$	575	$	157		$	(6	)	$	6,641
Post-merger regulatory asset	—		15,665		—		—			(26		)	15,639
Subtotal	2,241		19,339		575		157			(32		)	22,280
Pre-merger regulatory asset	—		—		—		—			6			6
Total unrecognized cost	$	2,241	$	19,339	$	575	$	157		$	(26	)	$	22,286

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2019 is net of income tax benefits of $1.7 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)
2020	$	115	$	3,281	$	151	$	90	$	86
2021	$	368	$	3,348	$	150	$	87	$	90
2022	$	106	$	3,424	$	148	$	85	$	91
2023	$	927	$	3,498	$	146	$	67	$	79
2024	$	111	$	3,549	$	144	$	64	$	80
Years 2025 through 2029	$	2,300	$	18,429	$	748	$	264	$	389

⁽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, 2019 and 2018 and the net periodic cost for the years ended December 31, 2019, 2018 and 2017 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2019			2018			2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	10,712		$	11,443		$	59,377		$	64,664		$	2,285		$	2,428
Interest cost	375			384			2,452			2,339			74			83
Actuarial loss (gain)	1,443			(610		)	6,508			(4,739		)	159			(74		)
Effect of settlement	(5,833		)	—			—			—			—			—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Benefit obligation — end of year	6,214			10,712			65,304			59,377			2,157			2,285
Change in plan assets:
Fair value of plan assets — beginning of year	8,649			9,350			43,601			48,396			—			—
Actual return on plan assets	1,180			(647		)	7,978			(3,113		)	—			—
Employer contributions	1,117			451			1,157			1,205			361			152
Effect of settlement	(5,833		)	—			—			—						—
Benefits paid	(483		)	(505		)	(3,033		)	(2,887		)	(361		)	(152		)
Fair value of plan assets — end of year	4,630			8,649			49,703			43,601			—			—
Reconciliation:
Funded status	(1,584		)	(2,063		)	(15,601		)	(15,776		)	(2,157		)	(2,285		)
Accrued pension cost	$	(1,584	)	$	(2,063	)	$	(15,601	)	$	(15,776	)	$	(2,157	)	$	(2,285	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%	3.00		%	4.00		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%	—		%	—		%

Component of Net Periodic Pension Cost (Benefit)

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2019 (1)			2018			2017			2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic pension cost:
Interest cost	$	375		$	384		$	402		$	2,452		$	2,339		$	2,482		$	74		$	83		$	89
Expected return on assets	(487		)	(542		)	(495		)	(2,770		)	(3,091		)	(2,779		)	—			—			—
Amortization of actuarial loss	391			343			399			505			404			513			85			101			87
Settlement expense	1,982			—			—			—			—			—			58			—			—
Net periodic pension cost	2,261			185			306			187			(348		)	216			217			184			176
Amortization of pre-merger regulatory asset	—			—			—			543			761			761			—			—			—
Total periodic cost	$	2,261		$	185		$	306		$	730		$	413		$	977		$	217		$	184		$	176
Assumptions:
Discount rate	3.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	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, 2019 and 2018:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2019			2018			2019			2018
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,002		$	1,128		$	1,187		$	1,287
Interest cost	39			38			48			47
Plan participants contributions	149			136			38			41
Actuarial loss (gain)	73			(131		)	47			(89		)
Benefits paid	(163		)	(169		)	(96		)	(99		)
Benefit obligation — end of year	1,100			1,002			1,224			1,187
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	14			33			58			58
Plan participants contributions	149			136			38			41
Benefits paid	(163		)	(169		)	(96		)	(99		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,100		)	(1,002		)	(1,224		)	(1,187		)
Accrued postretirement cost	$	(1,100	)	$	(1,002	)	$	(1,224	)	$	(1,187	)
Assumptions:
Discount rate	3.00		%	4.00		%	3.25		%	4.25		%

⁽¹⁾ The Chesapeake Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for 2019, 2018, and 2017 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2019			2018			2017			2019			2018			2017
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	39		$	38		$	41		$	48		$	47		$	50
Amortization of actuarial loss	46			58			53			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	8			19			17			48			47			50
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost	$	8		$	19		$	17		$	56		$	55		$	58
Assumptions
Discount rate	4.00		%	3.50		%	3.75		%	4.25		%	3.75		%	4.00		%

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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, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018		Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018		Dec. 31, 2017
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		$ 131,973	$ 92,626	$ 94,541	$ 160,464	$ 134,214		$ 93,400	$ 93,872	$ 168,831	$ 479,604	$ 490,316		$ 449,646
Intersegment Revenues (1)
Total intersegment revenues		131,973	92,626	94,541	160,464	134,214		93,400	93,872	168,831	479,604	490,316		449,646
Operating Income
Operating Income		29,642	14,358	18,164	44,123	28,873		12,879	12,238	40,853	106,287	94,843		89,730
Other income											(1,830)	(603)		(2,204)
Interest charges											22,224	16,146		12,530
Income Before Income taxes											82,233	78,094		74,996
Income Taxes on Continuing Operations											21,091	21,232		14,670
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent		17,169	6,246	8,913	28,814	17,796		6,090	5,705	27,271	61,142	56,862		60,326
Net Income		22,562	5,622	8,304	28,665	17,801		5,538	6,385	26,856	65,153	56,580		58,124
Income (Loss) from Discontinued Operations, Net of Tax, Attributable to Parent		(9)	(624)	(609)	(149)	5		$ (552)	$ 680	$ (415)	(1,391)	(282)		(2,202)
Discontinued Operation, Gain (Loss) on Disposal of Discontinued Operation, Net of Tax		5,402	$ 0	$ 0	$ 0						5,402
Depreciation and Amortization
Total depreciation and amortization											45,423	40,220		36,386
Identifiable Assets
Total identifiable assets		1,783,198				1,693,671					1,783,198	1,693,671
Regulated Energy
Operating Income
Operating Income											86,584	79,215		74,584
Depreciation and Amortization
Total depreciation and amortization											35,227	31,876		28,554
Payments to Acquire Productive Assets											130,604	235,912		159,011
Identifiable Assets
Total identifiable assets		1,434,066				1,345,805					1,434,066	1,345,805
Unregulated Energy
Operating Income
Operating Income											19,939	17,124		14,941
Depreciation and Amortization
Total depreciation and amortization											10,129	8,263		7,741
Payments to Acquire Productive Assets											60,034	38,585		14,424
Identifiable Assets
Total identifiable assets		296,810				245,702	[1]				296,810	245,702	[1]
Other
Operating Income
Operating Income											(236)	(1,496)		205
Depreciation and Amortization
Payments to Acquire Productive Assets											8,348	8,364		5,902
Identifiable Assets
Total identifiable assets		$ 52,322				41,821					52,322	41,821
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization											67	81		91
Total for Segments [Member]
Depreciation and Amortization
Payments to Acquire Productive Assets											198,986	282,861		179,337
Continuing Operations [Member]
Identifiable Assets
Total identifiable assets	[1]					$ 1,633,328						1,633,328
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues											479,604	490,316		449,646
Intersegment Revenues (1)
Total intersegment revenues											479,604	490,316		449,646
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues											340,857	343,313		323,972
Intersegment Revenues (1)
Total intersegment revenues											340,857	343,313		323,972
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues											138,747	147,003		125,674
Intersegment Revenues (1)
Total intersegment revenues											138,747	147,003		125,674
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[2]										18,080	17,522		17,514
Intersegment Revenues (1)
Total intersegment revenues	[2]										18,080	17,522		17,514
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[2]										2,149	1,968		2,338
Intersegment Revenues (1)
Total intersegment revenues	[2]										2,149	1,968		2,338
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[2]										15,403	14,902		14,402
Intersegment Revenues (1)
Total intersegment revenues	[2]										15,403	14,902		14,402
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[2]										528	652		774
Intersegment Revenues (1)
Total intersegment revenues	[2]										$ 528	$ 652		$ 774

[1] ⁽¹⁾ 2018 balance excludes assets held for sale related to the sale of assets and contracts for PESCO.

[2] All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.

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Leases Lease Cost Additional (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Leases [Abstract]
Operating Lease, Cost	$ 2,577	$ 3,339
Finance Lease, Right-of-Use Asset, Amortization	650	1,451
Finance Lease, Interest Expense	5	49
Lease, Cost	$ 3,232	$ 4,839

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Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Line of Credit Facility [Line Items]
Long-term Debt	$ (486,600)	$ (327,200)
Debt Instrument, Unused Borrowing Capacity, Amount	250,000
Prudential [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	150,000
Long-term Debt	(170,000)
Debt Instrument, Unused Borrowing Capacity, Amount	50,000
MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	150,000
New York Life [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	100,000
Long-term Debt	(100,000)
Debt Instrument, Unused Borrowing Capacity, Amount	50,000
Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(270,000)
Unsecured Debt [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (50,000)
Debt Instrument, Interest Rate, Stated Percentage	3.00%
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]
Long-term Debt	$ 0
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (70,000)	$ (70,000)
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 on Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (100,000)
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Maximum [Member] | Prudential [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	$ 220,000
Maximum [Member] | MetLife [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	150,000
Maximum [Member] | New York Life [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	150,000
Maximum [Member] | Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Debt Instrument, Face Amount	$ 520,000

XML

Acquisitions Divestitures (Details) $ in Thousands		12 Months Ended
		Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Number of Transactions		4
Accrued Revenue		$ 20,846	$ 22,640
Proceeds from the sale of discontinued operations		22,871
Depreciation and amortization		477	582	$ 213
Property, plant and equipment	[1]		1,036
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment		(336,876)	(294,089)
Disposal Group, Including Discontinued Operation, Property, Plant and Equipment, Noncurrent			1,242
Disposal Group, Including Discontinued Operation, Revenue	[2]	161,289	258,713	184,519
Disposal Group, Including Discontinued Operation, Costs of Goods Sold	[2]	157,646	252,111	182,307
Disposal Group, Including Discontinued Operation, Operating Expense		5,222	6,825	4,522
Disposal Group, Including Discontinued Operation, Operating Income (Loss)		(1,579)	(223)	(2,310)
Disposal Group, Including Discontinued Operation, Interest Expense		315	297	253
Discontinued Operation, Income (Loss) from Discontinued Operation, before Income Tax		(1,894)	(520)	(2,563)
Discontinued Operation, Gain (Loss) from Disposal of Discontinued Operation, before Income Tax		7,344	0	0
Discontinued Operation, Tax Effect of Discontinued Operation		1,439	238	361
Gain Loss From Discontinued Operations			(282)	(2,202)
Disposal Group, Including Discontinued Operation, Assets, Current		134,826	191,537
Disposal Group, Including Discontinued Operation, Other Assets	[1]		6,626
Disposal Group, Including Discontinued Operation, Assets			60,343
Disposal Group, Including Discontinued Operation, Liabilities	[3]		48,672
Deferred Income Tax Expense (Benefit)	[4]	23,901	20,650	12,085
Discontinued Operations, Disposed of by Sale [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Gain Loss From Discontinued Operations		4,011
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			115	11,766
Accumulated Depreciation, Depletion and Amortization, Property, Plant, and Equipment			(206)
Disposal Group, Including Discontinued Operation, Assets, Current	[5]		52,681
Deferred Income Tax Expense (Benefit)		(125)	1,088	(1,515)
Settlement Gain		(2,161)	5,002	4,911
Net Assets			11,671
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	$ 16,600
Accounts Receivable, before Allowance for Credit Loss, Current			31,100
Derivative Asset			13,100
Accrued Revenue			4,900
Prepaid Expense			3,200
Accounts Payable			31,100
Derivative Liability			13,300
Other Liabilities			$ 2,700

[1] These balances have been combined within the consolidated balance sheets to arrive at noncurrent assets held for sale.

[2] ) Included in operating revenues and cost of sales for the years ended December 31, 2019, 2018 and 2017, is $19.8 million, $31.5 million and $16.6 million respectively, representing amounts which had been previously eliminated in consolidation related to intercompany activity that will continue with the buyers after the disposition of the assets of PESCO.

[3] ⁽³⁾ At December 31, 2018, current liabilities were primarily comprised of $31.1 million of accounts payable, $13.3 million of derivative liabilities at fair value and $2.7 million of other accrued liabilities.

[4] ⁽¹⁾ Includes $4.7 million, $3.5 million, and $0.9 million of deferred state income taxes for the years 2019, 2018 and 2017, respectively.

[5] At December 31, 2018, current assets were primarily comprised of $31.1 million of accounts receivable, $13.1 million of derivative assets at fair value, $4.9 million of accrued revenue and $3.2 million of storage gas prepayments