10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended: December 31, 2018

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

Commission File Number: 001-11590

CHESAPEAKEUTILITIESCORPORATION

(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	Name of each exchange on which registered
Common Stock—par value per share $0.4867	New York Stock Exchange, Inc.

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    Yes ý    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 ý

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 ý    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 ý    No ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.  ý

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	ý	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 ý

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2018, the last business day of its most recently completed second fiscal quarter, based on the last sale price on that date, as reported by the New York Stock Exchange, was approximately $1.3 billion.

The number of shares of Chesapeake Utilities Corporation's common stock outstanding as of February 15, 2019 was 16,378,821.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the Proxy Statement for the 2019 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, 2018.

CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2018

TABLE OF CONTENTS

	Page
Part I	1
Item 1. Business	2
Item 1A. Risk Factors	11
Item 1B. Unresolved Staff Comments	17
Item 2. Properties	17
Item 3. Legal Proceedings	18
Item 4. Mine Safety Disclosures	18
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	21
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	23
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	45
Item 8. Financial Statements and Supplementary Data	47
Item 9. Changes In and Disagreements With Accountants on Accounting and Financial Disclosure	96
Item 9A. Controls and Procedures	96
Item 9B. Other Information	97
Part III	97
Item 10. Directors, Executive Officers of the Registrant and Corporate Governance	97
Item 11. Executive Compensation	97
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	97
Item 13. Certain Relationships and Related Transactions, and Director Independence	97
Item 14. Principal Accounting Fees and Services	97
Part IV	97
Item 15. Exhibits, Financial Statement Schedules	98
Item 16. Form 10-K Summary	102
Signatures	102

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

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

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

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

NYL: New York Life 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

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: 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

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 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 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;

• the weather and other natural phenomena, including the economic, operational and other 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;

• 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;

• the results of financing efforts, 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 2018 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 and in Florida, Pennsylvania 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;

•

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, 2018 and total assets as of December 31, 2018, for the 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	$	11,390	$	211,458
Central Florida Gas and FPU	Florida	11,754		312,769
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	17,460		262,918
Peninsula Pipeline	Florida	4,303		20,493
Electric Distribution
FPU	Florida	2,249		123,863
Total Regulated Energy		$	47,156	$	931,501

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 2018 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, 2018:

	Delmarva Natural Gas Distribution				Florida Natural Gas Distribution (2)				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	70,466	60	%	$	35,420	34	%	$	44,788		56	%
Commercial	36,916		32	%	33,229		31	%	39,442			49	%
Industrial	8,289		7	%	33,207		31	%	1,543			2	%
Other (1)	928		1	%	4,602		4	%	(5,970		)	(7	)%
Total Operating Revenues	$	116,599	100	%	$	106,458	100	%	$	79,803		100	%
Volumes (in Dts for natural gas/KW Hours for electric)
Residential	4,142,567		31	%	1,762,852		5	%	307,269			49	%
Commercial	3,792,220		28	%	6,441,806		18	%	302,687			48	%
Industrial	5,549,387		40	%	24,759,334		70	%	15,160			2	%
Other	80,254		1	%	2,338,815		7	%	7,402			1	%
Total Volumes	13,564,428		100	%	35,302,807		100	%	632,518			100	%
Average Number of Customers (3)
Residential	71,322		91	%	72,151		90	%	24,686			77	%
Commercial	6,979		9	%	5,434		7	%	7,497			23	%
Industrial	157		<1%		2,328		3	%	2			<1%
Other	5		<1%		11		<1%		—			—	%
Total Average Number of Customers	78,463		100	%	79,924		100	%	32,185			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, 2018.

Chesapeake Utilities Corporation 2018 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, 2018, and contracted firm transportation capacity, by customer type, as well as design day capacity at December 31, 2018:

	Eastern Shore					Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated (1)	$	19,725		31	%	$	9,478	80	%
Local distribution companies - non-affiliated	23,975			37	%	840		7	%
Commercial and industrial - affiliated	—			—	%	1,120		9	%
Commercial and industrial - non-affiliated	21,748			34	%	490		4	%
Other (2)	(1,200		)	(2	)%	—		—	%
Total Operating Revenues	$	64,248		100	%	$	11,928	100	%
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	122,652			42	%	143,500		93	%
Local distribution companies - non-affiliated	76,619			26	%	4,825		3	%
Commercial and industrial - affiliated	—			—	%	1,500		1	%
Commercial and industrial - non-affiliated	95,648			32	%	5,100		3	%
Total Contracted firm transportation capacity	294,919			100	%	154,925		100	%
Design day capacity (in Dts/d)	294,919			100	%	154,925		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 and reserve for rate case refund.

Regulatory Overview

The following table highlights key regulatory information for each of our principal Regulated Energy operations. 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. 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.

	Natural Gas Distribution					Electric Distribution	Natural Gas Transmission
	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	5/1/2018(7)	12/01/2018	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	N/A(7)	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	Reserved	Refunded	Refunded	Reserved	Reserved	Reserved	Refunded

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

Chesapeake Utilities Corporation 2018 Form 10-K Page 4

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

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

⁽⁴⁾ Allowed after-tax return on equity.

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

⁽⁶⁾ The terms of the settlement agreement for the FPU electric division limited proceeding with the Florida PSC prescribed an authorized return on equity range of 9.25 to 11.25 percent, with a mid-point of 10.25 percent. The FPU electric division cannot file for a base rate increase prior to December 2019, unless its allowed return on equity is below the authorized range and it experiences an unanticipated and unforeseen event that impacts the annual revenue requirement in excess of $800,000 within any contiguous four-month period.

⁽⁷⁾ The Maryland PSC approved a rate reduction for Maryland division effective May 1, 2018, related to the enactment of the TJCA.

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

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 Florida electric distribution operation's limited proceeding.

Operation(s)/Division(s)	Jurisdiction	Infrastructure mechanism	Revenue normalization
Delaware division	Delaware	No	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 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, generating and distribution customers, primarily in the northern portion of Delmarva and in Florida.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 5

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 operations receive a fee, which we share with our customers, from our natural gas marketing subsidiary, PESCO, who optimizes the transportation, storage and natural gas supply for these operations under a three-year contract.

We have a contract with an unaffiliated party to supply propane for customers of our Sandpiper system in Maryland who have not yet converted to natural gas. Under the contract, we are committed to purchase approximately 932,000 gallons of propane annually at either a fixed per-gallon or a local indexed-index-based price. The contract expires in May 2019, at which time, we can purchase the propane from our propane subsidiary or the external markets directly.

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.

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	122,652	2019-2028
	Columbia Gas(1)	15,160	2020-2024
	Transco(1)	27,551	2019-2028
	TETLP(1)	50,000	2027
Florida Natural Gas Distribution	Gulfstream(2)	10,000	2022
	FGT	41,909 - 73,317	2020-2041
	Peninsula Pipeline	137,500	2033-2048
	Peoples Gas	2,660	2024-2035

⁽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

⁽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, including PESCO. 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 on various dates between 2019 and 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:

Chesapeake Utilities Corporation 2018 Form 10-K Page 6

Counterparty	Area Served by Contract	Contracted Amount (MW)	Contract Expiration Date
Gulf Power Company	Northwest Florida	Full Requirement*	2019
FPL	Northeast Florida	Full Requirement*	2024
Eight Flags	Northeast Florida	21.0	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

The following table presents net income for the year ended December 31, 2018 and total assets as of December 31, 2018, 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	$	6,443		$	86,989
Energy Transmission (Aspire Energy)	Ohio	3,620			85,733
Energy Generation (Eight Flags)	Florida	1,657			10,895
Energy Services (PESCO)	Appalachian Basin, Mid-Atlantic, Southeast, Western Pennsylvania	(1,288		)	55,021
Marlin Gas Services (1)	Southeast and Midwest	(186		)	14,046
Other	Other	393			2,884
Total		$	10,639		$	255,568

⁽¹⁾ In December 2018, Marlin Gas Services, LLC (“Marlin Gas Services”), our newly created subsidiary, acquired the assets of Marlin Gas Transport, Inc. ("Marlin Gas Transport"). The net loss reported is a result of the costs of consummating the acquisition exceeding the margin generated for approximately half of December 2018.

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 onsite fueling infrastructure.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 7

Propane Operations - Operational Highlights

For the year ended December 31, 2018, 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 (2)
	Mid-Atlantic				Florida				Mid-Atlantic			Florida			Mid-Atlantic			Florida
Residential bulk	$	27,090	26	%	$	6,799	32	%	10,483	17	%	1,547	23	%	25,870	66	%	10,312	59	%
Residential metered	9,933		10	%	5,037		24	%	4,157	7	%	905	13	%	9,123	23	%	6,034	34	%
Commercial bulk	23,431		23	%	5,393		25	%	14,360	24	%	2,550	38	%	4,201	11	%	971	6	%
Commercial metered	—		—	%	2,127		10	%	—	—	%	820	12	%	—	—	%	280	1	%
Wholesale	31,469		31	%	1,165		5	%	28,680	47	%	944	14	%	31	<1%		8	<1%
AutoGas	4,238		4	%	—		—	%	3,104	5	%	—	—	%	85	<1%		—	—	%
Other (1)	6,160		6	%	761		4	%	—	—	%	—	—	%	—	—	%	—	—	%
Total	$	102,321	100	%	$	21,282	100	%	60,784	100	%	6,766	100	%	39,310	100	%	17,605	100	%

⁽¹⁾ Operating revenues from "Other" sources include revenues from customer loyalty programs; delivery, service and appliance fees; and unbilled revenues.

⁽²⁾ Average number of customers is based on a twelve-month average for the year ended December 31, 2018.

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 7.1 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 (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 2018 Form 10-K Page 8

For the twelve-month period ended December 31, 2018, 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	$	13,429	38	%	2,538	38	%
Supply to CGC	12,530		35	%	1,611	25	%
Supply to Marketers - affiliated	2,654		8	%	1,013	15	%
Supply to Marketers - unaffiliated	3,918		11	%	1,328	20	%
Other (including natural gas gathering and processing)	2,876		8	%	141	2	%
Total	$	35,407	100	%	6,631	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.

Energy Services (PESCO)

PESCO competes with utilities and third-party marketers to sell natural gas and related services directly to commercial and industrial customers. PESCO delivers the natural gas it sells to customers through affiliated and non-affiliated natural gas distribution systems and pipelines and bills customers directly or through the billing services of the natural gas distribution utility that delivers the gas to PESCO’s customer. PESCO manages a portion of the natural gas transportation and storage capacity for our Delmarva natural gas distribution operations under three-year asset management agreements that expire on March 31, 2020.

The following table summarizes PESCO's operating revenues by region in 2018:

	Operating Revenues
	(in thousands)		% of Total
Appalachian Basin	$	34,713	13	%
Mid-Atlantic	127,148		49	%
Southeast	59,077		23	%
Western Pennsylvania	37,775		15	%
Total	$	258,713	100	%

Marlin Gas Services

In December 2018, Marlin Gas Services, our newly created subsidiary, acquired certain operating assets of Marlin Gas Transport, a supplier of mobile compressed natural gas utility and pipeline solutions. Marlin Gas Services provides a temporary solution for gas pipeline and gas distribution systems while safety and integrity work is being performed. The assets purchased have the capacity to transport more than 7 billion cubic feet of natural gas annually using one of the largest fleets of tube trailers dedicated to the transportation of compressed natural gas (“CNG”). The acquisition will allow us to offer solutions to address supply interruption scenarios and provide other unique applications where pipeline supplies are not available or cannot meet customer requirements. Operating revenues and net income generated from the date of acquisition through the year ended December 31, 2018 were immaterial.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 9

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, 2018, we had a total of 983 employees, 119 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 2019.

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	61	2010	President (January 1, 2019 - present) Chief Executive Officer (January 1, 2019 - present) Director (January 1, 2019 - present) President of FPU (June 2010 - February 26, 2019)
Beth W. Cooper	52	2005	Executive Vice President (Beginning February 26, 2019) Chief Financial Officer (September 2008 - present) Senior Vice President (September 2008 - February 26, 2019) Assistant Corporate Secretary (March 2015 - present) Corporate Secretary (June 2005 - March 2015)
James F. Moriarty	61	2015	Executive Vice President (Beginning February 26, 2019) General Counsel & Corporate Secretary (March 2015 - present) Chief Policy and Risk Officer (Beginning February 26, 2019) Senior Vice President (February 2017 - February 26, 2019) Vice President (March 2015 - February 2017)
Stephen C. Thompson	58	1997	Senior Vice President (September 2004 - present) President, Eastern Shore (January 1997 - present) President and Chief Operating Officer, Sandpiper (May 2014 - present) Vice President (May 1997 - September 2004)

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 are 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.

Chesapeake Utilities Corporation 2018 Form 10-K Page 10

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.

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.

PESCO is exposed to market risks beyond our control, which could adversely affect our financial results and capital requirements.

PESCO is subject to market risks beyond our control, including market liquidity and commodity price volatility. Although we maintain a risk management policy, we may not be able to offset completely the price risk associated with volatile commodity prices, which could lead to volatility in earnings. Physical trading also has price risk on any net open positions at the end of each trading day, as well as volatility resulting from (i) intra-day fluctuations of natural gas prices, and (ii) daily price movements between the time natural gas is purchased or sold for future delivery and the time the related purchase or sale is economically hedged. The determination of our net open position at the end of any trading day requires us to make assumptions as to future circumstances, including the use of natural gas by our customers in relation to anticipated market positions. Because the price risk associated with any net open position at the end of such day may increase if the assumptions are not realized, we review these assumptions daily. Net open positions may increase volatility in our financial condition or results of operations if market prices move in a significantly favorable or unfavorable manner, because the changes in fair value of trading contracts are immediately recognized as profits or losses for financial accounting purposes. This volatility may occur, with a resulting increase or decrease in earnings or losses, even though the expected profit margin is essentially unchanged from the date the transactions were consummated.

PESCO is exposed to the credit risk of its counterparties.

PESCO extends credit to counterparties and continually monitors and manages collections aggressively. There is risk that PESCO may not be able to collect amounts owed to it. If the counterparty to such a transaction fails to perform, and any underlying collateral is inadequate, we could experience financial losses, which would negatively impact our results of operations.

PESCO is dependent upon the availability of credit to successfully operate its business.

PESCO depends upon credit to buy natural gas for resale or to trade. If financial market conditions or the financial condition of our Company declines, then the cost of credit could increase or become unavailable, which might adversely affect our results of operations, cash flows and financial condition.

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 gas costs, our results of operations and earnings could be negatively affected.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 11

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.

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. Our natural gas marketing operations compete with third-party suppliers to sell natural gas to commercial and industrial customers. 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. Some of our competitors have significantly greater resources. 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

Chesapeake Utilities Corporation 2018 Form 10-K Page 12

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 generally 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.

Security breaches of our information technology infrastructure, including cyber-attacks and cyber-terrorism, could lead to system disruptions or cause facility shutdowns. If such an 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.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 13

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 gross margin, earnings and cash flows.

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

Federal and state legislative and regulatory initiatives to promote energy efficiency and conservation 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 FERC does not allow the recovery through customer rates of the costs or lower consumption from energy efficiency or conservation, and our propane margins cannot be increased due to market conditions, our results of operations, cash flows and financial condition may be adversely affected.

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

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

Propane. Propane costs are subject to changes as a result of product supply or other market conditions, including weather, economic and political factors affecting crude oil and natural gas supply or pricing. For example, weather conditions could damage production

Chesapeake Utilities Corporation 2018 Form 10-K Page 14

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 and PESCO 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.

PESCO's earnings and operating cash flows are dependent upon optimization of physical assets.

PESCO’s earnings and cash flows are based, in part, on its ability to optimize its portfolio of contractual rights to utilize natural gas storage and pipeline assets. The optimization strategy involves utilizing its physical assets to take advantage of differences in natural gas prices between geographic locations and/or time periods. Any change among various pricing points could affect those differentials. In addition, significant increases in the supply of natural gas for PESCO's market areas can reduce its ability to take advantage of pricing fluctuations in the future. Changes in pricing dynamics and supply could have an adverse impact on its optimization activities, earnings and cash flows. PESCO incurs fixed demand fees to acquire its contractual rights to storage and transportation assets. Should commodity prices at various locations or time periods change in such a way that PESCO is not able to recoup these costs from customers, the cash flows and earnings of PESCO and ultimately, the Company, could be adversely impacted.

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 15

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).

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. Changes in energy use due to weather variations may affect our financial condition

Chesapeake Utilities Corporation 2018 Form 10-K Page 16

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.

ITEM 2. Properties.

Offices and other operational facilities

We own or lease offices and other operational facilities in the following locations: Anne Arundel, Cecil, Dorchester, Somerset, Talbot, Wicomico, and Worcester Counties, Maryland; Kent, New Castle and Sussex Counties, Delaware; Accomack County, Virginia; Alachua, Brevard, Broward, Hendry, Jackson, Levy, Martin, Nassau, Okeechobee, Palm Beach, Polk and Volusia Counties, Florida; Orrville and Athens, Ohio; and Pittsburgh, Pennsylvania.

Regulated Energy Segment

We own approximately 1,594 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 2,862 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 97 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 486 miles of natural gas transmission pipeline, extending from interconnects at Daleville, Honey Brook and Parkesburg, Pennsylvania; and Hockessin, Delaware, to 96 delivery points in southeastern Pennsylvania, Delaware and the eastern shore of Maryland and approximately 86 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 905 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 7.1 million gallons, in Delaware, Maryland, Virginia, Pennsylvania, and Florida. These facilities are located on real estate that is either owned or leased by us.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 17

We own approximately 204 miles of underground propane distribution mains in Delaware; 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: 1,980 miles of natural gas distribution mains (and related equipment) in its service areas; 16 miles of electric transmission line located in Nassau County, Florida; 905 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 76 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.

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 15, 2019, we had 2,253 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $1.4350 per share in 2018 and $1.2800 per share in 2017, and have paid a cash dividend to our common stock stockholders for 58 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, 2018.

Chesapeake Utilities Corporation 2018 Form 10-K Page 18

	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, 2018 through October 31, 2018 (1)	430	$	83.03	—	—
November 1, 2018 through November 30, 2018	—	—		—	—
December 1, 2018 through December 31, 2018	—	—		—	—
Total	430	$	83.03	—	—

⁽¹⁾ In October 2018, we purchased 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). During the quarter, 430 shares were purchased through the reinvestment of dividends.

⁽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 2018 Form 10-K     Page 19

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, 2018, 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.; Unitil Corporation; and Vectren Corporation.

The comparison assumes $100 was invested on December 31, 2013 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.

	2013		2014		2015		2016		2017		2018
Chesapeake Utilities	$	100	$	127	$	149	$	179	$	213	$	225
Industry Index	$	100	$	121	$	135	$	158	$	189	$	202
S&P 500 Index	$	100	$	114	$	115	$	129	$	157	$	150

Chesapeake Utilities Corporation 2018 Form 10-K Page 20

ITEM 6. SELECTED FINANCIAL DATA

	For the Year Ended December 31,
	2018			2017			2016			2015			2014
Operating
(in thousands)
Revenues
Regulated Energy	$	345,281		$	326,310		$	305,689		$	301,902		$	300,442
Unregulated Energy	420,617			324,595			203,778			162,108			184,961
Other businesses and eliminations	(48,409		)	(33,322		)	(10,607		)	(4,766		)	13,431
Total revenues	$	717,489		$	617,583		$	498,860		$	459,244		$	498,834
Operating income(1)
Regulated Energy	$	79,215		$	74,584		$	71,515		$	62,137		$	51,173
Unregulated Energy	16,901			12,631			14,066			16,437			11,686
Other businesses and eliminations	(1,496		)	205			402			418			104
Total operating income	$	94,620		$	87,420		$	85,983		$	78,992		$	62,963
Net income from continuing operations	$	56,580		$	58,124		$	44,675		$	41,140		$	36,092
Assets
(in thousands)
Gross property, plant and equipment	$	1,569,683		$	1,312,117		$	1,175,595		$	1,007,489		$	870,125
Net property, plant and equipment	$	1,383,972		$	1,126,027		$	986,664		$	854,950		$	689,762
Total assets	$	1,693,671		$	1,414,934		$	1,229,219		$	1,067,421		$	904,469
Capital expenditures	$	282,976		$	191,103		$	169,376		$	195,261		$	98,057
Capitalization
(in thousands)
Stockholders’ equity	$	518,439		$	486,294		$	446,086		$	358,138		$	300,322
Long-term debt, net of current maturities	316,020			197,395			136,954			149,006			158,486
Total capitalization	$	834,459		$	683,689		$	583,040		$	507,144		$	458,808
Current portion of long-term debt	11,935			9,421			12,099			9,151			9,109
Short-term debt	294,458			250,969			209,871			173,397			88,231
Total capitalization and short-term financing	$	1,140,852		$	944,079		$	805,010		$	689,692		$	556,148

(1) During the first quarter of 2018, we adopted amended FASB guidance on the presentation of net periodic and postretirement benefit cost ("net benefit cost"). As a result, the components of net benefit cost other than the service component are presented below the subtotal of Operating Income in the consolidated statements of income. All prior periods have been recast to conform to this presentation.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 21

	For the Year Ended December 31,
	2018			2017			2016			2015			2014
Common Stock Data and Ratios
Basic earnings per share	$	3.46		$	3.56		$	2.87		$	2.73		$	2.48
Diluted earnings per share	$	3.45		$	3.55		$	2.86		$	2.72		$	2.47
Diluted earnings per share growth - 1 year	(2.8		)%	24.1		%	5.1		%	10.1		%	9.3		%
Diluted earnings per share growth - 5 year	8.8		%	12.3		%	8.4		%	8.4		%	11.6		%
Diluted earnings per share growth - 10 year	10.1		%	10.7		%	9.3		%	8.4		%	8.5		%
Return on average equity	11.2		%	12.6		%	11.3		%	12.1		%	12.2		%
Common equity / total capitalization	62.1		%	71.1		%	76.5		%	70.6		%	65.5		%
Common equity / total capitalization and short-term financing	45.4		%	51.5		%	55.4		%	51.9		%	54.0		%
Capital expenditures / average total capitalization	37.3		%	30.2		%	31.1		%	29.5		%	22.9		%
Book value per share (1)	$	31.65		$	29.75		$	27.36		$	23.45		$	20.59
Weighted average number of shares outstanding (1)	16,369,616			16,336,789			15,570,539			15,094,423			14,551,308
Shares outstanding at year-end (1)	16,378,545			16,344,442			16,303,499			15,270,659			14,588,711
Cash dividends declared per share (1)	$	1.44		$	1.28		$	1.20		$	1.13		$	1.07
Dividend yield (annualized) (2)	1.8		%	1.7		%	1.8		%	2.0		%	2.2		%
Book yield (3)	4.7		%	4.5		%	4.7		%	5.1		%	5.4		%
Payout ratio (4)	41.6		%	36.0		%	41.8		%	41.5		%	43.0		%
Additional Data
Customers
Natural gas distribution	158,387			153,537			149,179			144,872			141,227
Electric distribution	32,185			32,026			31,695			31,430			31,272
Propane operations	56,915			54,760			54,947			53,682			53,272
Total employees	983			945			903			832			753

⁽¹⁾ Shares and per share amounts for all periods presented reflect the three-for-two stock split declared on July 2, 2014, effected in the form of a stock dividend, and distributed on September 8, 2014.

⁽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.

Chesapeake Utilities Corporation 2018 Form 10-K Page 22

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.

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.

OVERVIEWAND HIGHLIGHTS

(in thousands except per share data)							Increase									Increase
For the Year Ended December 31,	2018			2017			(decrease)			2017			2016			(decrease)
Operating Income:
Regulated Energy	$	79,215		$	74,584		$	4,631		$	74,584		$	71,515		$	3,069
Unregulated Energy	16,901			12,631			4,270			12,631			14,066			(1,435		)
Other businesses and eliminations	(1,496		)	205			(1,701		)	205			402			(197		)
Total Operating Income	94,620			87,420			7,200			87,420			85,983			1,437
Other expense	(615		)	(2,342		)	1,727			(2,342		)	(2,328		)	(14		)
Interest charges	16,431			12,645			3,786			12,645			10,639			2,006
Income Before Income Taxes	77,574			72,433			5,141			72,433			73,016			(583		)
Income taxes	20,994			14,309			6,685			14,309			28,341			(14,032		)
Net Income	$	56,580		$	58,124		$	(1,544	)	$	58,124		$	44,675		$	13,449
Earnings Per Share of Common Stock:
Basic	$	3.46		$	3.56		$	(0.10	)	$	3.56		$	2.87		$	0.69
Diluted	$	3.45		$	3.55		$	(0.10	)	$	3.55		$	2.86		$	0.69

Chesapeake Utilities Corporation 2018 Form 10-K     Page 23

2018 compared to 2017

Our net income decreased by approximately $1.5 million or $0.10 per share in 2018, compared to 2017. Key variances included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Year ended December 31, 2017 Reported Results	$	72,433		$	58,124		$	3.55
Adjusting for unusual items:
Absence of the 2017 deferred tax revaluation benefit associated with the TCJA	—			(14,299		)	(0.87		)
Net impact of PESCO's MTM activity	10,423			7,602			0.46
One-time separation expenses associated with a former executive	(1,548		)	(1,421		)	(0.09		)
Absence of Xeron expenses, including 2017 wind-down expenses	829			605			0.04
	9,704			(7,513		)	(0.46		)
Increased (Decreased) Gross Margins:
Eastern Shore and Peninsula Pipeline service expansions*	9,709			7,082			0.43
Pass-through of lower taxes to regulated energy customers(1)	(9,562		)	(6,975		)	(0.42		)
Natural gas growth (excluding service expansions)	5,911			4,311			0.26
Implementation of Eastern Shore settled rates*(2)	5,803			4,233			0.26
Impact on PESCO from Bomb Cyclone and pipeline capacity constraints	(5,545		)	(4,044		)	(0.25		)
Colder weather	5,046			3,680			0.22
Unregulated Energy growth, excluding PESCO	3,140			2,290			0.14
Florida electric reliability/modernization program*	1,516			1,106			0.07
Florida GRIP*	1,277			932			0.06
Other margin for PESCO operations (net)	(489		)	(357		)	(0.02		)
	16,806			12,258			0.75
Decreased (Increased) Other Operating Expenses(3):
Depreciation, asset removal and property taxes	(4,779		)	(3,486		)	(0.21		)
Payroll expense (increased staffing and annual salary increases)	(4,349		)	(3,172		)	(0.19		)
Facilities maintenance costs	(2,687		)	(1,960		)	(0.12		)
Operating expenses to increase staffing, infrastructure and risk management systems necessary to support growth for PESCO(3)	(2,665		)	(1,944		)	(0.12		)
Outside services	(2,182		)	(1,592		)	(0.10		)
Vehicle, other taxes and credit collections	(1,551		)	(1,131		)	(0.07		)
Other employee-related expenses	(1,100		)	(802		)	(0.05		)
Incentive compensation costs	734			535			0.03
Outside regulatory costs	661			482			0.03
Early termination of facility lease due to consolidation of operations facilities	(423		)	(309		)	(0.02		)
	(18,341		)	(13,379		)	(0.82		)
Interest charges	(3,786		)	(2,762		)	(0.17		)
Income taxes - Regulated Energy (1)	—			6,975			0.42
Other income tax effects - primarily the impact of income rate tax changes on Unregulated businesses	—			2,323			0.14
Net Other changes	758			554			0.04
Year ended December 31, 2018 Reported Results	$	77,574		$	56,580		$	3.45

⁽¹⁾ "Pass-through of lower taxes to regulated customers" represents the amounts that have already been refunded to customers or reserves established for future refunds and/or reduced rates to customers in 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes expense and are expected to have no net impact on net income.

⁽²⁾ Excluding amounts refunded to customers associated with the TCJA, which are broken out separately and discussed in footnote 1.

⁽³⁾As a result of increased staffing, infrastructure and risk management systems to support growth for PESCO, operating expenses for PESCO are presented separately.

* See the Major Projects and Initiatives table.

Chesapeake Utilities Corporation 2018 Form 10-K Page 24

2017 compared to 2016

Our net income increased by approximately $13.4 million or $0.69 per share (diluted) in 2017, compared to 2016. Key variances included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Year ended December 31, 2016 Reported Results	$	73,016		$	44,675		$	2.86
Adjusting for unusual items:
Deferred tax revaluation benefit associated with the TCJA	—			14,299			0.87
Net impact of PESCO's MTM activity	(5,783		)	(3,499		)	(0.21		)
Impact of winding down of Xeron operations and absence of 2016 loss	745			451			0.03
	(5,038		)	11,251			0.69
Increased (Decreased) Gross Margins:
Eight Flags' CHP plant	4,901			2,965			0.19
Implementation of new base rates for Eastern Shore*	3,693			2,234			0.14
PESCO - margin from operations	3,365			2,036			0.13
Natural gas growth (excluding service expansions)	2,818			1,705			0.11
Service expansions*	2,062			1,248			0.08
Florida GRIP*	1,902			1,151			0.07
Aspire Energy rates and management fees	1,125			680			0.04
Customer consumption (non-weather)	721			436			0.03
Implementation of Delaware Division settled rates	831			503			0.03
Wholesale propane sales and margins	678			410			0.03
Retail propane margins	645			390			0.02
Weather impact	578			350			0.02
Margin from Sandpiper System Improvement Rate	291			176			0.01
	23,610			14,284			0.90
(Increased) Decreased Other Operating Expenses:
Payroll expense	(6,487		)	(3,925		)	(0.25		)
Depreciation, asset removal and property tax costs due to new capital investments	(5,120		)	(3,098		)	(0.20		)
Eight Flags' operating expenses	(2,920		)	(1,767		)	(0.11		)
Benefit and other employee-related expenses	(1,485		)	(899		)	(0.06		)
Regulatory expenses associated with rate filings	(1,005		)	(608		)	(0.04		)
Taxes other than property and income	(739		)	(447		)	(0.03		)
Credit, collections & customer service expenses	515			311			0.02
Outside services and facilities maintenance costs	417			252			0.02
Vehicle expenses	(372		)	(225		)	(0.01		)
Sales and advertising expenses	(259		)	(157		)	(0.01		)
	(17,455		)	(10,563		)	(0.67		)
Increase in outstanding shares from the September 2016 public offering	—			—			(0.16		)
Interest charges	(2,006		)	(1,214		)	(0.08		)
Change in other expense	(191		)	(115		)	(0.01		)
Change in effective tax rate prior to tax reform	—			(500		)	(0.03		)
Net other changes	497			306			0.05
Year ended December 31, 2017 Reported Results	$	72,433		$	58,124		$	3.55

* See the Major Projects and Initiatives table.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 25

SUMMARYOF KEY FACTORS

Recently Completed and Ongoing Major Projects and Initiatives

We constantly seek and develop additional projects and initiatives in order to increase shareholder value and serve our customers. The following table represents the major projects recently completed and currently underway. In the future, we will add new projects to this table as such projects are initiated:

	Gross Margin for the Period
	Year Ended December 31,						Estimate for Fiscal
Project / Initiative	2016		2017		2018		2019
(in thousands)
Florida GRIP	$	11,552	$	13,454	$	14,731	$	16,276
Eastern Shore Rate Case (1)	—		3,693		9,496		9,800
Florida Electric Reliability/Modernization Pilot Program (1)	—		94		1,610		1,558
New Smyrna Beach, Florida(1)	—		235		1,409		1,409
2017 Eastern Shore System Expansion - including interim services (1)	—		483		8,015		15,709
Northwest Florida Expansion(1)	—		—		3,485		6,500
Western Palm Beach County, Florida Expansion(1)	—		—		54		1,250
Marlin Gas Services	—		—		110		4,475
Ohl propane acquisition (rolled into Sharp)	—		—		—		1,200
Total	$	11,552	$	17,959	$	38,910	$	58,177

⁽¹⁾Gross margin amount included in this table has not been adjusted to reflect the impact of the TCJA. The refunds and rate reductions implemented were or will be, offset by lower federal income taxes due to the TCJA.

Ongoing Growth 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 $127.0 million to replace 268 miles of qualifying distribution mains, including $13.3 million and $10.8 million during 2018 and 2017, respectively. GRIP generated additional gross margin of $1.3 million in 2018 compared to 2017.

Regulatory Proceedings

Eastern Shore Rate Case

Eastern Shore's rate case settlement agreement became final on April 1, 2018, with settlement rates effective August 1, 2017 and tax-adjusted rates effective January 1, 2018. The final agreement increases Eastern Shore's operating income by $6.6 million, representing an estimated $9.8 million in additional margin from base rates offset by an estimated $3.2 million in lower federal income tax expense for Eastern Shore resulting from the TCJA. In 2018, Eastern Shore recognized incremental gross margin of approximately $5.8 million and provided rate reductions to customers totaling approximately $3.3 million as a result of the new rates. Annual margin from the new rates in future years is estimated to be $9.8 million.

Florida Electric Reliability/Modernization Pilot Program

In December 2017, the Florida PSC approved a $1.6 million annualized rate increase, effective January 2018, for the recovery of a limited number of investments and costs related to reliability, safety and modernization for our Florida electric distribution system. This increase will continue through at least the last billing cycle of December 2019. For the years ended December 31, 2018 and 2017, incremental gross margin of $1.5 million and $94,000, respectively, was generated by this program.

Chesapeake Utilities Corporation 2018 Form 10-K Page 26

Major Projects and Initiatives Currently Underway

New Smyrna Beach, Florida Project

In the fourth quarter of 2017, we commenced construction of a 14-mile natural gas transmission pipeline to serve current customers and planned customer growth in the New Smyrna Beach service area. A portion of the project was placed into service at the end of 2017, and the remainder was placed into service during the fourth quarter of 2018. For the year ended December 31, 2018, the project generated incremental gross margin of approximately $1.2 million compared to 2017 and is expected to generate $1.4 million in annual gross margin going forward.

2017 Eastern Shore System Expansion Project

From November 2017 to December 2018, Eastern Shore substantially completed the construction of a system expansion project that increased its capacity by 26 percent. The first phase of the project was placed into service in December 2017. The project generated $7.5 million in incremental gross margin, including margin from interim services, for the year ended December 31, 2018, compared to 2017. It is expected to produce annual gross margin of approximately $15.7 million in 2019, $15.8 million from 2020 through 2022 and $13.2 million thereafter.

Northwest Florida Expansion Project

In our first expansion of natural gas service into Northwest Florida, Peninsula Pipeline completed construction of transmission lines and the Florida natural gas division completed construction of lateral distribution lines to serve several customers. The project was placed into service in May 2018 and generated gross margin of $3.5 million during 2018. The estimated annual gross margin going forward is $6.5 million.

Western Palm Beach County Belvedere, Florida Project

Peninsula Pipeline is constructing four transmission lines to bring 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 gross margin of $54,000 during 2018. We expect to complete the remainder of the project in phases through early 2020 and estimate gross margin of $1.3 million in 2019 and approximately $5.4 million in future years once fully in service.

Marlin Gas Services

In December 2018, Marlin Gas Services, our newly created subsidiary, acquired certain operating assets of Marlin Gas Transport, a supplier of mobile compressed natural gas utility and pipeline solutions. The acquisition will allow us to offer solutions to address supply interruption scenarios and provide other unique applications where pipeline supplies are not available or cannot meet customer requirements. Operating margins generated in 2018 were immaterial, given the date of acquisition. We estimate that this acquisition will generate additional annual gross margin of approximately $4.5 million in 2019, with potential for additional growth in future years.

Ohl Propane Acquisition

In December 2018, Sharp Energy acquired certain propane customers and operating assets of R.F. Ohl Fuel Oil, Inc ("Ohl"). Ohl provided propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania, located between two of Sharp's existing districts. The customers and assets acquired from Ohl have been assimilated into Sharp. Operating margins generated in 2018 were immaterial, given the date of acquisition. We estimate that this acquisition will generate additional gross margin of approximately $1.2 million for Sharp in 2019, with the potential for additional growth in future years.

Future Projects Not Included in the Table Above

Del-Mar Energy Pathway Project

In September 2018, Eastern Shore filed for FERC authorization to construct the Del-Mar Energy Pathway project to provide an additional 14,300 Dts/d of capacity to four customers. The benefits of this project include additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and the initial extension of Eastern Shore’s pipeline system into Somerset County, Maryland. The estimated annual gross margin from this project is $5.1 million. Eastern Shore anticipates that this project will be fully in-service by the third quarter of 2020, assuming that the FERC authorizes the project by August 2019.

Other Major Factors Influencing Gross Margin

Weather and Consumption

The impact of colder temperatures on customer consumption during 2018 contributed $5.0 million in incremental gross margin compared to 2017. While 2018 was colder than 2017, it was still 1.1 percent warmer than normal (average across our service territories). Normal weather during 2018 would have generated $4.0 million in additional gross margin. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for 2018, 2017 and 2016.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 27

HDD and CDD Information

For the Years Ended December 31,	2018		2017		Variance		2017		2016		Variance
Delmarva
Actual HDD	4,251		3,800		451		3,800		3,979		(179	)
10-Year Average HDD ("Normal")	4,379		4,374		5		4,374		4,453		(79	)
Variance from Normal	(128	)	(574	)			(574	)	(474	)
Florida
Actual HDD	780		533		247		533		672		(139	)
10-Year Average HDD ("Normal")	800		818		(18	)	818		828		(10	)
Variance from Normal	(20	)	(285	)			(285	)	(156	)
Ohio
Actual HDD	5,845		5,126		719		5,126		5,529		(403	)
10-Year Average HDD ("Normal")	5,823		5,914		(91	)	5,914		5,918		(4	)
Variance from Normal	22		(788	)			(788	)	(389	)
Florida
Actual CDD	3,105		3,013		92		3,013		3,152		(139	)
10-Year Average CDD ("Normal")	2,889		2,865		24		2,865		2,820		45
Variance from Normal	216		148				148		332

Hurricane Michael Update

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 losing electrical service. FPU has restored service to those customers who were able to accept service following Hurricane Michael after a significant hurricane restoration effort. In conjunction with restoring these services, FPU expended over $60 million to restore service, which has been recorded as new plant and equipment or charged against FPU’s accumulated depreciation and storm reserve. We have begun preparing the necessary regulatory filings to seek recovery for the costs incurred, including replenishment of our storm reserve. In conjunction with the hurricane-related expenditures, we executed two 13-month unsecured term loans as temporary financing, each in the amount of $30 million. The interest cost associated with these loans is LIBOR plus 75 basis points. One of the term loans was executed in December 2018 and the other was executed in January 2019. The storm did not have a material impact on our financial results in 2018 as services were restored to a majority of our customers, and is not expected to have a significant impact going forward as we will be seeking recovery of the storm costs through rates.

Natural Gas Distribution Customer and Consumption Growth

Customer growth for our natural gas distribution operations generated $3.9 million in additional gross margin for the year ended December 31, 2018 compared to the same period in 2017. The additional margin was generated from an increase of approximately 3.3 percent in the average number of residential customers served, growth in volumes delivered to commercial and industrial customers on the Delmarva Peninsula and in Florida, and new service initiated to customers in Northwest Florida. Higher residential and commercial customers' consumption increased gross margin by $2.0 million for the year ended December 31, 2018 compared to the same period in 2017.

Chesapeake Utilities Corporation 2018 Form 10-K Page 28

(in thousands)	Increase (decrease) in Margin in 2018
Customer growth:
Residential	$	1,604
Commercial and industrial, excluding new service in Northwest Florida	1,322
New service in Northwest Florida	987
Total customer growth	3,913
Volume growth:
Residential	655
Commercial and industrial	1,522
Other - including unbilled revenue	(179		)
Total volume growth	1,998
Total natural gas distribution growth	$	5,911

Propane Operations

The Company's Florida and Mid-Atlantic propane distribution operations continue to pursue a multi-pronged growth plan, which includes: targeting retail and wholesale customer growth in existing markets, both organically as well as through acquisitions; incremental growth from recent and planned start-ups in new markets; targeting new community gas systems in high growth areas; further build-out of the Company's propane vehicular platform through AutoGas fueling stations; and optimization of its supply portfolio to generate incremental margin opportunities. Our propane operations and AutoGas segment install and support propane vehicle conversion systems for vehicle fleets, including converting fleets to bi-fuel propane-powered engines and providing on-site fueling infrastructure. These operations generated $4.9 million during the year ended December 31, 2018 compared to 2017. Colder temperatures accounted for $2.2 million of the margin increase. The balance of the gross margin increase for the year reflected the impact of the growth strategies discussed above, including generating approximately a four-percent increase in customers. Supply management initiatives have also increased retail propane margins from many customer classes and margin from wholesale propane sales.

PESCO

In 2018, PESCO's gross margin increased by $4.4 million compared to 2017. Higher gross margin in 2018 from PESCO resulted from the following:

(in thousands)	Margin Impact
Net impact of PESCO's MTM activity	$	10,423
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)	(3,284		)
Loss for the Mid-Atlantic retail portfolio caused by pipeline capacity constraints in January and warm weather in February 2018 (1)	(2,261		)
Other margin for PESCO operations (net)	(489		)
Total Change in Gross Margin for PESCO in 2018	$	4,389

⁽¹⁾The 2018 Bomb Cyclone refers to the high-intensity winter storms in early January 2018 that impacted the Mid-Atlantic region and which had a residual impact on our businesses through the month of February.   The exceedingly high demand and associated impacts on pipeline capacity and gas supply in the Mid-Atlantic region created significant, unusual costs for PESCO. While such concerted impacts will recur infrequently, our management revisited and refined its risk management strategies and implemented additional controls.

For the year ended December 31, 2018, PESCO reported an operating loss of $1.4 million, compared to an operating loss of $3.1 million during the prior year period. The year-over-year improvement in operating loss reflects primarily increased gross margin of $4.4 million, for the reasons discussed in the table above, which was offset by an increase of $2.7 million in other operating expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy.

Xeron

Xeron's operations were wound down during the second quarter of 2017. Operating income in 2018 improved by $718,000 over 2017, due to the absence of an operating loss and wind-down expenses incurred in 2017.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 29

REGULATED ENERGY

							Increase								Increase
For the Year Ended December 31,	2018			2017			(decrease)		2017			2016			(decrease)
(in thousands)
Revenue	$	345,281		$	326,310		$	18,971	$	326,310		$	305,689		$	20,621
Cost of sales	121,828			118,769			3,059		118,769			109,609			9,160
Gross margin	223,453			207,541			15,912		207,541			196,080			11,461
Operations & maintenance	97,741			90,931			6,810		90,931			86,434			4,497
Gain from a settlement	(130		)	(130		)	—		(130		)	(130		)	—
Depreciation & amortization	31,876			28,554			3,322		28,554			25,677			2,877
Other taxes	14,751			13,602			1,149		13,602			12,584			1,018
Other operating expenses	144,238			132,957			11,281		132,957			124,565			8,392
Operating Income	$	79,215		$	74,584		$	4,631	$	74,584		$	71,515		$	3,069

2018 compared to 2017

Operating income for the Regulated Energy segment for 2018 was $79.2 million, an increase of $4.6 million, or 6.2 percent, compared to 2017. Adjusting for the estimated pass-through of lower taxes to customers, operating income increased by $14.2 million or 19.0 percent, compared to the prior year. The growth in operating income was due to an increase in gross margin of $15.9 million, $25.5 million adjusted for the tax pass-through, partially offset by $11.3 million in higher other operating expenses to support the margin growth. Growth in 2018 was strong across all business units in the regulated energy segment with the most significant contributions coming from expansions at Peninsula Pipeline and Eastern Shore, customer and consumption growth in the natural gas distribution operations, colder weather, and safety and reliability investments in the Florida electric and gas distribution operations.

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	$	9,709
Natural gas growth (excluding service expansions)	5,911
Implementation of Eastern Shore settled rates	5,803
Colder weather	1,788
Florida electric reliability/modernization program	1,516
Florida GRIP	1,277
Other	(530		)
Total	25,474
Less: Pass-through to regulated customers of lower taxes as a result of the TCJA*	(9,562		)
Year-over-year increase in gross margin	$	15,912

*As a result of the TCJA and resulting directives by federal and state regulatory commissions, we reserved or refunded to customers of our regulated businesses an estimated $9.6 million in 2018. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment.

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.

Service Expansions

The following natural gas pipeline service expansions generated additional gross margin of $9.7 million in 2018:

• $7.5 million from Eastern Shore's services, including those provided to customers on an interim basis, in conjunction with portions of Eastern Shore's 2017 Expansion Project that were placed in service, partially offset by the absence of $2.0 million in short-term contracts that were replaced by long-term service agreements; and

• $4.7 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.

Chesapeake Utilities Corporation 2018 Form 10-K Page 30

Natural Gas Growth (excluding service expansions)

We generated increased gross margin of $5.9 million in 2018 from natural gas growth and consumption (excluding service expansions) primarily from the following:

• $2.3 million and $1.6 million, respectively, from residential and commercial customer growth in Florida and on the Delmarva Peninsula; and

• $2.0 million from higher sales volumes (consumption) on the Delmarva Peninsula and in Florida that were not driven by weather.

Implementation of Eastern Shore's Settled Rates

Eastern Shore generated additional gross margin of $5.8 million from the implementation of new rates as a result of its rate case filing. See Note 19, Rates and Other Regulatory Activities, to the consolidated financial statements for additional details.

Colder Weather

Temperatures during 2018 were 1.1 percent warmer than normal (average across our service territories), compared to 14.8 percent warmer than normal (average across our service territories) during 2017. The colder weather increased usage and generated $1.8 million in additional margin for 2018.

Florida Electric Reliability/Modernization Program

This program generated incremental gross margin of $1.5 million in 2018. See Note 19, Rates and Other Regulatory Activities, to the consolidated financial statements for additional details.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $1.3 million in 2018 compared to 2017.

Impact of the TCJA on Customer Rates

Implementation of the TCJA in 2018, decreased gross margin by $9.6 million due to refunds and reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by an equal reduction in federal income taxes, and, therefore had no impact on net income. See Note 19, Rates and Other Regulatory Activities, for additional discussion of the TCJA impact.

Other Operating Expenses

Other operating expenses increased by $11.3 million, incurred primarily to support business growth. The significant factors contributing to the increase in other operating expenses included:

• $4.2 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;

• $2.4 million in higher payroll expenses related to staffing and salary increases. This increase was partially offset by lower incentive compensation costs of $737,000;

• $2.2 million in higher costs related to outside services to support growth;

• $1.7 million in higher facilities and maintenance costs to maintain system integrity;

• $869,000 in higher vehicle, other taxes and credit collections; and

• $514,000 in other employee-related expenses.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 31

2017 compared to 2016

Operating income for the Regulated Energy segment for 2017 was $74.6 million, an increase of $3.1 million, or 4.3 percent, compared to 2016. The increased operating income was due to an increase in gross margin of $11.5 million, partially offset by higher other operating expenses of $8.4 million.

Gross Margin

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

(in thousands)	Margin Impact
Implementation of Eastern Shore rates	$	3,693
Natural gas growth (including customer and consumption growth but excluding service expansions)	2,818
Eastern Shore and Peninsula Pipeline service expansions	2,062
Florida GRIP	1,902
Implementation of Delaware Division rates (2017 Settlement)	831
New natural gas transmission and distribution service to Eight Flags CHP plant	537
Other	(382		)
Year-over-year increase in gross margin	$	11,461

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

Implementation of Eastern Shore Rates

Eastern Shore generated additional gross margin of $3.7 million from implementation of new base rates in 2017 as a result of its rate case filing. See Note 19, Rates and Other Regulatory Activities, to the consolidated financial statements for additional details.

Natural Gas Growth (including customer and consumption growth but excluding service expansions)

In 2017, growth in customers and consumption generated increased gross margin of $2.8 million including:

• $1.6 million from a 3.8 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served; and

• $1.2 million from our Florida natural gas distribution operations' customer growth, with approximately two-thirds of the margin growth generated from commercial and industrial customers and one-third generated from new residential customers.

Service Expansions

We generated additional gross margin of $2.1 million in 2017 from the following natural gas services:

• $1.2 million from short-term firm service available through Eastern Shore's natural gas receipt capacity from TETLP;

• $433,000 from interim services provided by Eastern Shore after a portion of an expansion project was placed in service in December 2017;

• $298,000 from Eastern Shore's increased long-term firm service rates for an industrial customer in Delaware; and

• $235,000 generated by Peninsula Pipeline from the New Smyrna Beach Expansion Project.

Florida GRIP

Increased investment in GRIP generated additional gross margin of $1.9 million in 2017 compared to 2016.

Implementation of Delaware Division Rates

Our Delaware Division generated additional gross margin of $831,000 as a result of its rate case settlement in 2017.

Service to Eight Flags

We generated additional gross margin of $537,000 in 2017, compared to 2016, from new natural gas transmission and distribution services provided to Eight Flags' CHP plant.

Chesapeake Utilities Corporation 2018 Form 10-K Page 32

Other Operating Expenses

Other operating expenses increased by $8.4 million. The significant components of the increase in other operating expenses included:

• $4.1 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;

• $3.6 million in higher payroll expenses for additional personnel to support growth; and

• $1.0 million in increased regulatory expenses, due primarily to costs associated with Eastern Shore’s rate case filing in 2017; which was partially offset by

• $529,000 in lower credit, collection and customer services expenses.

UNREGULATED ENERGY

					Increase						Increase
For the Year Ended December 31,	2018		2017		(decrease)		2017		2016		(decrease)
(in thousands)
Revenue	$	420,617	$	324,595	$	96,022	$	324,595	$	203,778	$	120,817
Cost of sales	336,819		252,023		84,796		252,023		138,816		113,207
Gross margin	83,798		72,572		11,226		72,572		64,962		7,610
Operations & maintenance	54,263		48,576		5,687		48,576		42,437		6,139
Depreciation & amortization	8,845		7,954		891		7,954		6,386		1,568
Other taxes	3,789		3,411		378		3,411		2,073		1,338
Other operating expenses	66,897		59,941		6,956		59,941		50,896		9,045
Operating Income	$	16,901	$	12,631	$	4,270	$	12,631	$	14,066	$	(1,435	)

2018 Compared to 2017

Operating income for the Unregulated Energy segment for 2018 was $16.9 million, an increase of $4.3 million compared to 2017. The increased operating income was due to an increase in gross margin of $11.2 million, which was partially offset by an increase of $7.0 million in other operating expenses.

Given the impact of the MTM gain and loss recorded by PESCO in the first quarter of 2018 and fourth quarter of 2017, respectively, and the increased staffing, infrastructure and risk management systems implemented to support PESCO's growth, the Company is continuing to present PESCO’s 2018 results separate from the rest of its Unregulated Energy segment:

Unregulated Energy, excluding PESCO

					Increase						Increase
For the Year Ended December 31,	2018		2017		(decrease)		2017		2016		(decrease)
(in thousands)
Gross margin	$	77,197	$	70,360	$	6,837	$	70,360	$	60,332	$	10,028
Depreciation, amortization and property taxes	9,678		9,081		597		9,081		7,047		2,034
Other operating expenses	49,197		45,504		3,693		45,504		41,085		4,419
Operating Income	$	18,322	$	15,775	$	2,547	$	15,775	$	12,200	$	3,575

Chesapeake Utilities Corporation 2018 Form 10-K     Page 33

Gross Margin

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

(in thousands)	Margin Impact
Propane Operations
Customer growth, increased sales volumes (non-weather related) and other factors	2,947
Additional customer consumption from colder weather	2,241
Decreased margins per gallon in certain customer classes	(977		)
Service, appliances and other fees	404
Higher wholesale propane margins and sales	287
Aspire Energy
Higher customer consumption from colder weather	1,017
Increase in rates effective on various dates in 2018	602
Other	316
Year-over-year increase in gross margin	$	6,837

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.

Propane Operations - Increased Margin Driven by Growth and Other Factors

Gross margin increased by $2.9 million, due to increased propane sales as a result of customer growth, higher sales volumes and other factors in Florida and the Mid-Atlantic region.

Propane Operations - Increased Customer Consumption - (Weather)

Gross margin increased by $2.2 million, due primarily to increased customer consumption in the Mid-Atlantic region as a result of colder temperatures in 2018 compared to 2017.

Aspire Energy - Increased Customer Consumption (Weather)

Gross margin increased by $1.0 million, as a result of increased natural gas delivered, due primarily to colder temperatures in 2018 when compared to temperatures in 2017.

Propane Operations - Decreased retail margins per gallon for certain customer classes

Gross margin decreased by $1.0 million, driven by lower sales prices for primarily two customer classes in response to market conditions.

Propane Operations - Services, appliances and other fees

Gross margin increased by $404,000, from services, appliances and other fees.

Aspire Energy - Increased Margin Driven by Changes in Rates

Gross margin increased by $602,000, due primarily to changes in customer rates on various dates during 2018.

Wholesale Propane Margins

Gross margin increased by $287,000, in 2018 due to a higher realized margin per gallon and an increase in volumes delivered for the Mid-Atlantic propane operations.

Chesapeake Utilities Corporation 2018 Form 10-K Page 34

PESCO

							Increase							Increase
For the Year Ended December 31,	2018			2017			(decrease)		2017			2016		(decrease)
(in thousands)
Gross margin	$	6,601		$	2,212		$	4,389	$	2,212		$	4,630	$	(2,418	)
Depreciation, amortization and property taxes	604			206			398		206			18		188
Other operating expenses	7,418			5,150			2,268		5,150			2,746		2,404
Operating Income	$	(1,421	)	$	(3,144	)	$	1,723	$	(3,144	)	$	1,866	$	(5,010	)

In 2018, PESCO's gross margin increased by $4.4 million compared to 2017. Higher gross margin in 2018 from PESCO resulted from the following:

(in thousands)	Margin Impact
Net impact of PESCO's MTM activity	$	10,423
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)	(3,284		)
Loss for the Mid-Atlantic retail portfolio caused by pipeline capacity constraints in January and warm weather in February 2018 (1)	(2,261		)
Other margin for PESCO operations (net)	(489		)
Total Change in Gross Margin for PESCO in 2018	$	4,389

⁽¹⁾The 2018 Bomb Cyclone refers to the high-intensity winter storms in early January 2018 that impacted the Mid-Atlantic region and which had a residual impact on our businesses through the month of February.   The exceedingly high demand and associated impacts on pipeline capacity and gas supply in the Mid-Atlantic region created significant, unusual costs for PESCO. While such concerted impacts are not expected to occur frequently, our management revisited and refined its risk management strategies and implemented additional controls.

Other Operating Expenses

Other operating expenses increased by $7.0 million in 2018 compared to 2017. The significant components of the increase in operating expenses included:

• $2.7 million in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy;

• $1.9 million in higher payroll expense for additional personnel to support growth and increased deliveries driven by the colder weather in 2018 compared to 2017;

• $953,000 in higher facilities maintenance costs as a result of ongoing compliance activities;

• $597,000 in higher depreciation, amortization and property tax expense due to increased investments; and

• $586,000 in other employee-related costs.

2017 Compared to 2016

Operating income for the Unregulated Energy segment for 2017 was $12.6 million, a decrease of $1.4 million compared to 2016. The decreased operating income was due to an increase in gross margin of $7.6 million, which was offset by an increase of $9.0 million in other operating expenses. Gross margin and operating income, excluding the impact of the unrealized MTM loss on energy-related derivatives, grew by $13.4 million, or 20.6 percent, and $4.3 million, or 30.9 percent, respectively, during 2017, compared to 2016.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 35

Gross Margin

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

(in thousands)	Margin Impact
PESCO - unrealized MTM loss	$	(5,783	)
Eight Flags' CHP plant	4,365
PESCO - margin from operations	3,365
Customer consumption - weather and other	2,144
Pricing amendments to Aspire Energy's long-term sales agreements	1,125
Higher wholesale propane sales and margins	678
Wind-down of Xeron operations	658
Improved retail propane margins	645
Other	413
Year-over-year increase in gross margin	$	7,610

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.

Natural Gas Marketing - PESCO

PESCO's gross margin decreased by $2.4 million due primarily to $5.8 million in the unrealized MTM loss related to PESCO's financial derivatives contracts that were valued at the end of the year; offset by $3.4 million in additional gross margin generated primarily from: (a) providing natural gas to end users within one customer pool pursuant to a supplier agreement with Columbia Gas of Ohio, which expired on March 31, 2017, and (b) an increase in commercial and industrial customers served in Florida.

Eight Flags

Eight Flags' CHP plant generated $4.4 million in additional gross margin in 2017 during its first full year of operations.

Customer Consumption - Weather and Other

Gross margin increased by $2.1 million due to higher, non-weather related sales volumes for our propane operations, increased weather driven demand at Aspire Energy and for our Mid-Atlantic propane operations in the fourth quarter and for our Florida propane operations during the third quarter of 2017.

Pricing Amendments to Aspire Energy's Long-Term Agreements

An increase in gross margin of $1.1 million due to favorable pricing amendments to several long-term sales agreements.

Wholesale Propane Sales and Margins

Gross margin increased by $678,000, due primarily to increased volumes and favorable supply management activities for the Mid-Atlantic propane operations, as well as higher margins in Florida.

Wind-down of Xeron operations

The absence of the prior year operating loss from Xeron increased gross margin by $658,000.

Retail Propane Margins

Gross margin increased by $645,000, due primarily to favorable supply management activities and market conditions.

Other Operating Expenses

Other operating expenses increased by $9.0 million. The significant components of the increase in other operating expenses included:

• $2.9 million in higher operating expenses by Eight Flags' CHP plant in support of the margin generated;

• $2.9 million in higher payroll costs for additional personnel to support growth;

• $1.0 million in higher depreciation expense, of which $476,000 relates to lower depreciation recorded in 2016 as a result of the final accounting for the acquisition of Aspire Energy;

Chesapeake Utilities Corporation 2018 Form 10-K Page 36

• $1.0 million in higher benefits and employee-related costs in 2017; and

• $594,000 in higher taxes, other than property and income taxes.

OTHER EXPENSE, NET

Other expense, net for 2018 was $615,000, and was $2.3 million for both 2017 and 2016. 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 business and pension and other benefits expense. The decrease in other expense, net in 2018 was due to a decrease in pension expenses when compared to 2017 and the absence of a lease termination payment which occurred in 2017.

INTEREST CHARGES

2018 Compared to 2017

Interest charges for 2018 increased by approximately $3.8 million, compared to 2017. The increase is attributable $3.3 million in additional interest due to higher short-term borrowings and higher short-term interest rates as well as $1.5 million in additional interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017 and the NYL Shelf Notes (Series A) in May 2018. These increases were partially offset by allowance for funds used during construction ("AFUDC") of approximately $1.1 million, primarily from Eastern Shore and Peninsula Pipeline.

2017 Compared to 2016

Interest charges for 2017 increased by approximately $2.0 million compared to 2016. The increase is attributable to $1.3 million in additional interest due to higher short-term borrowings and $1.0 million in additional interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017. The balance of the increase reflects higher interest expense on customer deposits.

INCOME TAXES

2018 Compared to 2017

Income tax expense was $21.0 million for 2018 compared to $14.3 million for 2017. The increase in income tax expense in 2018 was due primarily to enactment of the TCJA in 2017, which resulted in a one-time decrease in our deferred income tax expense for 2017 by $14.3 million. Our effective income tax rate was 27.1 percent in 2018 compared to 19.8 percent in 2017. Our lower effective tax rate in 2017 resulted from the one-time revaluation of deferred tax assets and liabilities from our Unregulated Energy business as a result of the enactment of the TCJA.

2017 Compared to 2016

Income tax expense was $14.3 million for 2017, compared to $28.3 million in 2016. Our effective tax rate was 19.8 percent in 2017, compared to 38.8 percent in 2016. The lower tax expense and effective tax rate in 2017 was due primarily to enactment of the TCJA in December 2017.

LIQUIDITY AND CAPITAL RESOURCES

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $283.0 million in 2018 (including the purchase of certain assets from Marlin CNG Services and Ohl), $191.1 million in 2017 (including the purchase of certain assets of ARM) and $169.4 million in 2016. 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 2018 Form 10-K     Page 37

The following table shows the 2019 capital expenditure budget of $168.2 million by segment and by business line:

(dollars in thousands)
Regulated Energy:	Budget Capital Expenditures
Natural gas distribution	$	64,143
Natural gas transmission	66,787
Electric distribution	5,949
Total Regulated Energy	136,879
Unregulated Energy:
Propane operations	11,870
Energy transmission	8,345
Other unregulated energy	1,416
Total Unregulated Energy	21,631
Other:
Corporate and other businesses	9,705
Total Other	9,705
Total 2019 capital expenditures budget	$	168,215

The 2019 budget, excluding acquisitions, includes: Eastern Shore's Del-Mar Energy Pathway Project, Florida's 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, new buildings and facilities, 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. Over the last five years, our actual capital expenditures have averaged 98 percent of the initial budgeted capital expenditures for those years.

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

Capital Structure

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

Our capitalization as of December 31, 2018 and 2017 follows:

	December 31, 2018				December 31, 2017
(in thousands)
Long-term debt, net of current maturities	$	316,020	38	%	$	197,395	29	%
Stockholders’ equity	518,439		62	%	486,294		71	%
Total capitalization, excluding short-term borrowings	$	834,459	100	%	$	683,689	100	%

	December 31, 2018				December 31, 2017
(in thousands)
Short-term debt	$	294,458	26	%	$	250,969	26	%
Long-term debt, including current maturities	327,955		29	%	206,816		22	%
Stockholders’ equity	518,439		45	%	486,294		52	%
Total capitalization, including short-term borrowings	$	1,140,852	100	%	$	944,079	100	%

Chesapeake Utilities Corporation 2018 Form 10-K Page 38

Included in the long-term debt balances at December 31, 2018, were capital lease obligations for Sandpiper and Sharp. Sandpiper maintains a capacity, supply and operating agreement ($620,000 of current maturities) that expires in May 2019. The capacity portion of this agreement is accounted for as a capital lease. Our Mid-Atlantic propane operations business unit has entered into an agreement to rent property in Anne Arundel County Maryland which it intends to purchase during the first quarter of 2019 ($690,000 of current maturities).

As of December 31, 2018, 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, 2018, $242.8 million of our consolidated net income and $118.2 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 45 percent as of December 31, 2018. Excluding the funds expended for Hurricane Michael restoration activities, our equity to total capitalization ratio, including short-term borrowings, would have been approximately 48 percent.

As described below under “Short-Term Borrowings,” we have a Revolver with borrowing capacity of $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into long-term shelf agreements for the potential private placement of unsecured senior debt as further described below under the heading “Shelf Agreements.”

We will seek to align, as much as feasible, any long-term debt or equity issuance(s) with the commencement of service and associated earnings for larger revenue generating capital projects and considering market conditions.

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL who are under no obligation to purchase any unsecured debt. The proceeds received from the issuances of these shelf notes was used to reduce borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. 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 then amended in September 2018 to increase the borrowing capacity back to $150.0 million of which Prudential accepted our request to purchase our unsecured debt of $100.0 million at an interest rate of 3.98% on or before August 20, 2019. The NYL Shelf Agreement totaling $100.0 million was entered in March 2017 and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement was amended in November 2018 to add incremental borrowing capacity of $50.0 million. As of December 31, 2018, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement. The following table summarizes our shelf agreements borrowing information at December 31, 2018:

	Total Borrowing Capacity		Less: Amount of Debt Issued			Less: Unfunded Commitments			Remaining Borrowing Capacity
Shelf Agreement
(in thousands)
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

The 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, 2018 and 2017 were $294.5 million and $251.0 million, respectively, at weighted average interest rates of 3.44 percent and 2.42 percent, respectively.

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, 2018, we had five 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.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 39

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. 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 1.25 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 0.25 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.

Our outstanding short-term borrowings at December 31, 2018 and 2017 included $4.4 million and $10.3 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, 2018 and 2017 were $290.1 million and $240.7 million, respectively. Short-term borrowings were as follows during 2018, 2017 and 2016:

(in thousands)	2018			2017			2016
Average borrowings during the year	$	238,750		$	183,561		$	172,808
Weighted average interest rate for the year	2.93		%	2.03		%	1.43		%
Maximum month-end borrowings	$	290,103		$	240,671		$	201,311

As of December 31, 2018, we had issued $7.0 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, 2018, 2017 and 2016:

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Net cash provided by (used in):
Operating activities	$	146,778		$	110,089		$	104,141
Investing activities	(286,264		)	(186,895		)	(170,037		)
Financing activities	139,961			78,242			67,219
Net increase in cash and cash equivalents	475			1,436			1,323
Cash and cash equivalents—beginning of period	5,614			4,178			2,855
Cash and cash equivalents—end of period	$	6,089		$	5,614		$	4,178

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 2018 and 2017, net cash provided by operating activities was $146.8 million and $110.1 million, respectively, resulting in an increase in cash flows of $36.7 million. Significant operating activities generating the cash flows change were as follows:

Chesapeake Utilities Corporation 2018 Form 10-K Page 40

• Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities increased cash flows by $23.5 million, due primarily to the timing of the receipt of customer payments from increased revenue as well as the timing of payments to vendors.

• Net cash flows from changes in propane inventory, storage gas and other inventories increased by approximately $11.1 million due primarily to higher levels of our inventory during 2017.

• Changes in net prepaid expenses and other current assets, customer deposits and refunds decreased cash flows by $11.7 million due primarily to higher refund activity to customers associated with the impacts of the TCJA through the implementation of lower rates.

• Cash flows from changes in deferred income taxes resulted in an increase of $10.1 million due primarily to timing differences associated with depreciation from increased capital expenditures compared to the prior year, offset by $8.6 million in changes in income taxes payable as a result of the impacts of the TCJA.

• Changes in net regulatory assets and liabilities increased cash flows by $5.1 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.

During 2017 and 2016, net cash provided by operating activities was $110.1 million and $104.1 million, respectively, resulting in an increase in cash flows of $6.0 million. Significant operating activities generating the cash flow change were as follows:

• Net income, adjusted for reconciling activities, decreased cash flows by $485,000. Key reconciling items included: the revaluation of deferred tax assets and liabilities of our unregulated businesses as a result of the implementation of the TCJA, which decreased our deferred tax expense by $14.3 million, higher non-cash adjustments for depreciation and amortization related to increased investing activities and realized losses on sales of assets.

• Net cash flows from changes in other inventories decreased by approximately $6.5 million, due primarily to purchases of additional pipes and other construction inventory as a result of the large expansion projects then underway.

• Changes in income taxes receivable increased cash flows by $5.6 million, due to higher tax refunds as a result of increased tax deductions associated with bonus depreciation.

• Changes in net regulatory assets and liabilities increased cash flows by $4.7 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms and GRIP.

• Changes in net accounts receivable, accrued revenue, accounts payable and accrued liabilities increased cash flows by $3.5 million, due primarily to higher revenues and the timing of customer payments and payments to vendors.

• Changes in net prepaid expenses and other current assets and customer deposits and refunds decreased cash flows by $2.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $286.3 million and $186.9 million during the year ended December 31, 2018 and 2017, respectively, resulting in a decrease in cash flows of $99.4 million. Key investing activities contributing to the cash flow change included:

• Cash paid for capital expenditures increased by $94.4 million due in part to the costs associated with restoring equipment and service to customers following Hurricane Michael in Florida.

• Net cash of $16.7 million was used to acquire operating assets of Ohl and Marlin CNG Services.

Net cash used in investing activities totaled $186.9 million and $170.0 million for 2017 and 2016, respectively, resulting in a decrease in cash flows of $16.9 million in 2017. Key investing activities contributing to the cash flow change included:

• Cash paid for capital expenditures increased by $5.4 million to $175.3 million for 2017.

• Net cash of $11.9 million was used to acquire assets in various transactions during 2017, including ARM, Chipola and Central Gas; there were no corresponding transactions in 2016.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $140.0 million for the year ended December 31, 2018, compared to net cash of $78.2 million provided by financing activities during the prior year resulted in an increase in cash flows of $61.7 million, primarily due to the following:

• Receipt of $154.8 million in net cash proceeds from the Revolver, the Term Note and the issuance of the NYL Shelf Notes (Series A) in May and November 2018, respectively, which increased cash flow by $85.0 million during the year

Chesapeake Utilities Corporation 2018 Form 10-K     Page 41

ended December 31, 2018, compared to the prior year. For the year ended December 31, 2017, we received $69.8 million in net proceeds from the issuance of the Prudential Shelf Notes;

• Increased cash flows from lower repayments of short-term borrowing of $10.1 million under our line of credit arrangements in 2018;

• Decreased cash flows of $7.7 million as a result of changes in cash overdrafts in 2018;

• Higher repayment of long-term debt and capital lease obligations of $34.4 million during the year ended December 31, 2018, compared to $12.1 million in the prior year; and

• Cash dividend payments of $22.0 million in 2018 compared to $19.9 million for 2017.

Net cash provided by financing activities totaled $78.2 million and $67.2 million for 2017 and 2016, respectively. The increase in net cash provided by financing activities in 2017 resulted primarily from the following:

• $69.8 million in net cash proceeds from the issuance of the Prudential Shelf Notes in 2017, offset by the payment of $3.0 million in scheduled long-term debt principal and capital lease obligations payments.

• Net cash flows decreased by $57.4 million due to the absence of proceeds related to the issuance of common stock during the third quarter of 2016.

• Net borrowing of $39.3 million for 2017, compared to net borrowing of $32.5 million for 2016, increased cash flows by $6.8 million. Change in cash overdrafts decreased cash flows by $2.2 million.

• Cash dividend payments of $19.9 million in 2017 compared to $17.5 million for 2016.

CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2018:

	Payments Due by Period
Contractual Obligations	2019		2020-2021		2022-2023		After 2023		Total
(in thousands)
Long-term debt (1)	$	10,626	$	59,200	$	45,700	$	211,700	$	327,226
Operating leases (2)	2,349		3,759		3,331		5,398		14,837
Capital leases (2)	1,310		—		—		—		1,310
Purchase obligations (3)
Transmission capacity	32,276		53,062		39,197		127,634		252,169
Storage capacity	1,720		978		355		—		3,053
Commodities	107,713		18,255		—		—		125,968
Electric supply	16,835		2,675		2,727		1,385		23,622
Unfunded benefits (4)	597		692		635		1,421		3,345
Funded benefits (5)	2,823		—		—		5,188		8,011
Total Contractual Obligations	$	176,249	$	138,621	$	91,945	$	352,726	$	759,541

⁽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 $12.9 million, $21.6 million, $17.5 million and $49.8 million, respectively, for the periods indicated above. Expected interest payments for all periods total $101.8 million.

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

⁽³⁾ See Item 8, Financial Statements and Supplementary Data, Note 21, Other Commitments and Contingencies, for additional information.

⁽⁴⁾ We have recorded long-term liabilities of $3.3 million at December 31, 2018 for unfunded post-employment and post-retirement benefit plans. The amounts specified in the table are based on expected payments to current retirees and assume a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations. See Item 8, Financial Statements and Supplementary Data, Note 17, Employee Benefit Plans, for additional information on the plans.

⁽⁵⁾ We have recorded long-term liabilities of $17.8 million at December 31, 2018 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 $1.3 million, reflecting the payments we expect to make to the trust funds in 2017. 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 $6.7 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 account.

Chesapeake Utilities Corporation 2018 Form 10-K Page 42

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, 2018 was $76.5 million, with the guarantees expiring on various dates throughout 2019.

We have issued letters of credit totaling $7.0 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 December 2019. There were no draws on these letters of credit as of December 31, 2018. 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 seven 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.

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 43

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 theConsolidated 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.

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 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 2018 indicated no impairment of goodwill. Additional information is presented inItem 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.

Chesapeake Utilities Corporation 2018 Form 10-K Page 44

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 inItem 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 2018, 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 3.50 percent and 3.75 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 Citigroup yield curve, 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 increase our annual pension and postretirement costs by approximately $20,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $20,000.

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 $128,000 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. Additional information 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.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 45

We can store up to approximately 7.1 million gallons of propane (including leased storage and rail cars) during the winter season to serve our customers. Decreases in wholesale propane prices may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate this risk, we have implemented a Risk Management Policy that allows our propane operation to enter into fair value hedges, cash flows 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 to fulfill our natural gas purchase requirements.

PESCO is a party to natural gas swap and futures contracts, which provide us the right to purchase natural gas at a fixed price at future dates. Upon expiration, the contracts can be settled financially without taking delivery of natural gas, or PESCO can procure natural gas and deliver it to its customers. PESCO is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids and natural gas deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts.

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, 2017 to December 31, 2018:

(in thousands)	Balance at December 31, 2017			Increase (Decrease) in Fair Market Value			Less Amounts Settled			Balance at December 31, 2018
PESCO	$	(6,153	)	$	16,674		$	(10,705	)	$	(184	)
Sharp	1,192			(3,376		)	663			(1,521		)
Total	$	(4,961	)	$	13,298		$	(10,042	)	$	(1,705	)

There were no changes in the methods of valuations during the year ended December 31, 2018.

The following is a summary of fair market value of financial derivatives as of December 31, 2018, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2019			2020			2021			2022		Total Fair Value
Price based on ICE(1)  PESCO	$	(2,075	)	$	1,817		$	72		$	2	$	(184	)
Price based on Mont Belvieu - Sharp	(1,229		)	(250		)	(42		)	—		(1,521		)
Total	$	(3,304	)	$	1,567		$	30		$	2	$	(1,705	)

⁽¹⁾ Intercontinental Exchange (an electronic trading platform)

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 2018 Form 10-K Page 46

ITEM 8. FINANCIAL STATEMENTSAND SUPPLEMENTARY DATA.

REPORTOF 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, 2018 and 2017, 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, 2018, 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, 2018, 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, 2018 and 2017, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2018, 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, 2018, 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 2018 Form 10-K     Page 47

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.

/s/ Baker Tilly Virchow Krause, LLP

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

Philadelphia, Pennsylvania

February 26, 2019

Chesapeake Utilities Corporation 2018 Form 10-K Page 48

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Income
	For the Year Ended December 31,
	2018			2017			2016
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	345,281		$	326,310		$	305,689
Unregulated Energy	420,617			324,595			203,778
Other businesses and eliminations	(48,409		)	(33,322		)	(10,607		)
Total operating revenues	717,489			617,583			498,860
Operating Expenses
Regulated Energy cost of sales	121,828			118,769			109,609
Unregulated Energy and other cost of sales	288,913			219,145			128,434
Operations	138,441			125,994			115,684
Maintenance	14,387			12,701			12,391
Gain from a settlement	(130		)	(130		)	(130		)
Depreciation and amortization	40,802			36,599			32,159
Other taxes	18,628			17,085			14,730
Total operating expenses	622,869			530,163			412,877
Operating Income	94,620			87,420			85,983
Other expense, net	(615		)	(2,342		)	(2,328		)
Interest charges	16,431			12,645			10,639
Income Before Income Taxes	77,574			72,433			73,016
Income taxes	20,994			14,309			28,341
Net Income	$	56,580		$	58,124		$	44,675
Weighted Average Common Shares Outstanding:
Basic	16,369,616			16,336,789			15,570,539
Diluted	16,419,870			16,383,352			15,613,091
Earnings Per Share of Common Stock:
Basic	$	3.46		$	3.56		$	2.87
Diluted	$	3.45		$	3.55		$	2.86
Cash Dividends Declared Per Share of Common Stock	$	1.4350		$	1.2800		$	1.2025

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 49

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Comprehensive Income
	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Net Income	$	56,580		$	58,124		$	44,675
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(22), $(31) and $(29), respectively	(55		)	(46		)	(48		)
Net (loss)/gain, net of tax of $(49), $432, and $178, respectively	(108		)	663			268
Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(555), $(8) and $496, respectively	(1,371		)	(11		)	742
Total Other Comprehensive Income (Loss)	(1,534		)	606			962
Comprehensive Income	$	55,046		$	58,730		$	45,637

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

Chesapeake Utilities Corporation 2018 Form 10-K Page 50

Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets
	As of December 31,
Assets	2018			2017
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,297,416		$	1,073,736
Unregulated Energy	237,682			210,682
Other businesses and eliminations	34,585			27,699
Total property, plant and equipment	1,569,683			1,312,117
Less: Accumulated depreciation and amortization	(294,295		)	(270,599		)
Plus: Construction work in progress	108,584			84,509
Net property, plant and equipment	1,383,972			1,126,027
Current Assets
Cash and cash equivalents	6,089			5,614
Accounts receivable (less allowance for uncollectible accounts of $1,108 and $936, respectively)	85,404			77,223
Accrued revenue	27,499			22,279
Propane inventory, at average cost	9,791			8,324
Other inventory, at average cost	7,127			12,022
Regulatory assets	4,796			10,930
Storage gas prepayments	6,603			5,250
Income taxes receivable	15,300			14,778
Prepaid expenses	10,079			13,621
Derivative assets, at fair value	13,165			1,286
Other current assets	5,684			7,260
Total current assets	191,537			178,587
Deferred Charges and Other Assets
Goodwill	25,837			19,604
Other intangible assets, net	6,207			4,686
Investments, at fair value	6,711			6,756
Regulatory assets	72,422			75,575
Receivables and other deferred charges	6,985			3,699
Total deferred charges and other assets	118,162			110,320
Total Assets	$	1,693,671		$	1,414,934

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 51

Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets
	As of December 31,
Capitalization and Liabilities	2018			2017
(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)	7,971			7,955
Additional paid-in capital	255,651			253,470
Retained earnings	261,530			229,141
Accumulated other comprehensive loss	(6,713		)	(4,272		)
Deferred compensation obligation	3,854			3,395
Treasury stock	(3,854		)	(3,395		)
Total stockholders’ equity	518,439			486,294
Long-term debt, net of current maturities	316,020			197,395
Total capitalization	834,459			683,689
Current Liabilities
Current portion of long-term debt	11,935			9,421
Short-term borrowing	294,458			250,969
Accounts payable	129,804			74,688
Customer deposits and refunds	34,155			34,751
Accrued interest	2,317			1,742
Dividends payable	6,060			5,312
Accrued compensation	13,923			13,112
Regulatory liabilities	7,883			6,485
Derivative liabilities, at fair value	14,871			6,247
Other accrued liabilities	12,828			10,273
Total current liabilities	528,234			413,000
Deferred Credits and Other Liabilities
Deferred income taxes	156,820			135,850
Regulatory liabilities	135,039			140,978
Environmental liabilities	7,638			8,263
Other pension and benefit costs	28,513			29,699
Deferred investment tax credits and other liabilities	2,968			3,455
Total deferred credits and other liabilities	330,978			318,245
Environmental and other commitments and contingencies (Note 20 and 21)
Total Capitalization and Liabilities	$	1,693,671		$	1,414,934

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

Chesapeake Utilities Corporation 2018 Form 10-K Page 52

Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Cash Flows
	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Operating Activities
Net Income	$	56,580		$	58,124		$	44,675
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	40,802			36,599			32,159
Depreciation and accretion included in operations expenses	8,535			8,122			7,334
Deferred income taxes, net	21,226			11,085			31,257
Realized loss on sale of assets/investments/commodity contracts	5,497			3,179			695
Unrealized loss (gain) on investments/commodity contracts	429			(1,001		)	(385		)
Employee benefits and compensation	856			1,577			1,887
Share-based compensation	2,813			2,490			2,367
Other, net	—			(750		)	(79		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(16,311		)	(19,506		)	(27,013		)
Propane inventory, storage gas and other inventory	2,107			(9,036		)	(2,531		)
Regulatory assets/liabilities, net	2,250			(2,855		)	(7,523		)
Prepaid expenses and other current assets	(7,421		)	(7,001		)	(1,387		)
Accounts payable and other accrued liabilities	35,907			15,596			19,599
Income taxes receivable (payable)	(522		)	8,110			2,466
Customer deposits and refunds	(596		)	5,513			2,065
Accrued compensation	708			2,488			358
Other assets and liabilities, net	(6,082		)	(2,645		)	(1,803		)
Net cash provided by operating activities	146,778			110,089			104,141
Investing Activities
Property, plant and equipment expenditures	(269,767		)	(175,329		)	(169,861		)
Proceeds from sale of assets	782			708			174
Acquisitions, net of cash acquired	(16,654		)	(11,945		)	—
Environmental expenditures	(625		)	(329		)	(350		)
Net cash used in investing activities	(286,264		)	(186,895		)	(170,037		)
Financing Activities
Common stock dividends	(22,043		)	(19,928		)	(17,482		)
Issuance of stock for Dividend Reinvestment Plan	(706		)	89			811
Proceeds from issuance of common stock, net of expenses	—			(10		)	57,360
Tax withholding payments related to net settled stock compensation	(1,210		)	(692		)	(770		)
Change in cash overdrafts due to outstanding checks	(5,943		)	1,738			3,920
Net borrowing under line of credit agreements	49,432			39,338			32,526
Proceeds from issuance of long-term debt	154,819			69,807			—
Repayment of long-term debt and capital lease obligation	(34,388		)	(12,100		)	(9,146		)
Net cash provided by financing activities	139,961			78,242			67,219
Net Increase in Cash and Cash Equivalents	475			1,436			1,323
Cash and Cash Equivalents — Beginning of Period	5,614			4,178			2,855
Cash and Cash Equivalents — End of Period	$	6,089		$	5,614		$	4,178

Supplemental Cash Flow Disclosures (see Note 7)

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 53

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, 2015	15,270,659	$	7,432	$	190,311		$	166,235		$	(5,840	)	$	1,883	$	(1,883	)	$	358,138
Net Income	—	—		—			44,675			—			—		—			44,675
Other comprehensive loss	—	—		—			—			962			—		—			962
Dividends declared ($1.2025 per share)	—	—		—			(18,848		)	—			—		—			(18,848		)
Retirement savings plan and dividend reinvestment plan	36,253	17		2,225			—			—			—		—			2,242
Stock issuance (3)	960,488	467		56,893			—			—			—		—			57,360
Share-based compensation and tax benefit (4) (5)	36,099	19		1,538			—			—			—		—			1,557
Treasury stock activities(2)	—	—		—			—			—			533		(533		)	—
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

⁽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 Statements of Stockholders’ Equity. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and at their discretion.

⁽²⁾ Includes 97,053, 90,961 and 76,745 shares at December 31, 2018, 2017 and 2016, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

⁽³⁾ On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

⁽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 2018, 2017 and 2016, we withheld 10,436, 10,269 and 12,031shares, respectively, for taxes.

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

Chesapeake Utilities Corporation 2018 Form 10-K Page 54

Notes to the Consolidated Financial Statements

1. ORGANIZATIONAND BASISOF 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 natural gas marketing operation providing natural gas supply directly to commercial and industrial customers in Florida, Delaware, Maryland, Pennsylvania, Ohio and other states; (c) our unregulated natural gas transmission/supply operation in central and eastern Ohio; (d) our CHP plant in Florida that generates electricity and steam; and (e) our newest subsidiary, based in Florida, that provides mobile compressed natural gas ("CNG") utility and pipeline solutions to commercial, industrial and other utility customers throughout the Southeast and Midwest portions of the country.

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.

We reclassified certain amounts in the consolidated statement of income for the years ended December 31, 2017 and 2016 to conform to the current year’s presentation.

2. SUMMARYOF 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 by classification as of December 31, 2018 and 2017 is provided in the following table:

Chesapeake Utilities Corporation 2018 Form 10-K     Page 55

Notes to the Consolidated Financial Statements

	As of December 31,
(in thousands)	2018			2017
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	657,630		$	589,149
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	537,654			384,360
Electric distribution – Florida	102,133			100,227
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	123,632			108,177
Natural gas transmission – Ohio	70,225			66,037
Electricity and Steam generation – Florida	35,239			35,239
Mobile CNG utility and pipeline solutions	7,240			—
Other unregulated energy	1,346			1,229
Other	34,584			27,699
Total property, plant and equipment	1,569,683			1,312,117
Less: Accumulated depreciation and amortization	(294,295		)	(270,599		)
Plus: Construction work in progress	108,584			84,509
Net property, plant and equipment	$	1,383,972		$	1,126,027

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, 2018, 2017 and 2016, the non-refundable contributions totaled $2.8 million, $2.1 million and $1.0 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 year ended December 31, 2018, AFUDC totaled $1.9 million, which was reflected as a reduction of interest charges. During the years ended December 31, 2017 and 2016, AFUDC was not material.

Assets Used in Leases

Property, plant and equipment for the Florida natural gas transmission operation included $1.4 million of assets, at December 31, 2018 and 2017, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a 20-year term. Accumulated depreciation for these assets totaled $720,000 and $652,000 at December 31, 2018 and 2017, respectively.

Capital Lease Assets

Property, plant and equipment include capital lease assets related to: (i) a lease arrangement entered into by our Delmarva Peninsula natural gas distribution operation associated with Sandpiper's capacity, supply and operating agreement and (ii) our Mid-Atlantic propane operation's lease arrangement for property in Anne Arundel County Maryland which it intends to purchase during the first quarter of 2019. Information regarding the impact of the capital leases in our financial statements is shown below. Additional information can be found in Note 21, Other Commitments and Contingencies.

Chesapeake Utilities Corporation 2018 Form 10-K Page 56

Notes to the Consolidated Financial Statements

	As of December 31,
(in thousands)	2018		2017
Fair value of asset at lease inception	$	7,816	$	7,126
Less: Accumulated amortization	6,506		5,056
Capital lease asset	$	1,310	$	2,070

	For the years ended December 31,
(in thousands)	2018	2017	2016
Amortization included in fuel cost recovery mechanism	$1,451	$1,401	$1,353

Jointly-owned Pipeline

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2018 and 2017, 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 the operating expenses of the income statement. Accumulated depreciation for this pipeline totaled $1.4 million and $1.3 million, at December 31, 2018 and 2017, respectively.

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.

In May 2016, we received $650,000 in cash pursuant to a settlement agreement with a vendor related to implementation of a customer billing system which is reflected as "Gain from a settlement" in the accompanying consolidated statements of income. The retention of this amount is contingent upon engaging this vendor to provide agreed-upon services through May 2020.

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, 2018, 2017 and 2016:

	2018	2017	2016
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.8%	2.7%
Natural gas transmission – Florida	2.3%	3.5%	3.9%
Electric distribution – Florida	3.4%	3.4%	3.5%

Chesapeake Utilities Corporation 2018 Form 10-K     Page 57

Notes to the Consolidated Financial Statements

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

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

We report certain depreciation and accretion in operations expense, rather than as a depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2018, 2017 and 2016, we reported $8.5 million, $8.1 million and $7.3 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. Eastern Shore’s revenues are based on rates approved by the FERC. 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. 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.

Chesapeake Utilities Corporation 2018 Form 10-K Page 58

Notes to the Consolidated Financial Statements

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.

For the unregulated propane operation business, we record revenue in the period the products are delivered and/or services are rendered for bulk delivery customers without meters. For propane customers with meters and natural gas marketing customers 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 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.

Our natural gas marketing operation recognizes revenue based on the volume of natural gas delivered to its customers.

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

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, the level of 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 2018, 2017 or 2016.

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 2018, 2017 and 2016 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.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 59

Notes to the Consolidated Financial Statements

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 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 reviewed periodically and is based on the actuarial table that best reflects of 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. Our natural gas marketing

Chesapeake Utilities Corporation 2018 Form 10-K Page 60

Notes to the Consolidated Financial Statements

operation enters into natural gas futures and swap contracts to mitigate any price risk associated with the purchase and/or sale of natural gas to specific customers. 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, call option or natural gas futures contract, 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 and natural gas marketing 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 marketing operations 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

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of adoption of the new revenue standard was immaterial to our net income.

This standard required entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration that the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 5, Revenue Recognition, for additional information.

The following highlights the impact of the adoption of ASC 606 on our income statement for the year ended December 31, 2018 and consolidated balance sheet as of December 31, 2018:

	Year Ended   December 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	345,281	$	346,289	$	(1,008	)
Regulated Energy cost of sales	121,828		122,463		(635		)
Depreciation and amortization	40,802		40,767		35
Income before income taxes	77,574		77,981		(407		)
Income taxes	20,994		21,106		(112		)
Net income	56,580		56,875		(295		)

Chesapeake Utilities Corporation 2018 Form 10-K     Page 61

Notes to the Consolidated Financial Statements

	As of December 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenue	$	27,499	$	29,461	$	(1,962	)
Long-term receivables and other deferred charges	$	6,985	$	6,816	$	169
Capitalization
Retained earnings	$	261,530	$	263,323	$	(1,793	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in operating income during the year ended December 31, 2018, to future years, and a cumulative adjustment that decreased retained earnings and other assets by $1.8 million at December 31, 2018, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included in operating expenses. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the other components of net benefit costs, retrospectively. As our plans have been frozen for some time, there is no service cost component. The components of net benefit costs have been reclassified to other expense. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 16, Stockholders' Equity, for additional information.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. We adopted ASU 2017-12, effective July 1, 2018, with no material impact on our financial statements. See Note 8, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU

Chesapeake Utilities Corporation 2018 Form 10-K Page 62

Notes to the Consolidated Financial Statements

2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021, although early adoption is permitted. We early adopted and updated our disclosures during the annual period ended December 31, 2018. Since the guidance impacted disclosures only, there was no impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

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 ("ROU") model that requires a lessee to recognize a ROU 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; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019, and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the respective lease components.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $11.0 to $13.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

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. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not 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. Since the changes only impact disclosures, there will be no financial impact.

3. EARNINGS PER SHARE

The following table presents the calculation of our basic and diluted earnings per share for the years ended December 31:

Chesapeake Utilities Corporation 2018 Form 10-K     Page 63

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
	2018		2017		2016
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Weighted average shares outstanding	16,369,616		16,336,789		15,570,539
Basic Earnings Per Share	$	3.46	$	3.56	$	2.87
Calculation of Diluted Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,369,616		16,336,789		15,570,539
Effect of dilutive securities — Share-based compensation	50,254		46,563		42,552
Adjusted denominator — Diluted	16,419,870		16,383,352		15,613,091
Diluted Earnings Per Share	$	3.45	$	3.55	$	2.86

4. ACQUISITIONS

Acquisitions in 2018

Marlin Gas Services and Ohl Fuel Oil Acquisitions

In December 2018, Marlin Gas Services, LLC (“Marlin Gas Services”), our newly created subsidiary, acquired certain operating assets of Marlin Gas Transport, Inc. (“Marlin Gas Transport”), a supplier of mobile compressed natural gas utility and pipeline solutions. The acquisition will enable Chesapeake Utilities to offer solutions to address supply interruption scenarios and tailor other alternatives where pipeline supplies are not available or cannot meet customer requirements.

In December 2018, Sharp acquired certain propane operating assets and customers of R. F. Ohl Fuel Oil, Inc. ("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 $18.4 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. The amounts recorded in conjunction with these acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period. Due to the timing of these acquisitions, the revenue and net income from these acquisitions in 2018 were immaterial.

Acquisitions in 2017

ARM, Chipola and Central Gas Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM Energy Management, LLC ("ARM"). The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $4.3 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on a projection that the acquired business would achieve a gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our consolidated financial statements. Based on actual gross margin results in 2018, we were not required to make additional payments under the contingent consideration provisions of the purchase agreement.

In August and December of 2017, Flo-gas acquired certain operating assets of Chipola Propane Gas Company ("Chipola") and Central Gas Company of Okeechobee, Incorporated ("Central Gas"), adding approximately 1,125 residential and commercial propane delivery service customers in Florida.

The acquisition accounting amounts recorded in conjunction with the above transactions are final. The revenue and net income from these acquisitions included in our consolidated statements of income were not material.

Chesapeake Utilities Corporation 2018 Form 10-K Page 64

Notes to the Consolidated Financial Statements

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 our revenue by major source based on product and service type for the twelve months endedDecember 31, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	70,338		$	—		$	—		$	70,338
Florida natural gas division	25,341			—			—			25,341
FPU electric distribution	79,803			—			—			79,803
FPU natural gas distribution	81,118			—			—			81,118
Maryland natural gas division	24,172			—			—			24,172
Sandpiper natural gas/propane operations	22,088			—			—			22,088
Total energy distribution	302,860			—			—			302,860
Energy transmission
Aspire Energy	—			35,407			—			35,407
Eastern Shore	64,248			—			—			64,248
Peninsula Pipeline	11,927			—			—			11,927
Total energy transmission	76,175			35,407			—			111,582
Energy generation
Eight Flags	—			17,302			—			17,302
Propane operations
Mid-Atlantic propane operations	—			102,321			—			102,321
Florida propane operations	—			21,282			—			21,282
Total propane operations	—			123,603			—			123,603
Energy services
Marlin Gas Services	—			121			—			121
PESCO - Natural Gas Marketing	—			258,713			—			258,713
	—			258,834			—			258,834
Other and eliminations
Eliminations	(33,754		)	(16,486		)	(49,062		)	(99,302		)
Other	—			1,957			653			2,610
Total other and eliminations	(33,754		)	(14,529		)	(48,409		)	(96,692		)
Total operating revenues (1)	$	345,281		$	420,617		$	(48,409	)	$	717,489

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $236,000 and $334,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Chesapeake Utilities Corporation 2018 Form 10-K Page 65

Notes to the Consolidated Financial Statements

Regulated Energy Segment

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

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

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

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

Unregulated Energy Segment

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

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

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

PESCO provides natural gas supply and asset management services to customers (including affiliates of Chesapeake Utilities) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on monthly customer meter readings. We accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period.

Chesapeake Utilities Corporation 2018 Form 10-K Page 66

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, 2018 and 2017 were as follows:

	Trade Receivables		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962	$	1,270	$	407
Balance at 12/31/2018	83,214		2,614		480
Increase (decrease)	$	8,252	$	1,344	$	73

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. At December 31, 2018 and 2017, we had a contract liability of $480,000 and $407,000, respectively, which was included in other accrued liabilities in the consolidated balance sheet, and which relates to non-refundable prepaid fixed fees for our Mid-Atlantic propane operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the twelve months endedDecember 31, 2018, we recognized revenue of $697,000.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2018 are expected to be recognized as follows:

(in thousands)	2019		2020		2021		2022		2023		2024 and thereafter
Eastern Shore and Peninsula Pipeline	$	38,505	$	36,768	$	33,510	$	26,566	$	21,146	$	212,620
Natural gas distribution operations	4,109		3,586		3,358		3,320		2,924		30,826
PESCO - Natural Gas Marketing	8,886		4,702		1,728		23		—		—
FPU electric distribution	297		297		297		109		—		—
Total revenue contracts with remaining performance obligations	$	51,797	$	45,353	$	38,893	$	30,018	$	24,070	$	243,446

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 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 2018 Form 10-K Page 67

Notes to the Consolidated Financial Statements

• Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, the new mobile CNG utility and pipeline solutions subsidiary, and other energy services (natural gas marketing and related services). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that wound down its operations shortly after the first quarter of 2017. 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.

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,
	2018			2017			2016
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	332,749		$	316,971		$	302,402
Unregulated Energy	384,740			300,612			196,458
Total operating revenues, unaffiliated customers	$	717,489		$	617,583		$	498,860
Intersegment Revenues(1)
Regulated Energy	$	12,532		$	9,339		$	3,287
Unregulated Energy	35,877			23,983			7,321
Other businesses	653			774			880
Total intersegment revenues	$	49,062		$	34,096		$	11,488
Operating Income
Regulated Energy	$	79,215		$	74,584		$	71,515
Unregulated Energy	16,901			12,631			14,066
Other businesses and eliminations	(1,496		)	205			402
Operating Income	94,620			87,420			85,983
Other expense	(615		)	(2,342		)	(2,328		)
Interest charges	16,431			12,645			10,639
Income Before Income taxes	77,574			72,433			73,016
Income taxes	20,994			14,309			28,341
Net Income	$	56,580		$	58,124		$	44,675
Depreciation and Amortization
Regulated Energy	$	31,876		$	28,554		$	25,677
Unregulated Energy	8,845			7,954			6,386
Other businesses and eliminations	81			91			96
Total depreciation and amortization	$	40,802		$	36,599		$	32,159
Capital Expenditures
Regulated Energy	$	235,912		$	159,011		$	139,994
Unregulated Energy	38,700			26,190			23,984
Other businesses	8,364			5,902			5,398
Total capital expenditures	$	282,976		$	191,103		$	169,376

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

Chesapeake Utilities Corporation 2018 Form 10-K Page 68

Notes to the Consolidated Financial Statements

	As of December 31,
	2018		2017
Identifiable Assets
Regulated Energy	$	1,345,805	$	1,121,673
Unregulated Energy	306,045		259,041
Other businesses	41,821		34,220
Total identifiable assets	$	1,693,671	$	1,414,934

Our operations are entirely domestic.

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2018, 2017 and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017			2016
(in thousands)
Cash paid for interest	$	16,741	$	12,420		$	10,315
Cash paid for income taxes, net of refunds	$	477	$	(4,114	)	$	(5,308	)

Non-cash investing and financing activities during the years ended December 31, 2018, 2017, and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017		2016
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	39,402	$	15,457	$	9,791
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	777
Common stock issued under the SICP	$	2,006	$	1,127	$	1,027
Capital lease obligation	$	1,310	$	2,070	$	3,471

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 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. Both our propane operations and our natural gas marketing 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, 2018 and 2017 our natural gas and electric distribution operations did not have any outstanding derivative contracts.

We adopted ASU 2017-12 as of July 1, 2018. See Note 1, Summary of Significant Accounting Policies, under the heading "recently adopted accounting standards" for additional details.

Volume of Derivative Activity

As of December 31, 2018, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO/natural gas marketing	Natural gas (Dts)	14.4	Cash flows hedges	March 2022
PESCO/natural gas marketing	Natural gas (Dts)	3.8	Not designated	December 2020
Sharp/propane operations	Propane (gallons)	9.7	Cash flows hedges	June 2021
Sharp/propane operations	Propane (gallons)	0.3	Fair value hedges	March 2019

Chesapeake Utilities Corporation 2018 Form 10-K     Page 69

Notes to the Consolidated Financial Statements

PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts 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 loss to earnings during the next 12-month period ending December 31, 2019.

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 August 2018 through June 2021) 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 $1.2 million from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2019.

Balance sheet offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payables on a gross and net basis at December 31, 2018 and 2017:

	At December 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	12,368	$	3,834	$	8,534
Accounts payable	$	24,741	$	3,834	$	20,907

	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252

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 maintain separate broker margin accounts for Sharp and PESCO. At December 31, 2018 and 2017, Sharp's account had a zero balance. The balances related to PESCO are as follows:

(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
PESCO	Other Current Assets	$	2,810	$	6,300

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2018 and 2017 are as follows:

Chesapeake Utilities Corporation 2018 Form 10-K Page 70

Notes to the Consolidated Financial Statements

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	4,024		—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	71		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	9,059		92
Propane swap agreements	Derivative assets, at fair value	11		1,181
Total Derivative Assets		$	13,165	$	1,286

	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	4,562	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	8,705		—
Natural gas swap contracts	Derivative liabilities, at fair value	—		469
Propane swap agreements	Derivative liabilities, at fair value	1,604		2
Total Derivative Liabilities		$	14,871	$	6,247

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)		2018			2017			2016
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts and options (1)	Revenue	$	—		$	112		$	(546	)
Natural gas futures contracts	Cost of sales	(3,189		)	(3,633		)	(541		)
Propane swap agreements	Cost of sales	(13		)	8			7
Natural gas swap contracts	Cost of sales	—			1			—
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			(9		)	49
Natural gas futures contracts	Natural gas inventory	—			—			(233		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(647		)	1,607			(364		)
Propane swap agreements	Other comprehensive income (loss)	(2,773		)	487			1,016
Natural gas futures contracts	Cost of sales	(2,010		)	(456		)	345
Natural gas swap contracts	Cost of sales	197			(822		)	—
Natural gas futures contracts	Other comprehensive income (loss)	532			(1,476		)	222
Natural gas swap contracts	Other comprehensive income	200			986			—
Total		$	(7,703	)	$	(3,195	)	$	(45	)

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

As of December 31, 2018, the following amounts were recorded in the consolidated balance sheets related to fair value hedges:

Chesapeake Utilities Corporation 2018 Form 10-K     Page 71

Notes to the Consolidated Financial Statements

(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At December 31, 2018		At December 31, 2017		At December 31, 2018		At December 31, 2017
Inventory	$	212	$	—	$	—	$	—

9. FAIR VALUEOF 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 values of forward contracts are measured using market transactions in either the listed or over-the-counter markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts 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, 2018 and 2017, respectively:

			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	13,165		—		13,165		—
Total assets	$	19,876	$	6,025	$	13,165	$	686
Liabilities:
Derivative liabilities	$	14,871	$	—	$	14,871	$	—

Chesapeake Utilities Corporation 2018 Form 10-K Page 72

Notes to the Consolidated Financial Statements

			Fair Value Measurements Using:
As of December 31, 2017	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	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	68			79
Transfers/disbursements	(41		)	(53		)
Investment income	11			61
Ending Balance	$	686		$	648

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

At December 31, 2018 and 2017, 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 and 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, 2018, long-term debt, which includes the current maturities but excludes capital lease obligations, had a carrying value of $327.2 million, compared to the estimated fair value of $323.8 million, 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, adjusted for duration, optionality and risk profile. At December 31, 2017, long-term debt, which includes the current maturities but excludes a capital lease obligation, had a carrying value of $205.2 million, compared to a fair value of $215.4 million. 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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 73

Notes to the Consolidated Financial Statements

The investment balances at December 31, 2018 and 2017, consisted of the following:

	As of December 31,
(in thousands)	2018		2017
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	6,689	$	6,734
Investments in equity securities	22		22
Total	$	6,711	$	6,756

We classify these investments as trading securities and report them at their fair value. For the year ended December 31, 2018, we recorded net unrealized losses of $428,000 and for the years ended December 31, 2017 and 2016, we recorded net unrealized gains of $1.0 million and $379,000, respectively, in other income (expense) in the consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

11. GOODWILLAND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2018 and 2017 was as follows:

	As of December 31,
(in thousands)	2018		2017
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy
Mid-Atlantic Propane Operations	2,147		674
Florida Propane Operations	1,188		1,188
Aspire Energy	10,119		10,119
Marlin Gas Services	4,760		—
Natural Gas Marketing - PESCO	4,270		4,270
Total Goodwill	$	25,837	$	19,604

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

The annual impairment testing for 2018 and 2017 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2018 and 2017 are as follows:

	As of December 31,
	2018				2017
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	7,757	$	3,664	$	7,393	$	2,880
Non-Compete agreements	2,245		202		270		175
Other	270		199		270		192
Total	$	10,272	$	4,065	$	7,933	$	3,247

The customer lists, non-compete agreements and other intangibles acquired in the purchases of the operating assets of several companies are being amortized over five to 41 years.

For the years ended December 31, 2018, 2017 and 2016, amortization expense of intangible assets was $818,000, $537,000, and $380,000, respectively. Amortization expense of intangible assets is expected to be $1.1 million for each of the years 2019, 2020 and 2021, $820,000 for 2022 and $813,000 for 2023.

Chesapeake Utilities Corporation 2018 Form 10-K Page 74

Notes to the Consolidated Financial Statements

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, 2018, the 2015 and 2016 federal income tax returns are under examination, and no report has been issued at this time.

We had no net operating loss for federal income tax purposes as of December 31, 2018 and 2017. For state income tax purposes, we had net operating losses in various states of $60.1 million and $34.2 million as of December 31, 2018 and 2017, respectively, almost all of which will expire in 2037. We have recorded deferred tax assets of $2.0 million and $1.6 million related to state net operating loss carry-forwards at December 31, 2018 and 2017, 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 are effective for taxable years beginning on or after January 1, 2018. The provisions significantly impacting 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. We have completed the assessment of the impact as it relates to 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 2018, 2017, and 2016; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2018, 2017, and 2016; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2018 and 2017.

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Current Income Tax Expense
Federal	$	(845	)	$	2,803		$	(4,898	)
State	660			492			2,053
Other	(47		)	(71		)	(71		)
Total current income tax expense	(232		)	3,224			(2,916		)
Deferred Income Tax Expense (1)
Property, plant and equipment	19,164			8,314			31,062
Deferred gas costs	(1,435		)	2,002			1,163
Pensions and other employee benefits	463			180			237
FPU merger-related premium cost and deferred gain	(528		)	(1,148		)	(572		)
Net operating loss carryforwards	(331		)	193			(9		)
Other	3,893			1,544			(624		)
Total deferred income tax expense	21,226			11,085			31,257
Total Income Tax Expense	$	20,994		$	14,309		$	28,341

⁽¹⁾ Includes $3.5 million, $873,000 and $2.1 million of deferred state income taxes for the years 2018, 2017 and 2016, respectively.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 75

Notes to the Consolidated Financial Statements

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	16,291		$	25,351		$	22,759
State income taxes, net of federal benefit	4,088			1,894			3,422
ESOP dividend deduction	(158		)	(257		)	(264		)
Revaluation of deferred tax assets and liabilities	—			(14,299		)	—
Other	773			1,620			2,424
Total Income Tax Expense	$	20,994		$	14,309		$	28,341
Effective Income Tax Rate (2)	27.06		%	19.75		%	38.81		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2018 and 35 percent for 2017 and 2016.

⁽²⁾Effective tax rate 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,
	2018		2017
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	153,423	$	133,581
Acquisition adjustment	8,896		9,323
Loss on reacquired debt	32		153
Deferred gas costs	1,139		2,574
Natural gas conversion costs	3,987		2,760
Other	2,641		2,662
Total deferred income tax liabilities	170,118		151,053
Deferred income tax assets:
Pension and other employee benefits	3,711		4,698
Environmental costs	1,710		1,744
Net operating loss carryforwards	2,010		1,625
Self-insurance	151		164
Storm reserve liability	—		717
Other	5,716		6,255
Total deferred income tax assets	13,298		15,203
Deferred Income Taxes Per Consolidated Balance Sheets	$	156,820	$	135,850

Chesapeake Utilities Corporation 2018 Form 10-K Page 76

Notes to the Consolidated Financial Statements

13. LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,986		$	7,982
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	4,000			6,000
5.93% note, due October 31, 2023	15,000			18,000
5.68% note, due June 30, 2026	23,200			26,100
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			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			—
3.58% note, due November 30, 2038	50,000			—
Term Note due January 21, 2020 (1)	30,000			—
Promissory notes	26			97
Capital lease obligations	1,310			2,070
Less: debt issuance costs	(567		)	(433		)
Total long-term debt	327,955			206,816
Less: current maturities	(11,935		)	(9,421		)
Total long-term debt, net of current maturities	$	316,020		$	197,395

⁽¹⁾ In December of 2018 we issued a $30.0 million unsecured Term Note through PNC Bank N.A. The maturity date of the Term Note is January 21, 2020. The Term Note bears interest at a rate equal to the one month LIBOR rate plus 75 basis points. The interest rate at December 31, 2018 was 3.23%

Annual maturities

Annual maturities and principal repayments of long-term debt, excluding the capital lease obligation, are as follows:

Year	2019		2020		2021		2022		2023		Thereafter		Total
(in thousands)
Payments	$	10,626	$	45,600	$	13,600	$	25,100	$	20,600	$	211,700	$	327,226

See Note 15, Lease Obligations, for future payments related to the capital lease obligation.

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 percent unsecured debt in April 2017. The Prudential Shelf Agreement was amended in September 2018 to increase the borrowing capacity to $150.0 million after which Prudential accepted our request to purchase our unsecured debt of $100.0 million at an interest rate of 3.98 percent on or before August 20, 2019. The NYL Shelf Agreement totaling $100.0 million was entered 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, 2018, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 77

Notes to the Consolidated Financial Statements

The following table summarizes our shelf agreements borrowing information at December 31, 2018:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments			Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

The Prudential Shelf Agreement and the NYL Shelf Agreement 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.

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, 2018, FPU’s cumulative net income base was $155.8 million, offset by restricted payments of $37.6 million, leaving $118.2 million of available dividend capacity.

The dividend restrictions in FPU’s first mortgage bonds resulted in approximately $42.2 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2018. This represents approximately 8.1 percent 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

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 in December 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50.0 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2018, the cumulative consolidated net income base was $444.3 million, offset by restricted payments of $201.5 million, leaving $242.8 million of cumulative net income free of restrictions. As of December 31, 2018, we are in compliance with all of our debt covenants.

14. SHORT-TERM BORROWINGS

At December 31, 2018 and 2017, we had $294.5 million and $251.0 million, respectively, of short-term borrowings outstanding at the weighted average interest rates of 3.44 percent and 2.42 percent, respectively. We have an aggregate of $370.0 million in credit lines comprised of five 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 on October 31, 2019 with the exception of the Revolver which is available through October 8, 2020. We incurred commitment fees of $93,300, $131,000 and $145,000 in 2018, 2017 and 2016, respectively. The following table summarizes our short-term borrowing facilities information at December 31, 2018 and 2017.

Chesapeake Utilities Corporation 2018 Form 10-K Page 78

Notes to the Consolidated Financial Statements

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2018		December 31, 2017		Available at December 31, 2018
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 1.00 percent	$	25,000	$	55,000	$	30,000
Committed revolving credit facility B	30,000		plus 1.00 percent	15,431		20,500		14,569
Short-term revolving credit note C	50,000		plus 0.80 percent	50,000		50,000		—
Committed revolving credit facility D	45,000		plus 0.85 percent	34,672		40,171		10,328
Committed revolving credit facility E	40,000		plus 0.85 percent	40,000		—		—
Committed revolving credit facility F(2)	150,000		plus up to 1.25 percent	125,000		75,000		25,000
Total short term credit facilities	$	370,000		$	290,103	$	240,671	$	79,897
Book overdrafts(1)				4,355		10,298
Total short-term borrowing				$	294,458	$	250,969

.

⁽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 $200.0 million.

We are authorized by our Board of Directors to borrow up to $350.0 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. We are in compliance with all of our debt covenants.

15. LEASE OBLIGATIONS

We have entered into several operating lease arrangements for office space, land, equipment and pipeline facilities. Rent expense related to these leases for 2018, 2017 and 2016 was $3.8 million, $3.6 million and $2.5 million, respectively. As of December 31, 2018, future minimum payments under our current lease agreements are as follows:

Year(s)	2019	2020	2021	2022	2023	Thereafter	Total
(in thousands)
Expected payments	$2,349	$1,998	$1,761	$1,689	$1,642	$5,398	$14,837

For the years ended December 31, 2018, 2017 and 2016 we paid $2.4 million ,$1.5 million and $1.5 million respectively, for capital lease arrangements related to Sandpiper's capacity, supply and operating agreement and our Mid-Atlantic propane operations' lease arrangement for property in Anne Arundel County, Maryland which it intends to purchase during the first quarter of 2019. Future minimum payments under these lease arrangements are $1.3 million in 2019.

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 79

Notes to the Consolidated Financial Statements

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 table present the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2018 and 2017. All amounts in the following tables are presented net of tax.

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contracts Cash Flow Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income before reclassifications	281			159			440
Amounts reclassified from accumulated other comprehensive income/(loss)	336			(170		)	166
Net current-period other comprehensive income/(loss)	617			(11		)	606
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	)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016. 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)	2018			2017			2016
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(579		)	(636		)	(871		)
Total before income taxes	(502		)	(559		)	(794		)
Income tax benefit	63			223			320
Net of tax	$	(439	)	$	(336	)	$	(474	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(647	)	$	1,607		$	(322	)
Natural gas swaps (2)	197			(822		)	—
Natural gas futures (2)	(2,010		)	(456		)	345
Total before income taxes	(2,460		)	329			23
Income tax impact	701			(159		)	(3		)
Net of tax	$	(1,759	)	$	170		$	20
Total reclassifications for the period	$	(2,198	)	$	(166	)	$	(454	)

⁽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.

Amortization of defined benefit pension and postretirement plan items is included in other expense, net and gains and losses on propane swap agreements, call options and natural gas futures contracts are included in cost of sales in the accompanying

Chesapeake Utilities Corporation 2018 Form 10-K Page 80

Notes to the Consolidated Financial Statements

consolidated statements of income. 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.

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 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, 2018 and 2017, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedule sets forth the funded status at December 31, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017 and 2016 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2018			2017			2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,443		$	11,355		$	64,664		$	63,832		$	2,428		$	2,428
Interest cost	384			402			2,339			2,482			83			89
Actuarial loss (gain)	(610		)	454			(4,739		)	1,199			(74		)	63
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Benefit obligation — end of year	10,712			11,443			59,377			64,664			2,285			2,428
Change in plan assets:
Fair value of plan assets — beginning of year	9,350			8,668			48,396			43,272			—			—
Actual return on plan assets	(647		)	1,144			(3,113		)	6,025			—			—
Employer contributions	451			306			1,205			1,948			152			152
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Fair value of plan assets — end of year	8,649			9,350			43,601			48,396			—			—
Reconciliation:
Funded status	(2,063		)	(2,093		)	(15,776		)	(16,268		)	(2,285		)	(2,428		)
Accrued pension cost	$	(2,063	)	$	(2,093	)	$	(15,776	)	$	(16,268	)	$	(2,285	)	$	(2,428	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%	4.00		%	3.50		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%	—		%	—		%

Chesapeake Utilities Corporation 2018 Form 10-K     Page 81

Notes to the Consolidated Financial Statements

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic pension cost:
Interest cost	$	384		$	402		$	421		$	2,339		$	2,482		$	2,525		$	83		$	89		$	91
Expected return on assets	(542		)	(495		)	(501		)	(3,091		)	(2,779		)	(2,702		)	—			—
Amortization of actuarial loss	343			399			459			404			513			519			101			87			87
Settlement expense	—			—			161			—			—			—
Net periodic pension cost(1)	185			306			540			(348		)	216			342			184			176			178
Amortization of pre-merger regulatory asset	—			—			—			761			761			761			—			—			—
Total periodic cost	$	185		$	306		$	540		$	413		$	977		$	1,103		$	184		$	176		$	178
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	6.50		%	—		%	—		%	—		%

(1) As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the consolidated statements of income.

Included in the net periodic costs for the FPU Pension Plan is continued 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. The unamortized balance of this regulatory asset was $543,000 and $1.3 million at December 31, 2018 and 2017, respectively.

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 following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2018, 2017 and 2016:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2018		2017		2016		2018		2017		2016
Asset Category
Equity securities	49.02	%	52.70	%	52.93	%	50.04	%	55.17	%	53.18	%
Debt securities	40.98	%	37.79	%	37.64	%	41.06	%	36.56	%	37.74	%
Other	10.00	%	9.51	%	9.43	%	8.90	%	8.27	%	9.08	%
Total	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%

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 long-term investment return in excess of the growth of the plans’ retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain a diversified portfolio to reduce the risk of large losses.

Chesapeake Utilities Corporation 2018 Form 10-K Page 82

Notes to the Consolidated Financial Statements

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

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, 2018 and 2017, 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, 2018								At December 31, 2017
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)	$	3,399	$	—	$	—	$	3,399	$	4,245	$	—	$	—	$	4,245
U.S. Mid Cap (1)	1,478		—		—		1,478		1,775		—		—		1,775
U.S. Small Cap (1)	670		—		—		670		918		—		—		918
International (2)	9,226		—		—		9,226		11,916		—		—		11,916
Alternative Strategies (3)	5,726		—		—		5,726		5,528		—		—		5,528
	20,499		—		—		20,499		24,382		—		—		24,382
Mutual Funds - Debt securities
Fixed income (4)	18,630		—		—		18,630		18,454		—		—		18,454
High Yield (4)	2,818		—		—		2,818		2,772		—		—		2,772
	21,448		—		—		21,448		21,226		—		—		21,226
Mutual Funds - Other
Commodities (5)	1,902		—		—		1,902		2,154		—		—		2,154
Real Estate (6)	2,216		—		—		2,216		2,300		—		—		2,300
Guaranteed deposit (7)	—		—		627		627		—		—		436		436
	4,118		—		627		4,745		4,454		—		436		4,890
Total Pension Plan Assets in fair value hierarchy	$	46,065	$	—	$	627	46,692		$	50,062	$	—	$	436	50,498
Investments measured at net asset value (8)							5,558								7,248
Total Pension Plan Assets							$	52,250							$	57,746

⁽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.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 83

Notes to the Consolidated Financial Statements

⁽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, 2018 and 2017, 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, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Balance, beginning of year	$	436		$	498
Purchases	1,674			2,271
Transfers in	2,375			1,743
Disbursements	(3,872		)	(4,101		)
Investment income	14			25
Balance, end of year	$	627		$	436

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, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017, and 2016:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,128		$	1,132		$	1,287		$	1,349
Interest cost	38			41			47			50
Plan participants contributions	136			118			41			48
Actuarial loss (gain)	(131		)	72			(89		)	(48		)
Benefits paid	(169		)	(235		)	(99		)	(112		)
Benefit obligation — end of year	1,002			1,128			1,187			1,287
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	33			117			58			64
Plan participants contributions	136			118			41			48
Benefits paid	(169		)	(235		)	(99		)	(112		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,002		)	(1,128		)	(1,187		)	(1,287		)
Accrued postretirement cost	$	(1,002	)	$	(1,128	)	$	(1,187	)	$	(1,287	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%

⁽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 2018 Form 10-K Page 84

Notes to the Consolidated Financial Statements

Net periodic postretirement benefit costs for 2018, 2017, and 2016 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	38		$	41		$	43		$	47		$	50		$	55
Amortization of actuarial loss	58			53			64			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	19			17			30			47			50			55
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost(1)	$	19		$	17		$	30		$	55		$	58		$	63
Assumptions
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%

(1) As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

Similar to the FPU Pension Plan, continued amortization of the FPU Medical Plan regulatory asset related to the unrecognized cost prior to the merger with Chesapeake Utilities was included in the net periodic cost. The unamortized balance of this regulatory asset was $14,000 and $22,000 at December 31, 2018 and 2017, respectively.

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, 2018:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(524	)	$	—		$	(524	)
Net loss (gain)	3,865		18,544		559		578			(79		)	23,467
Total	$	3,865	$	18,544	$	559	$	54		$	(79	)	$	22,943
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,865	$	3,523	$	559	$	54		$	(15	)	$	7,986
Post-merger regulatory asset	—		15,021		—		—			(64		)	14,957
Subtotal	3,865		18,544		559		54			(79		)	22,943
Pre-merger regulatory asset	—		543		—		—			14			557
Total unrecognized cost	$	3,865	$	19,087	$	559	$	54		$	(65	)	$	23,500

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2018 is net of income tax benefits of $2.1 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations, which is included in the above table as a post-merger regulatory asset. FPU also continues to maintain and amortize a portion of the unrecognized pension and postretirement benefit costs prior to the merger with Chesapeake Utilities related to its regulated operations, which is shown as a pre-merger regulatory asset.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 85

Notes to the Consolidated Financial Statements

Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2018, 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, 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 2018 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 2019, we expect to contribute $163,000 and $1.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $383,000 to the Chesapeake SERP. We also expect to contribute $96,000 and $94,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2019.

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)
2019	$	528	$	3,091	$	383	$	96	$	94
2020	$	529	$	3,221	$	150	$	85	$	87
2021	$	736	$	3,299	$	148	$	82	$	91
2022	$	595	$	3,485	$	147	$	81	$	93
2023	$	1,244	$	3,558	$	145	$	64	$	80
Years 2024 through 2028	$	3,866	$	18,570	$	744	$	275	$	402

⁽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, 2018, 2017 and 2016, 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 $5.5 million, $5.0 million, and $4.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, 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

Chesapeake Utilities Corporation 2018 Form 10-K Page 86

Notes to the Consolidated Financial Statements

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 $6.7 million at both December 31, 2018 and 2017. (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 $3.9 million and $3.4 million at December 31, 2018 and 2017, 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 475,099 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2018, 2017 and 2016:

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Awards to non-employee directors	$	539		$	540		$	580
Awards to key employees	2,871			1,950			1,787
Total compensation expense	3,410			2,490			2,367
Less: tax benefit	(934		)	(1,003		)	(952		)
Share-based compensation amounts included in net income	$	2,476		$	1,487		$	1,415

Stock Options

There were no stock options outstanding at December 31, 2018 or 2017, nor were any stock options issued during the years 2016 through 2018.

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 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for board service through the 2018 Annual Meeting of Stockholders; as a group, 7,515 shares, with a weighted average fair value of $71.80, were issued and vested in 2017. 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, were issued and vested in 2018.

The intrinsic values of the shares granted to our non-employee directors are equal to the fair value of these awards on the date of grant. At December 31, 2018, there was $180,000 of unrecognized compensation expense related to these awards. This expense will be fully recognized by April 2019, which approximates the expected remaining service period of those directors.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 87

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, 2016	115,091		$	51.85
Granted	52,355		$	63.42
Vested	(32,926	)	$	38.88
Expired	(1,878	)	$	39.97
Outstanding — December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding — December 31, 2018	131,741		$	67.24

⁽¹⁾ Includes 2,569 shares that were forfeited

The intrinsic value of these awards was $10.7 million, $10.4 million and $7.7 million in 2018, 2017 and 2016, respectively. At December 31, 2018, there was $2.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2019 through 2020.

In 2018, 2017 and 2016, 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,
	2018		2017		2016
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,436		10,269		12,031
Amounts remitted to tax authorities to satisfy obligations	$	1,210	$	692	$	770
Tax benefit associated with settlement of share based payments	$	—	$	349	285

In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). 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, and an additional 2,569 shares were forfeited. We settled the awards that vested in cash and recognized $1.1 million as share-based compensation expense.

Chesapeake Utilities Corporation 2018 Form 10-K Page 88

Notes to the Consolidated Financial Statements

19. RATESAND 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 by the Florida PSC.

Delaware

Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018.

CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition, and subsequent conversion to natural gas of certain CGS located within our service territory. We requested the establishment of regulatory accounting treatment and valuation of the proposed acquisition, approval of a methodology to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs. The application included a request that the Delaware PSC regulate the propane CGS systems after their acquisition but before conversion to natural gas.  In late 2018, the Delaware PSC ruled that it did not have jurisdiction over these propane CGS systems and could not approve the methodology given the lack of jurisdiction.  We are considering proposing legislation to clarify the Delaware PSC jurisdiction or we may redesign the application and re-file.

Effect of the TCJA on customers: The Delaware PSC issued an order requiring all rate-regulated utilities to: (i) file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules), and (ii) propose procedures for changing rates to reflect those impacts on or before March 31, 2018. In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changes in the federal corporate income tax laws. In compliance with the Delaware PSC order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. On May 31, 2018, our Delaware Division filed the information requested by the PSC, including an updated report reflecting the impact of the TCJA. On January 31, 2019, the Delaware PSC approved the as-filed Delaware Division Delivery Service Rates reflecting the impact of the TCJA.  The new rates will go into effect March 1, 2019, and the Company will have to complete refunds back to February 2018, per the Commission’s previous order, by June 30, 2019.  The order also provides for a line item billing credit to go into effect on April 1, 2019, for the return of the excess deferred income taxes.  Additional information on the TCJA impact is included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Maryland

Effect of the TCJA on customers: In April 2018, the Maryland PSC issued orders related to the TCJA impact on both the Maryland Division and Sandpiper operations. Please see the actions taken in conjunction with these orders in the TCJA table at the end of this Note 19, Rates and Other Regulatory Activities. Additionally, if in the future the Maryland Division or Sandpiper identifies any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations filed a petition with the Florida PSC requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of our electrical grid. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. More details about this methodology are included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Electric Limited Proceeding-Storm Recovery: 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 this filing, had a deficit of $779,000. We requested approval of a surcharge of $1.82 per kilowatt hour for two years to recover storm-related costs and replenish the storm reserve. FPU filed written testimony on this matter in August 2018. This matter was heard before the Florida PSC in December 2018, final legal briefs were submitted and, on January 14, 2019, and is scheduled for approval at Agenda on March 5, 2019.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 89

Notes to the Consolidated Financial Statements

In October 2018, Hurricane Michael passed through Florida Public Utilities Company's (“FPU”) 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 losing electrical service. FPU has restored service to those customers who were able to accept service following Hurricane Michael after a significant hurricane restoration effort. In conjunction with restoring these services, FPU expended over $60.0 million to restore service, which has been recorded as new plant and equipment or charged against FPU’s storm reserve. We are preparing the necessary regulatory filings to seek recovery for the costs incurred, including replenishment of FPU's storm reserve. In conjunction with the hurricane-related expenditures, we executed two13-month unsecured term loans as temporary financing, each in the amount of $30.0 million. The interest cost associated with these loans is LIBOR plus 75 basis points. One of the term loans was executed in December 2018 and the other was executed in January 2019. The storm did not have a material impact on the Company’s financial results in 2018, and is not expected to have a significant impact going forward assuming reasonable regulatory treatment.

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 division filed petitions and supporting testimony regarding the disposition of the related impacts of the TCJA. Hearings on this matter took place in November 2018, The Florida PSC approved staff’s recommendations on February 5, 2019. Final orders were issued on February 25, 2019, and are subject to a 30-day appeal period. Staff’s recommendations are summarized in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Eastern Shore

2017 Expansion Project: In October 2017, the FERC issued a Certificate of Public Convenience and Necessity authorizing Eastern Shore to construct this project, the largest expansion in Eastern Shore's history. The facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system and an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

The first phase of the project was placed into service in December 2017 and, as of December 31, 2018, we have substantially completed construction. The TETLP interconnect upgrade was placed into service in December 2017, and the Fair Hill Loop, the Jennersville Loop, the Daleville Compressor Station, the Seaford-Millsboro Connector, and the Millsboro Pressure Control Station were placed into service at various dates in 2018. The Parkesburg Loop was placed into service in January 2019. The few remaining segments are expected to be placed into service in various phases during the first half of 2019.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC. In August 2017, Eastern Shore implemented the proposed new rates, subject to refund, based on the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates pending FERC approval of a settlement agreement and refunds to customers according to the terms of the settlement. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. In April 2018, Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates. Exclusive of the TCJA impact, which is discussed below, base rates increased, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on customers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the reduction in its federal corporate income tax rate. These adjusted base rates became effective January 1, 2018 and will generate approximately $6.6 million in incremental margin, on an annual basis. Other information about the impact of the TCJA on ESNG has been included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

In October 2018, the FERC issued an order granting a waiver to Eastern Shore. In April 2018, Eastern Shore consummated a filing, which included its comments associated with the United Airlines, Inc. vs. FERC proceeding and requested confirmation from the FERC that Eastern Shore is not required to provide an informational filing because of its implementation of lower rates in accordance with the 2017 rate case settlement agreement.

Chesapeake Utilities Corporation 2018 Form 10-K Page 90

Notes to the Consolidated Financial Statements

Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application with the FERC, requesting authorization to construct and operate the Del-Mar Energy Pathway project, which will provide an additional 14,300 Dts/d of capacity 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 Somerset County, Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) further 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. During the fourth quarter of 2018, the FERC held a full project area scoping meeting in Sussex County, Delaware and issued a Notice of Schedule for Environmental Review, indicating issuance of its Environmental Assessment for the Del-Mar Energy Pathway project by April 1, 2019.

Summary TCJA Table

	Regulatory Liabilities related to Excess Accumulated Deferred Income Taxes ("ADIT")		Status of Customer Rate impact related to 35 percent to 21 percent rate change
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing	Implemented one-time bill credit (totaling $900,000) in April 2018 - Customer rates adjusted in April, 2018
Delaware Division (Delaware PSC)	$13,262	In January 2019, PSC approved amortization of ADIT and corresponding customer rate reductions effective March 1, 2019.	Customer rates to be adjusted March 1, 2019. One-time bill credit to be implemented during the second quarter.
Maryland Division (Maryland PSC)	$4,211	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $365,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Sandpiper Energy (Maryland PSC)	$3,815	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $608,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,471	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Natural Gas (includes FPU, Fort Meade, and Indiantown) (Florida PSC)	$19,505	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Electric (Florida PSC)	$5,995	In January 2019, PSC approved 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, 2018 and 2017, our regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 91

Notes to the Consolidated Financial Statements

	As of December 31,
	2018		2017
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	4,631	$	9,869
Under-recovered GRIP revenue (2)	165		164
Deferred postretirement benefits (3)	15,517		15,498
Deferred conversion and development costs (1)	16,727		11,735
Environmental regulatory assets and expenditures (4)	2,731		3,222
Acquisition adjustment (5)	33,255		39,992
Loss on reacquired debt (6)	942		1,031
Other	3,250		4,994
Total Regulatory Assets	$	77,218	$	86,505
Regulatory Liabilities
Self-insurance (7)	$	947	$	1,013
Over-recovered purchased fuel and conservation cost recovery (1)	5,443		2,048
Over-recovered GRIP revenue (2)	1,563		2,245
Storm reserve (7)	677		669
Accrued asset removal cost (8)	42,401		40,948
Deferred income taxes due to rate change (9)	91,162		98,492
Other	729		2,048
Total Regulatory Liabilities	$	142,922	$	147,463

⁽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. 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. Included in these amounts are $543,000 of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including a gross up for income tax, because it is not tax deductible, and $746,000 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.

20. ENVIRONMENTAL COMMITMENTSAND 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 six sites located in Salisbury, Maryland, Seaford, Delaware and Winter

Chesapeake Utilities Corporation 2018 Form 10-K Page 92

Notes to the Consolidated Financial Statements

Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland.

As of December 31, 2018, we had approximately $9.1 million 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, 2018, we have recovered approximately $11.5 million, leaving approximately $2.5 million 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 Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford (Florida)	In March 2018, the 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. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.
Seaford (Delaware)	Proposed plan for implementation approved by Delaware Department of Natural Resources and Environmental Control in July 2017. Site assessment is ongoing.	$273,000 to $465,000.
Cambridge (Maryland)	Currently in discussions with MDE.	Unable to estimate.

21. OTHER COMMITMENTSAND CONTINGENCIES

Natural Gas, Electric and Propane Supply

Our Delmarva Peninsula natural gas distribution operations have 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. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with Eastern Gas & Water Investment Company, LLC ("EGWIC") to purchase propane through May 2019. Sandpiper's remaining commitment is approximately 1.2 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC through May 2019. Sharp's current annual commitment is estimated at approximately 1.2 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC; neither agreement permits the set off of the rights and obligations in one agreement against those in the other agreement.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 93

Notes to the Consolidated Financial Statements

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, including PESCO. 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.

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL 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, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

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

Year	2019		2020-2021		2022-2023		Beyond 2023		Total
(in thousands)
Purchase Obligations	$	158,544	$	74,970	$	42,279	$	129,019	$	404,812

Corporate Guarantees

The Board of Directors has authorized the Company 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 during 2018 was $95.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at December 31, 2018 was $76.5 million, with the guarantees expiring on various dates through December 2019.

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, 2018, we have issued letters of credit totaling approximately $7.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019. There have been no draws on these letters of credit as of December 31, 2018. 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.

Chesapeake Utilities Corporation 2018 Form 10-K Page 94

Notes to the Consolidated Financial Statements

22. QUARTERLY FINANCIAL DATA (UNAUDITED)

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

	For the Quarters Ended
	March 31		June 30		September 30		December 31
(in thousands except per share amounts)
2018(1)
Operating Revenues	$	239,356	$	136,664	$	140,279	$	201,190
Operating Income	$	40,406	$	13,248	$	12,036	$	28,930
Net Income	$	26,855	$	6,387	$	5,538	$	17,801
Earnings per share:
Basic	$	1.64	$	0.39	$	0.34	$	1.09
Diluted	$	1.64	$	0.39	$	0.34	$	1.08
2017(1)
Operating Revenues	$	185,160	$	125,084	$	126,936	$	180,403
Operating Income	$	35,099	$	14,061	$	14,632	$	23,628
Net Income	$	19,144	$	6,046	$	6,833	$	26,101
Earnings per share:
Basic	$	1.17	$	0.37	$	0.42	$	1.60
Diluted	$	1.17	$	0.37	$	0.42	$	1.59

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

Chesapeake Utilities Corporation 2018 Form 10-K     Page 95

ITEM 9. CHANGES INAND DISAGREEMENTS WITH ACCOUNTANTSON ACCOUNTINGAND FINANCIAL DISCLOSURE.

None.

ITEM 9A. CONTROLSAND 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, 2018. 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, 2018.

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, 2018, 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, 2018. In addition, on June 8, 2018, our former 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, 2018.

Our independent auditors, Baker Tilly Virchow Krause, LLP, have audited the effectiveness of our internal control over financial reporting as of December 31, 2018, as stated in their report which appears under Part II, Item 8. Financial Statements and Supplementary Data. 

Chesapeake Utilities Corporation 2018 Form 10-K Page 96

ITEM 9B. OTHER INFORMATION.

None.

PART III

ITEM 10. DIRECTORS, EXECUTIVE OFFICERSOFTHE REGISTRANTAND CORPORATE GOVERNANCE.

In December 2018, the Company announced that its Board of Directors had appointed Jeffry M. Householder, formerly President of the Company's Florida business unit, President and Chief Executive Officer. Concurrent with his promotion, Mr. Householder was also appointed to the Company's Board of Directors. Both appointments were effective on January 1, 2019.

The Company's former President and Chief Executive Officer, Michael P. McMasters, who retired on December 31, 2018, is continuing as a member of the Company's Board of Directors.

We have adopted a Code of Ethics that applies to our principal executive officer, president, principal financial officer, principal accounting officer or controller, and persons performing similar functions, which is a “code of ethics” as defined by applicable rules of the SEC. This Code of Ethics is publicly available on our website at http://www.chpk.com/wp-content/uploads/Code_of_Ethics.pdf. 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” in the Proxy Statement.

ITEM 12. SECURITY OWNERSHIPOF CERTAIN BENEFICIAL OWNERSAND MANAGEMENTAND 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 RELATIONSHIPSAND 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 FEESAND 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."

Chesapeake Utilities Corporation 2018 Form 10-K     Page 97

PART IV

ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.

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 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.
•       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 14, 2011, between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form 8-K, filed January 21, 2011, File No. 001-11590.
•        Exhibit 10.5*	Amendment to Executive Employment Agreement effective January 1, 2014, between Chesapeake Utilities Corporation and Michael P. McMasters, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form 8-K filed January 14, 2014, File No. 001-11590.
•        Exhibit 10.6*	Executive Employment Agreement dated January 9, 2013, between Chesapeake Utilities Corporation and Stephen C. Thompson, is incorporated herein by reference to Exhibit 10.9 of our Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-11590.
•        Exhibit 10.7*	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 10.8*	Executive Employment Agreement dated January 9, 2013, between Chesapeake Utilities Corporation and Elaine B. Bittner, incorporated herein by reference to Exhibit 10.11 of our Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-11590.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 99

•      Exhibit 10.9*	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 10.10*	Form of Performance Share Agreement, effective January 7, 2014 for the period 2014 to 2016, 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 10.18 of our Annual Report on Form 10-K for the year ended December 31, 2013, File No. 001-11590.
•     Exhibit 10.11*	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 10.12*	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 10.13*	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.
•     Exhibit 10.14*	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 10.15*	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 10.16	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 10.17	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 10.18*	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 10.19*	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 10.20	Credit Agreement, dated November 28, 2017, by and between Chesapeake Utilities Corporation and Branch Banking and Trust Company is filed herewith.

Chesapeake Utilities Corporation 2018 Form 10-K Page 100

•      Exhibit 10.21*	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 10.22*	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 10.23	Term Note dated December 21, 2018 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is filed herewith.
•      Exhibit 10.24*	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 filed herewith.
•      Exhibit 10.25*	Executive Employment Agreement dated February 25, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is filed herewith.
•      Exhibit 10.26	Term Note dated January 31, 2019 issued by Chesapeake Utilities Corporation in favor of Branch Banking & Trust Company 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.
•       Exhibit 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document is filed herewith.

*	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 2018 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, 2019

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, 2019	and Assistant Corporate Secretary
	(Principal Financial and Accounting Officer)
	February 26, 2019
/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, 2019
February 26, 2019
/S/ EUGENE H. BAYARD, ESQ	/S/ PAUL L. MADDOCK, JR.
Eugene H. Bayard, Esq., Director	Paul L. Maddock, Jr., Director
February 26, 2019	February 26, 2019
/S/ THOMAS J. BRESNAN	/s/ MICHAEL P. MCMASTERS
Thomas J. Bresnan, Director	Michael P. McMasters, Director
February 26, 2019	February 26, 2019
/S/ RONALD G. FORSYTHE, JR.	/S/ CALVERT A. MORGAN, JR.
Dr. Ronald G. Forsythe, Jr., Director	Calvert A. Morgan, Jr., Director
February 26, 2019	February 26, 2019
/S/ THOMAS P. HILL, JR.	/S/ DIANNA F. MORGAN
Thomas P. Hill, Jr., Director	Dianna F. Morgan, Director
February 26, 2019	February 26, 2019

Chesapeake Utilities Corporation 2018 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
2018	$	936	$	1,157	$	136	$	(1,121	)	$	1,108
2017	909		602		337		(912		)	936
2016	909		985		340		(1,325		)	909

⁽¹⁾ Recoveries.

⁽²⁾ Uncollectible accounts charged off.

Chesapeake Utilities Corporation 2018 Form 10-K     Page 103

EX-10.20

CREDIT AGREEMENT

by and between

BRANCH BANKING AND TRUST COMPANY

and

CHESAPEAKE UTILITIES CORPORATION

November 28, 2017

WCSR 39139774v4

CREDIT AGREEMENT

THIS CREDIT AGREEMENT (the “Agreement”) is made as of the 31^st day of August, 2017, by and between CHESAPEAKE UTILITIES CORPORATION, a Delaware corporation (“Borrower”), and BRANCH BANKING AND TRUST COMPANY (“Bank”). Borrower and Bank agree, under seal, as follows:

BACKGROUND

A.    Borrower desires the Bank to make available to it a $40,000,000.00 revolving line of credit (the “Credit Facility”).

B.    Bank is willing to make the Credit Facility available to Borrower, subject to the terms and conditions hereof.

ARTICLE 1DEFINITIONS

Section 1.1.Definitions. When used in this Agreement, the following terms shall have the respective meanings set forth below.

1.1.1.“Advance” means a borrowing under the Credit Facility in accordance with Section 2.3 hereof.

1.1.2.“Affiliate” means as to any Person, each other Person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with the Person in question. For purposes of this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of an entity, whether through the ownership of voting securities, by contract, or otherwise.

1.1.3.“Agreement” means this Credit Agreement and all exhibits and schedules hereto, as each may be amended, renewed, replaced, supplemented or otherwise modified from time to time in accordance with the terms of this Agreement.

1.1.4.“Applicable Margin” has the meaning ascribed to such term on Exhibit B attached hereto and made a part hereof.

1.1.5.“Bank” means Branch Banking and Trust Company, and its successors and assigns pursuant to Section 9.3 hereof.

1.1.6.“Bank Indebtedness” means all obligations and indebtedness of Borrower to Bank, whether now or hereafter owing or existing, including without limitation all obligations under the Credit Documents, all obligations under any interest rate swap agreements or arrangements with the Bank designed to protect the Borrower against fluctuations in interest rates or currency exchange rates, and all other obligations or undertakings now or hereafter made by or for the benefit of Borrower under any other agreement, promissory note or undertaking now existing or hereafter entered into by Borrower with Bank related to the Credit Documents, including, without limitation, all obligations of Borrower to Bank under any guaranty or surety agreement and all obligations of Borrower to immediately pay to Bank the amount of any overdraft on any deposit account maintained with Bank, together with all interest and other sums

2

WCSR 39139774v4

payable in connection with any of the foregoing (including without limitation interest and fees that accrue after the commencement by or against Borrower or any Affiliate thereof of any proceeding under any Debtor Relief Law naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding).

1.1.7.“Borrower” means Chesapeake Utilities Corporation, a Delaware corporation.

1.1.8.“Borrowing Notice” means the certificate in the form attached hereto as Exhibit A to be delivered by Borrower to Bank.

1.1.9.“Business Day” has the meaning ascribed to such term on Exhibit B attached hereto.

1.1.10. “Code” means the Internal Revenue Code of 1986, as amended from time to time, and all rules and regulations with respect thereto in effect from time to time.

1.1.11. “Credit Documents” means this Agreement, the Note and any other agreements, documents, instruments and writings now or hereafter existing, creating, evidencing, guarantying, securing or relating to any of the liabilities of Borrower to the Bank together with all amendments, modifications, renewals or extensions thereof.

1.1.12.“Credit Facility” has the meaning set forth in the Background of this Agreement.

1.1.13.“Debtor Relief Law” means the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

1.1.14.“Default” means an event, condition or circumstance the occurrence of which would, with the giving of notice or the passage of time, or both, constitute an Event of Default.

1.1.15.“Default Rate” has the meaning set forth in Section 2.2 hereof.

1.1.16.“Dollars” or “$” means the lawful currency of the United States.

1.1.17.“Environmental Control Statutes” means any federal, state, county, regional or local laws governing the control, storage, removal, spill, release or discharge of Hazardous Substances, including without limitation CERCLA, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 and the Hazardous and Solid Waste Amendments of 1984, the Federal Water Pollution Control Act, as amended by the Clean Water Act of 1976, the Hazardous Materials Transportation Act, the Emergency Planning and Community Right to Know Act of 1986, the National Environmental Policy Act of 1975, the Oil Pollution Act of 1990, any similar or implementing state law, and in each case including all amendments thereto and all rules and regulations promulgated thereunder and permits issued in connection therewith.

1.1.18.“EPA” means the United States Environmental Protection Agency, or any successor thereto.

3

WCSR 39139774v4

1.1.19. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, any successor statute of similar import, and all rules and regulations with respect thereto in effect from time to time.

1.1.20.“ERISA Affiliate” means any Person that is a member of any group or organization within the meaning of Code sections 414(b), (c), (m) or (o) of which Borrower is a member.

1.1.21.“Event of Default” means an event described in Section 8.1 hereof.

1.1.22.“Existing Credit Agreement” means that certain Credit Agreement, dated as of October 8, 2015, by and among the Borrower, the lenders party thereto and PNC Bank, National Association as administrative agent, swing loan lender and issuing lender, as amended, restated, refinanced, extended, replaced, supplemented or otherwise modified from time to time.

1.1.23.“Funded Debt” means all indebtedness for borrowed money having an original term of more than one year, including, but not limited to, capitalized lease obligations, reimbursement obligations in respect of letters of credit, and guaranties of any such indebtedness.

1.1.24.“GAAP” means generally accepted accounting principles as in effect in the United States of America set forth in the Opinions of the Accounting Principles Board of the American Institute of Certified Public Accountants and in statements of the Financial Accounting Standards Board and in such other statements by such other entity as Bank may reasonably approve, which are applicable in the circumstances as of the date in question; and such principles observed in a current period shall be comparable in all material respects to those applied in a preceding period.

1.1.25. “Hazardous Substance” means petroleum products and items defined in the Environmental Control Statutes as “hazardous substances”, “hazardous wastes”, “pollutants” or “contaminants” and any other toxic, reactive, corrosive, carcinogenic, flammable or hazardous substance or other pollutant.

1.1.26.“Indebtedness” means:

(a)all indebtedness, obligations, and liabilities secured by any mortgage, pledge, lien, conditional sale or other title retention agreement or other security interest to which any property or asset owned or held by such Person is subject, whether or not the indebtedness, obligations or liabilities secured thereby shall have been assumed by such Person; and

(b)to the extent not included in the foregoing, all indebtedness, obligations and liabilities of others which such Person has directly or indirectly guaranteed, endorsed (other than for collection or deposit in the ordinary course of business), sold with recourse, or agreed (contingently or otherwise) to purchase or repurchase or otherwise acquire or in respect of which such Person has agreed to supply or advance funds (whether by way of loan, stock purchase, capital contribution or otherwise) or otherwise to become directly or indirectly liable.

1.1.27. “Late Charge” has the meaning set forth in Section 2.2 hereof.

1.1.28.“Material Adverse Effect” means either singly or in the aggregate, the occurrence of any event, condition, circumstance or proceeding that materially and adversely affects the financial condition or operations of the Borrower and its Subsidiaries taken as a whole or the Borrower’s ability to perform its obligations under this Agreement and the other Credit Documents.

4

WCSR 39139774v4

1.1.29.“Note” shall mean the promissory note, dated of even date herewith, of the Borrower payable to the order of the Bank, as the same may be amended, renewed, replaced, or supplemented from time to time, evidencing the Credit Facility.

1.1.30.“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

1.1.31.“Person” means an individual, corporation, trust, limited partnership, general partnership, limited liability company or unincorporated association, governmental entity, agency, instrumentality, or political subdivision thereof, or any other form of entity or organization.

1.1.32.“Plan” means any pension benefit or welfare benefit plan as defined in sections 3(1), (2) or (3) of ERISA maintained or sponsored by, contributed to, or covering employees of, Borrower or any ERISA Affiliate.

1.1.33.“Prime Rate” has the meaning ascribed on Exhibit B attached hereto.

1.1.34.“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System, comprising Part 204 of Title 12, Code of Federal Regulations, as amended from time to time, and any successor thereto.

1.1.35.“Release” means any spill, leak, emission, discharge, release or the pumping, pouring, emptying, disposing, injecting, escaping, leaching or dumping of a Hazardous Substance.

1.1.36. “Subsidiary” of any Person at any time means any corporation, trust, partnership, limited liability company or other business entity (i) of which more than 50% of the outstanding voting securities or other interests normally entitled to vote for the election of one or more directors, managers, managing members, trustees or similar positions (regardless of any contingency which does or may suspend or dilute the voting rights) is at such time owned directly or indirectly by such Person or one or more of such Person’s Subsidiaries, or (ii) which is controlled or capable of being controlled by such Person or one or more of such Person's Subsidiaries.

1.1.37. “Termination Date” means the earlier of (i) October 31, 2018 or (ii) the date on which the Credit Facility is terminated pursuant to Section 2.4 or Section 8.2 hereof.

Section 1.2.Rules of Construction, Interpretation.

1.2.1.GAAP. Except as otherwise provided herein, financial and accounting terms used in the foregoing definitions or elsewhere in this Agreement, shall be defined in accordance with GAAP. Where the character or amount of any asset or liability or item of income or expense is required to be determined or any consolidation or other accounting computation is required to be made for the purposes of this Agreement, the same shall be done in accordance with GAAP, to the extent applicable, except where such principles are inconsistent with the requirements of this Agreement.

1.2.2.Directly or Indirectly. Where any provision in this Agreement refers to action to be taken by any Person, or that such person is prohibited from taking, such provision shall be applicable whether the action in question is taken directly or indirectly by such Person.

5

WCSR 39139774v4

1.2.3.Plural / Singular. Except as otherwise provided herein, capitalized terms used in the foregoing definitions or elsewhere in this Agreement that are defined in the singular may also be used in the plural and any such terms which are defined in the plural may also be used in the singular.

1.2.4.Uniform Commercial Code. Except as otherwise provided herein, capitalized terms used in the foregoing definitions or elsewhere in this Agreement that are defined in the Uniform Commercial Code, including without limitation, “Accounts,” “Documents,” “Instruments,” “General Intangibles,” and “Chattel Paper” shall have the respective meanings ascribed to such terms in the Uniform Commercial Code as in effect in the State of Delaware from time to time (“UCC”).

ARTICLE 2
CREDIT FACILITY

Section 2.1.The Credit Facility. From time to time prior to the applicable Termination Date, subject to the provisions of this Agreement, the Bank shall make Advances to Borrower under the Credit Facility, which Borrower shall pay and may reborrow, so long as the aggregate principal amount of Advances outstanding under the Credit Facility at any one time shall not exceed the amount of the Credit Facility.

2.1.1.Promissory Note. The indebtedness of the Borrower to the Bank under the Credit Facility is evidenced by the Note. The original principal amount of the Note will be the amount of the Credit Facility; provided, however, that notwithstanding the face amount of the Note, Borrower’s liability under the Note shall be limited at all times to its actual indebtedness, principal, interest and fees, then outstanding under this Agreement and the other Credit Documents.

2.1.1.Use of Proceeds. Funds advanced under the Credit Facility shall be used solely for Borrower’s working capital and other general corporate purposes.

2.1.2.Interest and Principal Payments.

(a)Interest on the outstanding principal amount of the Credit Facility shall accrue at a rate equal to (i) the LIBOR Rate or the LIBOR Advantage Rate, as selected by Borrower, plus (ii) the Applicable Margin. Interest shall be calculated on the basis of the actual number of days elapsed over a year of three hundred sixty (360) days. Notwithstanding anything contained herein to the contrary, all of the provisions contained in Exhibit B attached hereto shall apply to the Credit Facility. In the event that there are any inconsistencies between the terms of this Agreement and the terms contained in Exhibit B attached hereto, the terms contained in Exhibit B shall control. If Borrower does not select a LIBOR Rate or the LIBOR Advantage Rate, the Prime Rate shall apply, and interest on the outstanding principal amount of the Credit Facility shall accrue at a rate equal to (i) the Prime Rate plus (ii) the Prime Rate Margin.

(b)Commencing on the first Interest Payment Date after the date of the initial Advance and on each consecutive Interest Payment Date thereafter until and including the Interest Payment Date in August 2018, a payment shall be made equal to the sum of accrued interest on the outstanding principal balance of the Credit Facility. The entire unpaid principal amount of the Credit Facility, together with accrued and unpaid interest thereon and all other amounts payable in connection with the Credit Facility, shall be due and payable in full on the Termination Date.

All capitalized terms used in this Section 2.1.3 and not otherwise defined in this Agreement shall have the meanings ascribed to such terms in Exhibit B.

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Section 2.2.Late Charge and Default Rate. Notwithstanding the foregoing, if the Borrower fails to make any payment of principal, interest or other amount coming due pursuant to the provisions of this Agreement or the Note within ten (10) calendar days of the date due and payable, the Borrower also shall pay to the Bank a late charge equal to three percent (3.0%) of the amount of such payment (the “Late Charge”). Such ten (10) day period shall not be construed in any way to extend the due date of any such payment. Upon maturity, whether by acceleration, demand or otherwise, and at the Bank’s option upon the occurrence of any Event of Default and during the continuance thereof, the Note shall bear interest at a rate that shall be three percentage points (3.0%) in excess of the interest rate in effect from time to time under the Note but not more than the maximum rate allowed by law (the “Default Rate”). The Default Rate shall continue to apply whether or not judgment shall be entered on this Agreement or the Note. Both the Late Charge and the Default Rate are imposed as liquidated damages for the purpose of defraying the Bank’s expenses incident to the handling of delinquent payments, but are in addition to, and not in lieu of, the Bank’s exercise of any rights and remedies hereunder, under the other Credit Documents or under applicable law, and any fees and expenses of any agents or attorneys which the Bank may employ. In addition, the Default Rate reflects the increased credit risk to the Bank of carrying a loan that is in default. The Borrower agrees that the Late Charge and Default Rate are reasonable forecasts of just compensation for anticipated and actual harm incurred by the Bank, and that the actual harm incurred by the Bank cannot be estimated with certainty and without difficulty.

Section 2.3.Advances.

2.3.1.Borrower shall give the Bank prior written notice not later than two o’clock (2:00) p.m. (New York time), on the second Business Day prior to the date of an Advance. Any such notice shall be in the form of the Borrowing Notice, shall be certified by the chief financial officer or other authorized officer of the Borrower, and shall set forth the aggregate amount of the requested Advance, which shall be in multiples of $5,000.00 but not less than the lesser of $25,000.00 or the unborrowed balance of the Credit Facility; provided, however, if Borrower and Bank enter into a cash management agreement related to the Credit Facility, and if any terms of this Agreement related to advance procedure conflict with the terms of such cash management agreement, the terms of such cash management system shall govern.

2.3.2.Upon receiving a request for an Advance in accordance with subsection 2.3.1 above, the Bank shall, upon approval of such request, promptly make the requested Advance available to Borrower (A) by crediting such amount to Borrower’s deposit account with the Bank on the day of the requested Advance, or (B) otherwise in accordance with such instructions as have been provided by Borrower to the Bank with sufficient notice to permit the Bank, in accordance with standard Banking practices, to timely comply with such instructions.

2.3.3.Each request for an Advance pursuant to this Section 2.3 shall be irrevocable and binding on the Borrower. With respect to any Advance, Borrower shall indemnify the Bank against any loss, cost or expense incurred by the Bank as a result of any failure by the Borrower to fulfill on or before the date specified in such request for an Advance the applicable conditions set forth in Article 4, including, without limitation, any loss (including loss of margin and anticipated profits), cost or expense incurred by reason of the liquidation or redeployment of deposits or other funds acquired by the Bank to fund the Advance when such Advance, as a result of such failure, is not made on such date, as calculated by the Bank.

Section 2.4.Termination of Credit Facility. Pursuant to Section 8.2 hereof, the Bank shall have the right to terminate the Credit Facility upon the occurrence of any Event of Default hereunder. Otherwise, the Credit Facility shall terminate on the Termination Date. Upon termination of the Credit Facility, the Bank shall not be obligated to make any Advances.

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Section 2.5.Prepayment; Mandatory Repayment.

2.5.1.Borrower may prepay the outstanding principal balance under the Credit Facility at any time without premium or penalty, provided that (i) Borrower shall comply with the prepayment provisions set forth on Exhibit B attached hereto and (ii) prepayments of all or any portion of the Credit Facility prior to the applicable Termination Date shall not reduce the Credit Facility amount and may be re-borrowed.

Section 2.6.Payments; Application. All payments of principal, interest, fees and other amounts due hereunder, including any prepayments thereof, shall be made by Borrower to the Bank in immediately available funds before twelve o’clock (12:00) noon on any Business Day at the office of the Bank set forth in Section 9.9 hereof or to such other office or location as the Bank from time to time so notifies Borrower. All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. Borrower hereby authorizes the Bank to charge any account maintained by Borrower with the Bank from time to time for all payments of principal, interest, fees and costs when due hereunder. Any and all payments on account of the Credit Facility will be applied to accrued and unpaid interest, outstanding principal and other sums due hereunder or under the Credit Documents, in such order as Bank, in its discretion, elects. If Borrower makes a payment or payments and such payment or payments, or any part thereof, are subsequently invalidated, declared to be fraudulent or preferential, set aside or are required to be repaid to a trustee, receiver, or any other person under any bankruptcy act, state, provincial or federal law, common law or equitable cause, then to the extent of such payment or payments, the obligations or part thereof hereunder intended to be satisfied shall be revived and continued in full force and effect as if said payment or payments had not been made.

ARTICLE 3
REPRESENTATIONS AND WARRANTIES

Borrower represents and warrants as follows:

Section 3.1.Organization; Good Standing; Qualification. Borrower is a corporation duly formed and validly existing under the laws of the State of Delaware. Each Subsidiary is a corporation, limited liability company, partnership or other entity duly formed and validly existing under the laws of its state of incorporation or organization. Borrower has full power and authority to execute, deliver and comply with the Credit Documents, and each of Borrower and its Subsidiaries has full power and authority to carry on its business as it is now being conducted. Each of Borrower and its Subsidiaries is duly licensed or qualified as a corporation, limited liability company, partnership or other entity in each jurisdiction where the failure to be so qualified would have a Material Adverse Effect.

Section 3.2.Licenses. Each of Borrower and its Subsidiaries has all licenses, registrations, approvals and other authority as may be necessary to enable it to own and operate its business and perform all services and business that it has agreed to perform in any state, municipality or other jurisdiction, and the same are valid, binding and enforceable without any adverse limitations thereon, except where the failure to have any or all such licenses, registrations, approvals or other authority would not have a Material Adverse Effect.

Section 3.3.Reserved.

Section 3.4.Accuracy of Information; Full Disclosure.

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3.4.1All financial statements furnished to Bank concerning the Borrower and its Subsidiaries in accordance with the terms of the Agreement have been prepared in accordance with GAAP and fairly present the financial condition of Borrower and such Subsidiaries as of the dates and for the periods covered, subject, in each case of any unaudited interim financial statements to normal year-end adjustments, and there has been no material adverse change in the financial condition or business of Borrower, its Subsidiaries or such other entities considered as a whole from the date of such statements to the date hereof; and

3.4.2    All financial statements and other documents furnished by Borrower to the Bank in connection with this Agreement do not and will not contain any untrue statement of material fact or omit to state a material fact necessary in order to make the statements contained therein not misleading. As of the date of this Agreement, no Material Adverse Effect has occurred or is continuing to occur.

Section 3.5.Pending Litigation or Proceedings. As of the date of this Agreement, there are no judgments outstanding or actions, suits or proceedings pending or, to Borrower’s knowledge, threatened against or affecting Borrower or any of its Subsidiaries, at law or in equity or before or by any federal, provincial, state, municipal or other governmental department, commission, board, bureau, court, agency or instrumentality, domestic or foreign, which, if adversely determined, could reasonably be expected to have a Material Adverse Effect.

Section 3.6.Due Authorization; No Legal Restrictions. Borrower has the power and authority under the laws of the state of its organization, and under its organizational documents, to enter into and perform this Agreement, the Note, the other Credit Documents and other agreements and documents required hereunder and to which it is a party. The execution and delivery by Borrower of the Credit Documents to which it is a party, the consummation of the transactions contemplated by the Credit Documents and the fulfillment and compliance with the respective terms, conditions and provisions of the Credit Documents: (a) have been duly authorized by all requisite corporate action of Borrower and (b) will not conflict with or result in a breach of, or constitute a default (or might, upon the passage of time or the giving of notice or both, constitute a default) under, any of the terms, conditions or provisions of any statute, law, rule, regulation or ordinance applicable to Borrower or any Subsidiary of Borrower or Borrower’s incorporation documents or by-laws, or any material indenture, mortgage, loan or credit agreement or instrument to which Borrower or any Subsidiary of Borrower is a party or by which it may be bound or affected, or any judgment or order of any court or governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, except in the case of clause (b) where such conflict, breach, default or violation would not have a Material Adverse Effect.

Section 3.7.Enforceability. The Credit Documents have been duly executed by Borrower and delivered to Bank and constitute legal, valid and binding obligations of Borrower, enforceable in accordance with their terms.

Section 3.8.Compliance with Laws, Agreements, Other Obligations, Orders or Governmental Regulations. Neither Borrower nor any of its Subsidiaries is in default of its respective formation documents or by-laws or other applicable organizational documents. Neither Borrower has nor any of its Subsidiaries have been declared in default of the performance or observance of any of its obligations, covenants or conditions contained in any material indenture or other agreement creating, evidencing or securing any Indebtedness or pursuant to which any such Indebtedness is issued. Neither Borrower is nor any of its Subsidiaries are in violation of or in default under any other agreement or instrument or any judgment, decree, order, statute, rule or governmental regulation, applicable to it or by which its properties

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may be bound or affected, except to the extent such violation or default is not reasonably likely to have a Material Adverse Effect.

Section 3.9.Governmental Consents, No Violations of Laws or Agreements. No consent, approval or authorization of or designation, declaration or filing with any governmental authority on the part of Borrower or any Subsidiary of Borrower which has not already been obtained is required in connection with the execution, delivery or performance by Borrower of the Credit Documents or the consummation of the transactions contemplated thereby.

Section 3.10.Taxes. Each of Borrower and its Subsidiaries has filed all material tax returns which it is required to file, if any, and has paid, or made provision for the payment of, all taxes which have or may have become due pursuant to such returns or pursuant to any assessment received by it. Such tax returns are complete and accurate in all material respects.

Section 3.11.Addresses. As of the date of this Agreement, during the past twelve (12) months, Borrower has not been known by any names (including trade names) other than its current name and the chief executive office of Borrower has not been located at any addresses other than the address of Borrower identified in Section 9.9.

Section 3.12.Current Compliance. Borrower is currently in compliance with all of the terms and conditions of the Credit Documents.

Section 3.13.Reserved.

Section 3.14.Intellectual Property. Each of Borrower and its Subsidiaries owns or possesses the right to use all of the material patents, trademarks, service marks, trade names, copyrights, licenses, franchises and permits and rights with respect to the foregoing necessary to own and operate its properties and to carry on its business as presently conducted and presently planned to be conducted without conflict with the rights of others, except for those conflicts that, individually or in the aggregate, would not have a Material Adverse Effect.

Section 3.15.Business Interruptions. Within five (5) years prior to the date hereof, neither the business nor operations of Borrower or any of its Subsidiaries have been materially and adversely affected in any way by any casualty, strike, lockout, combination of workers, order of the United States of America or any state or local government, or any political subdivision or agency thereof, directed against Borrower or any of its Subsidiaries. There are no pending or threatened labor disputes, strikes, lockouts or similar occurrences or grievances against the businesses being operated by Borrower or its Affiliates.

Section 3.16.Accuracy of Representations and Warranties. No representation or warranty by Borrower contained herein or in any certificate or other document furnished by Borrower pursuant hereto or in connection herewith fails to contain any statement of material fact necessary to make such representation or warranty not misleading in light of the circumstances under which it was made. There is no fact which Borrower knows or should know and has not disclosed to Bank, which does or may materially and adversely affect Borrower or any of its Subsidiaries or any of Borrower’s or any of its Subsidiaries’ operations.

Section 3.17.Reserved.

Section 3.18.No Extension of Credit for Securities. Neither Borrower nor any of its Subsidiaries is now, nor at any time has it been engaged principally, or as one of its important activities, in the business of extending or arranging for the extension of credit, for the purpose of purchasing or carrying

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any “margin stock” or “margin securities” within the meaning of Regulations U, G, T or X of the Board of Governors of the Federal Reserve System; nor will the proceeds of the Credit Facility be used by Borrower or any of its Subsidiaries directly or indirectly, for such purposes.

Section 3.19.Hazardous Wastes, Substances and Petroleum Products.

3.19.1.Each of Borrower and its Subsidiaries (i) have received all material permits and filed all material notifications required by the Environmental Control Statutes to carry on its respective business(es); and (ii) are in compliance with all Environmental Control Statutes, except where the failure to comply would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

3.19.2.Neither Borrower nor any of its Subsidiaries has received written notice that it is potentially responsible for clean-up, remediation, costs of clean-up or remediation, fines or penalties with respect to any actual or imminently threatened Release of Hazardous Substances pursuant to any Environmental Control Statute, except as would not reasonably be expected to result in a Material Adverse Effect.

Section 3.20.Foreign Assets Control Regulations. Neither the borrowing of any Advance by Borrower nor the use of the proceeds thereof by the Borrower or any of its Subsidiaries will violate foreign assets, trade or similar control regulations.

Section 3.21.Investment Company Act. Neither Borrower nor any of its Subsidiaries is directly or indirectly controlled by or acting on behalf of any person which is an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

ARTICLE 4
CONDITIONS

Section 4.1.Disbursement of the First Advance. The obligation of the Bank to make the first Advance of the Credit Facility shall be subject to the Bank’s receipt of the following documents, each in form and substance satisfactory to the Bank:

4.1.1.Delivery of Credit Documents. The Credit Documents shall have been properly executed, as applicable, and delivered to the Bank.

4.1.1.Organizational and Authorization Documents. Certified copies of the organizational documents of Borrower and resolutions authorizing the execution, delivery and performance of the Credit Documents by Borrower.

4.1.2.Certificates of Good Standing. Certificate of good standing issued by the Delaware Secretary of State for Borrower.

4.1.3.Insurance. Certificates of insurance with respect to all of the Borrower’s fire, casualty, liability and other insurance covering its respective property and business required under Section 5.6 hereof.

4.1.4.Borrowing Notice. A completed Borrowing Notice required under Subsection 2.3.1 hereof and any other documents or information reasonably required by the Bank in connection therewith.

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4.1.5.Other Documents. The execution and delivery by Borrower to Bank at Borrower’s sole cost and expense of any and all documents, agreements and corporate resolutions, as Bank shall reasonably request in connection with the execution and delivery of this Agreement, the Credit Documents or any other documents in connection herewith, each of which shall be in form and content reasonably acceptable to Bank.

4.1.6.Searches. Uniform Commercial Code, tax, judgment, litigation and lien searches against Borrower in those offices and jurisdictions as the Bank shall reasonably request.

4.1.7.Opinion. A legal opinion from Borrower’s counsel in form and substance satisfactory to Bank.

4.1.8.Closing Certificate. A certificate, dated as of the effective date of this Agreement, signed by an authorized officer of the Borrower to the effect that (i) no Default or Event of Default hereunder has occurred and is continuing on such date or after giving effect to this Agreement and the other Credit Documents and any Advance occurring on such date and (ii) the representations and warranties of the Borrower contained in this Agreement and the other Credit Documents are true on and as of such date and after giving effect to this Agreement and the other Credit Documents and any Advance occurring on such date.

4.1.9.Other Documents. Such additional documents as the Bank reasonably may request, including, but not limited to, the items set forth on the closing checklist delivered by Bank to Borrower.

Section 4.2.Subsequent Advances. The obligation of the Bank to make additional Advances shall be subject to the Borrower’s satisfaction of the following conditions:

4.2.1.(a) All applicable conditions of this Agreement, including, but not limited to, the conditions of the preceding Section 4.1 shall continue to be met and (b) all representations and warranties of the Borrower contained in this Agreement and the other Credit Documents are true and correct on and as of the date of each Advance and after giving effect to such Advance;

4.2.2.Bank’s receipt of a completed Borrowing Notice; and

4.2.3.Bank’s receipt from Borrower of such other information and documentation reasonably requested by the Bank.

Section 4.3.Additional Condition to the Bank’s Obligations. It shall be a condition to the Bank’s obligation hereunder to make any Advance, that no Default or Event of Default shall have occurred or be caused by such Advance or issuance, and there shall have been no Material Adverse Effect since the date hereof.

ARTICLE 5
GENERAL COVENANTS

Borrower covenants and agrees that so long as the Credit Facility or any Bank Indebtedness is outstanding, Borrower will perform and comply with, and cause each of its Subsidiaries to perform and comply with, the following covenants:

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Section 5.1.Payment of Principal, Interest and Other Amounts Due. Borrower will pay when due all Bank Indebtedness and all other amounts payable by it hereunder.

Section 5.2.Merger; Consolidation. Neither Borrower nor any of its Subsidiaries will merge into or consolidate with any Person or permit any Person to merge into it unless the Borrower or such Subsidiary is the surviving entity (provided, that, in the event of any merger involving the Borrower, the Borrower shall be the surviving entity).

Section 5.3.Taxes; Claims for Labor and Materials. Each of the Borrower and its Subsidiaries will pay or cause to be paid when due all taxes, assessments, governmental charges or levies imposed upon it or its income, profits, payroll or any property belonging to it, including without limitation all withholding taxes, and all claims for labor, materials and supplies which, if unpaid, might become a lien or charge upon any of its properties or assets; provided that Borrower and its Subsidiaries shall not be required to pay any such tax (other than real estate taxes which must be paid regardless of challenge), assessment, charge, levy or claim so long as (a) the validity thereof shall be contested in good faith by appropriate proceedings promptly initiated and diligently conducted by it, and neither execution nor foreclosure sale or similar proceedings shall have been commenced in respect thereof (or such proceedings shall have been stayed pending the disposition of such contest of validity), and it shall have set aside on its books adequate reserves with respect thereto or (b) the nonpayment thereof would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 5.4.Existence; Approvals; Qualification; Business Operations; Compliance with Laws; Notification.

5.4.1.Each of the Borrower and its Subsidiaries (i) will obtain, preserve and keep in full force and effect (A) its separate existence and (B) all rights, licenses, registrations and franchises necessary to the proper conduct of its business or affairs, the absence of which could result in a Material Adverse Effect; (ii) will qualify and remain qualified as a foreign corporation, limited liability company, partnership or other entity in each jurisdiction in which the character or location of the properties owned by it or the business transacted by it requires such qualification; (iii) will not change the nature of its present business substantially as presently conducted; and (iv) will comply with the requirements of all applicable laws and all rules, regulations (including environmental regulations) and orders of regulatory agencies and authorities having jurisdiction over it, except, in the cases of clauses (ii) and (iv), where the lack of such qualification or compliance would not, individually or in the aggregate, have a Material Adverse Effect.

5.4.2.With respect to any Environmental Control Statute, Borrower will promptly notify Bank when, in connection with the conduct of the Borrower’s or any of its Subsidiaries’ business or operations, any Person (including, without limitation, any United States federal, state or local agency) provides oral or written notification to Borrower or any Subsidiary of Borrower, or Borrower or any Subsidiary of Borrower otherwise becomes aware, of a condition with regard to an actual or imminently threatened Release of Hazardous Substances which could reasonably be expected to have a Material Adverse Effect; and notify Bank in detail promptly upon the receipt by Borrower or any of its Subsidiaries of an assertion of liability under the Environmental Control Statutes, of any actual or alleged failure to comply with, failure to perform, breach, violation or default under (with or without the passage of time) any such statutes or regulations which could reasonably be expected to have a Material Adverse Effect.

Section 5.5.Maintenance of Properties. Each of Borrower and its Subsidiaries will maintain, preserve, protect and keep or cause to be maintained, preserved, protected and kept its real and tangible personal property used or useful in the conduct of its business in good working order and condition,

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reasonable wear and tear excepted, and will pay and discharge when due the cost of repairs to and maintenance of the same; provided that this Section 5.5 shall not prevent the Borrower or any Subsidiary from discontinuing the operation and the maintenance of any of its properties if such discontinuance is desirable in the conduct of its business and the Borrower has concluded that such discontinuance would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 5.6.Insurance. Each of Borrower and its Subsidiaries will maintain insurance with commercially acceptable insurance companies as is customary for similarly situated businesses.

Section 5.7.Inspections; Examinations.

5.7.1.To the extent permitted by applicable law, Borrower authorizes all federal, state and municipal authorities to furnish to Bank copies of reports or examinations relating to Borrower or any of its Subsidiaries, whether made by Borrower or otherwise.

5.7.2.The officers of Bank, or such Persons as any of them may reasonably designate, may visit and inspect any of the properties of Borrower and any of its Subsidiaries, examine (either by Bank’s employees or by independent accountants) the books of account of Borrower and any of its Subsidiaries, and discuss the affairs, finances and accounts of Borrower and any of its Subsidiaries with their officers at such times as Bank may reasonably request; provided, however, so long as no Event of Default or Default then exists, Bank shall provide Borrower with twenty four (24) hours prior notice thereof.

Section 5.8.Reserved.

Section 5.9.Change in Control / Change to Organizational Documents. Borrower shall not permit a Change in Control of its ownership or make any amendment to its organizational documents that would have a Material Adverse Effect without the prior written consent of Bank; provided, however, that Bank shall not unreasonably withhold its consent. As used herein, “Change in Control” means any Person or group of Persons within the meaning of § 13(d)(3) of the Securities Exchange Act of 1934, as amended, becoming the beneficial owner, directly or indirectly, of 50% or more of the outstanding equity interests of Borrower.

Section 5.10.Transactions with Affiliates. Neither Borrower nor any of its Subsidiaries will enter into any material transaction or material group of related transactions (including without limitation the purchase, lease, sale or exchange of properties of any kind or the rendering of any service) with any Affiliate (other than the Borrower or a Subsidiary of the Borrower), except pursuant to the reasonable requirements of the Borrower’s or such Subsidiary’s business and upon fair and reasonable terms no less favorable to the Borrower or such Subsidiary than would be obtainable in a comparable arm’s-length transaction with a Person not an Affiliate; provided that the foregoing restriction shall not apply to the payment or grant of reasonable compensation, benefits and indemnities to any director or officer of the Borrower or any of its Subsidiaries. Notwithstanding the foregoing, nothing in this Section 5.10 shall restrict transactions with any Affiliate that have been approved by or are entered into pursuant to any orders or decisions of any governmental authority having jurisdiction over the Borrower or the applicable Subsidiary.

Section 5.11.Name or Address Change. Borrower shall not change its name or address except upon thirty (30) days prior written notice to Bank and delivery to Bank of any items reasonably requested by Bank to access to Borrower’s books and records.

Section 5.12.Notices. Borrower will promptly notify Bank of (a) the occurrence of any Event of Default, (b) the occurrence of a Default, (c) the failure of Borrower to observe any of its undertakings

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under the Credit Documents, or (d) any Material Adverse Effect. Any notice given pursuant to this section shall not cure or otherwise affect any Event of Default.

Section 5.13.Additional Documents and Future Actions. Borrower will, at its sole cost, take such actions and provide Bank from time to time with such agreements, documents or information as the Bank may in its reasonable discretion deem necessary or advisable to carry out the terms of the Credit Documents.

Section 5.14.Restrictions on Use of Proceeds. Neither Borrower nor any of its Subsidiaries will carry or purchase with the proceeds of the Credit Facility any “margin stock” or “margin security” within the meaning of Regulations U, G, T or X of the Board of Governors of the Federal Reserve System.

ARTICLE 6
FINANCIAL COVENANT

Except as otherwise consented in writing in advance by Bank, Borrower and its Subsidiaries will comply with the following covenant, which, unless otherwise specified, shall be tested using amounts that have been determined in accordance with GAAP:

Section 6.1.Funded Debt / Total Capitalization. The Borrower will maintain at all times a ratio of Funded Debt of the Borrower and its consolidated Subsidiaries to the sum of Funded Debt of the Borrower and its consolidated Subsidiaries plus stockholder’s equity of the Borrower and its consolidated Subsidiaries of not more than sixty five percent (65%) (the “Funded Debt to Total Capitalization”), to be tested at the end of each fiscal quarter.

ARTICLE 7ACCOUNTING RECORDS, REPORTS AND FINANCIAL STATEMENTS

Borrower will maintain books of record and account in which full, correct and current entries in accordance with GAAP will be made of all of its dealings, business and affairs of Borrower and its Subsidiaries and will deliver to Bank the following:

Section 7.1.10K and Covenant Compliance Certificate. Within fifteen (15) days of filing, the Form 10K of Borrower filed with the Securities and Exchange Commission. Together with the delivery of each Form 10K, Borrower shall provide to Bank a compliance certificate in the form attached hereto as Exhibit C, including a certificate of Borrower’s chief financial officer that no Event of Default or Default then exists or if an Event of Default or Default exists, the nature and duration thereof and Borrower’s intention with respect thereto.

Section 7.2.10Q and Covenant Compliance Certificate. Within fifteen (15) days of filing, the Form 10Q of Borrower filed with the Securities and Exchange Commission; together with the delivery of each Form 10Q, Borrower shall provide to Bank a compliance certificate in the form attached hereto as Exhibit C, including a certificate of Borrower’s chief financial officer that no Event of Default or Default then exists or if an Event of Default or Default exists, the nature and duration thereof and Borrower’s intention with respect thereto.

Section 7.3.Requested Information. With reasonable promptness, all such other data and information in respect of the condition, operation and affairs of Borrower and its Subsidiaries as Bank may reasonably request from time to time.

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ARTICLE 8
DEFAULT

Section 8.1.Events of Default. Each of the following events shall be an Event of Default hereunder:

8.1.1.If Borrower shall fail to pay (i) as and when due any amount of principal hereunder or on the Note, or (ii) any interest, fees, costs, expenses or any other sum payable to the Bank hereunder or otherwise, whether on demand, at the stated maturity or due date thereof, or by reason of any requirement for prepayment thereof, by acceleration or otherwise, within five (5) days of the date when due;

8.1.1.The failure of Borrower to observe the covenants set forth in Article 6 hereof.

8.1.2.The failure of Borrower to duly perform or observe any obligation, covenant or agreement on its or their part contained herein or in any other Credit Document not otherwise specifically constituting an Event of Default under this Section 8.1 and the continuance of such failure for a period of thirty (30) days after the notice from Bank to Borrower, provided that, in the event such failure is incapable of remedy or consists of a default of the financial covenant in Article 6, Borrower shall not be entitled to any notice or grace hereunder;

8.1.3.A breach, default or event of default shall occur at any time under the terms of the Existing Credit Agreement, and such breach, default or event of default either (i) consists of the failure to pay (beyond any period of grace permitted with respect thereto, whether waived or not) any indebtedness under or in connection with the Existing Credit Agreement when due (whether at stated maturity, by acceleration or otherwise) or (ii) causes, or permits the holder or holders of such indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, with the giving of notice if required, such indebtedness to be demanded or to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such indebtedness to be made, prior to its stated maturity;

8.1.4.The adjudication of Borrower as a “debtor” or insolvent, or the entry of an order for relief against Borrower or the entry of an order appointing a receiver or trustee for Borrower of any of its property or approving a petition seeking reorganization or other similar relief under the bankruptcy or other similar laws of the United States or any state or any other competent jurisdiction;

8.1.5.A proceeding under any bankruptcy, reorganization, arrangement of debt, insolvency, readjustment of debt or receivership law is filed by or (unless dismissed within 90 days) against Borrower or Borrower makes an assignment for the benefit of creditors, or Borrower takes any action to authorize any of the foregoing;

8.1.6.The suspension of the operation of Borrower’s present business, or Borrower becoming unable to meet its debts as they mature, or the admission in writing by Borrower to such effect, or Borrower calling any meeting of all or any material portion of its creditors for the purpose of debt restructure;

8.1.7.All or any part of the assets of Borrower that are material to the operation of Borrower’s business are attached, seized, subjected to a writ or distress warrant, or levied upon, or come within the possession or control of any receiver, trustee, custodian or assignee for the benefit of creditors, or any other assets of Borrower are attached, seized, subject to a writ or distress warrant, or levied upon, or

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come within the possession or control of any receiver, trustee, custodian or assignee for the benefit of creditors and any such action is not, within thirty (30) days after such action is instituted, discharged or stayed pending appeal, or shall not have been discharged within twenty (20) days after the expiration of any such stay;

8.1.8.The entry of final judgment(s) for the payment of money aggregating in excess of $15,000,000 against Borrower which, within twenty (20) days after such entry, shall not have been discharged or execution thereof stayed pending appeal or shall not have been discharged, insured or bonded within five (5) days after the expiration of any such stay;

8.1.9.Any representation or warranty of Borrower in any of the Credit Documents is discovered to be untrue in any material respect or any statement, certificate or data furnished by Borrower pursuant hereto is discovered to be untrue in any material respect as of the date as of which the facts therein set forth are stated or certified;

8.1.10.A Material Adverse Effect occurs in Borrower’s operations or to the financial condition of Borrower;

8.1.11.Borrower voluntarily or involuntarily dissolves or is dissolved, terminates or is terminated;

8.1.12.Borrower is enjoined, restrained, or in any way prevented by the order of any court or any administrative or regulatory agency, the effect of which order restricts Borrower from conducting all or any material part of its business;

8.1.13.Any material uninsured damage to, or loss, theft, or destruction of, any of Borrower’s property that has a Material Adverse Effect;

8.1.14.The loss, suspension, revocation or failure to renew any license or permit now held or hereafter acquired by Borrower, which loss, suspension, revocation or failure to renew has a Material Adverse Effect;

8.1.15.The validity or enforceability of this Agreement or any of the Credit Documents is contested by Borrower.

Section 8.2.Remedies Generally. Upon the happening of any Event of Default and at any time during the continuance thereof and by notice by Bank to Borrower (except if an Event of Default described in Subsection 8.1.5 or 8.1.6 shall occur in which case acceleration shall occur automatically without notice), the Bank may terminate its obligation to make any further Advances and may declare the entire unpaid balance, principal, interest and fees of all Bank Indebtedness, hereunder or otherwise, to be immediately due and payable. Upon such declaration, the Credit Facility shall immediately and automatically terminate and the Bank shall have no further obligation to make any Advances. In addition, the Bank may increase the interest rate on the Credit Facility to the applicable Default Rate set forth herein, without notice; and the Bank shall have all the rights and remedies granted by any applicable law, all of which shall be cumulative in nature.

Section 8.3.Set-Off. At any time and from time to time following the occurrence and during the continuance of a Default or an Event of Default, Bank may without notice or demand, set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by Bank to or for the credit of Borrower against any or all of the Bank Indebtedness and the Borrower’s obligations under the Credit Documents.

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ARTICLE 9
MISCELLANEOUS

Section 9.1.Indemnification and Release Provisions; Costs and Expenses. Except to the extent of the gross negligence or willful misconduct on the part of the specific party indemnified hereunder as determined by a court of competent jurisdiction in a final and nonappealable judgment, Borrower hereby indemnifies and agrees to protect, defend and hold harmless Bank and its Affiliates, directors, officers, officials, agents, employees and counsel and their respective heirs, administrators, executors, successors and assigns (each, “Indemnified Person”), from and against, any and all losses, liabilities (including without limitation settlement costs and amounts, transfer taxes, documentary taxes, or assessments or charges made by any governmental authority), claims, damages, interest, judgments, costs, or expenses, including without limitation reasonable fees and disbursements of counsel, incurred by any Indemnified Person or asserted against any Indemnified Person by any Person (including Borrower or any Subsidiary of Borrower) arising out of or in connection with or by reason of this Agreement, the Credit Facility or any other Credit Document, including without limitation, any and all losses, liabilities, claims, damages, interests, judgments, costs or expenses relating to or arising under any Environmental Control Statute or the application of any such Statute to Borrower’s or any Affiliate’s properties or assets. Borrower hereby releases Bank and its respective Affiliates, directors, officers, agents, employees and counsel from any and all claims for loss, damages, costs or expenses caused or alleged to be caused by any act or omission on the part of any of them, except to the extent caused by the gross negligence or willful misconduct of any party to be released hereunder as determined by a court of competent jurisdiction in a final and nonappealable judgment. All obligations provided for in this Section 9.1 shall survive any termination of this Agreement or the Credit Facility and the repayment of the Credit Facility.

Section 9.2.Certain Fees, Costs, Expenses and Expenditures. Borrower agrees to pay on demand all reasonable costs and expenses of Bank related to the Credit Facility, including without limitation:

9.2.1.all reasonable costs and expenses to third parties in connection with the preparation, review, negotiation, execution and delivery of the Credit Documents, and the other documents to be delivered in connection therewith, or any amendments, extensions and increases to any of the foregoing (including, without limitation, reasonable attorney’s fees and expenses), and following an Event of Default, the cost of periodic lien searches and tax clearance certificates, as Bank deems advisable; and

9.2.2.all losses, reasonable costs and reasonable expenses in connection with the enforcement, protection and preservation of the Bank’s rights or remedies under the Credit Documents, or any other agreement relating to any Bank Indebtedness, or in connection with legal advice relating to the rights or responsibilities of Bank (including without limitation court costs, reasonable attorneys’ fees and reasonable expenses of accountants and appraisers).

In the event Borrower shall fail to pay taxes, insurance, assessments, costs or expenses which it is required to pay hereunder, or otherwise breaches any obligations under the Credit Documents, Bank in its discretion, may (but shall not be obligated to) make expenditures for such purposes and the amount so expended (including reasonable attorney’s fees and expenses, filing fees and other charges) shall be payable by Borrower on demand and shall constitute part of the Bank Indebtedness.

With respect to any amount required to be paid by Borrower under this Section 9.2, in the event Borrower fail to pay such amount within five (5) days of demand, Borrower shall also pay to Bank interest thereon at the Default Rate. Borrower’s obligations under this Section 9.2 shall survive termination of this Agreement.

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Section 9.3.Participations and Assignments. Borrower hereby acknowledges and agrees that the Bank may at any time:

9.3.1.at Bank’s sole cost and expense, grant participations in all or any portion of the Credit Facility or the Note or of its right, title and interest therein or in or to this Agreement to any other lending office or to any other bank, lending institution or other entity; and

9.3.1. assign all or any portion of its rights under the Credit Facility; and

9.3.2.pledge or assign its interest in the Credit Facility, the Note or any participation interest to any Federal Reserve Bank in accordance with applicable law.

Section 9.4.Binding and Governing Law. This Agreement, the other Credit Documents and all documents executed hereunder shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns (provided that the Borrower may not assign or otherwise transfer any of its rights or obligations under this Agreement or the other Credit Documents without the prior written consent of Bank) and shall be governed as to their validity, interpretation and effect by the laws of the State of Delaware.

Section 9.5.Survival. All agreements, representations, warranties and covenants of Borrower contained herein or in any documentation required hereunder shall survive the execution of this Agreement and the making of the Credit Facility hereunder and except for Section 9.1, which provides otherwise, will continue in full force and effect as long as any indebtedness or other obligation of Borrower to the Bank remains outstanding.

Section 9.6.No Waiver; Delay. If the Bank shall waive any power, right or remedy arising hereunder or under any applicable law, such waiver shall not be deemed to be a waiver of the later occurrence or recurrence of any of said events. No delay by the Bank in the exercise of any power, right or remedy shall, under any circumstances, constitute or be deemed to be a waiver, express or implied, of the same and no course of dealing between the parties hereto shall constitute a waiver of the Bank’s powers, rights or remedies. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

Section 9.7.Modification; Waiver. Except as otherwise provided in this Agreement, no modification or amendment hereof, or waiver or consent hereunder, shall be effective unless made in a writing signed by appropriate officers of the parties hereto. Whenever any consent, approval or waiver is requested hereunder, the determination to grant such request shall be in the Bank’s sole discretion (unless otherwise indicated).

Section 9.8.Headings. The various headings in this Agreement are inserted for convenience only and shall not affect the meaning or interpretation of this Agreement or any provision hereof.

Section 9.9.Notices. Any notice, request, consent or other communication made, given or required hereunder or in connection herewith shall be deemed satisfactorily given if in writing (including facsimile transmissions) and delivered by hand, mail (registered or certified mail) or overnight courier to the parties at their respective addresses or facsimile number set forth below or such other addresses or facsimile numbers as may be given by any party to the others in writing:

To Borrower:

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Chesapeake Utilities Corporation

909 Silver Lake Boulevard

Dover, Delaware 19904

Attention: Beth W. Cooper, Chief Financial Officer

Facsimile No.: 302-734-6750

Telephone No.: 302-734-6022

With a copy to:

Baker & Hostetler LLP

PNC Center

1900 E. Ninth Street, Suite 3200

Cleveland, Ohio 44114

Attention: Phillip M. Callesen and Matthew G. Oliver

Facsimile No.: 216-696-0740

To Bank:

Branch Banking and Trust Company

8200 Greensboro Dr. Suite 1000

McLean, VA 22102

Attention: Matt Davis, Senior Vice President

Facsimile No.: 888-707-3035

Telephone No.: 703-269-1653

Section 9.10.Payment on Non-Business Days. Whenever any payment to be made hereunder shall be stated to be due on a day other than a Business Day, such payment may be made on the next succeeding Business Day, provided however that such extension of time shall be included in the computation of interest due in conjunction with such payment or other fees due hereunder, as the case may be.

Section 9.11.Time of Day. Except as expressly provided otherwise herein, all time of day restrictions imposed herein shall be calculated using the local time in Wilmington, Delaware.

Section 9.12.Severability. If any provision of this Agreement or the application thereof to any person or circumstance shall be invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provisions to other persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 9.13.Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all the signatures on such counterparts appeared on one document, and each such counterpart shall be deemed to be an original.

Section 9.14.Consent to Jurisdiction and Service of Process. Borrower hereby consents to the exclusive jurisdiction of any state or federal court located within the District of Delaware, and irrevocably agrees that, subject to the Bank’s election, all actions or proceedings relating to the Credit Documents or the transactions contemplated hereunder shall be litigated in such courts, and Borrower waives any objection which it may have based on lack of personal jurisdiction, improper venue or forum non conveniens to the conduct of any proceeding in any such court. Nothing contained in this Section 9.14 shall

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affect the right of Bank to serve legal process in any other manner permitted by law or affect the right of Bank to bring any action or proceeding against Borrower or its property in the courts of any other jurisdiction.

Section 9.15.WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVES ANY RIGHTS IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON OR ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE NOTE OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER ORAL OR WRITTEN) OR ACTIONS OF BANK. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE BANK ENTERING INTO THIS AGREEMENT.

Section 9.16.ADDITIONAL WAIVERS; LIMITATIONS.

9.16.1.IN CONNECTION WITH ANY PROCEEDINGS UNDER THE CREDIT DOCUMENTS, INCLUDING WITHOUT LIMITATION ANY ACTION BY BANK IN REPLEVIN, FORECLOSURE OR OTHER COURT PROCESS OR IN CONNECTION WITH ANY OTHER ACTION RELATED TO THE CREDIT DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREUNDER, BORROWER WAIVES:

(a)ALL PROCEDURAL ERRORS, DEFECTS AND IMPERFECTIONS IN SUCH PROCEEDINGS;

(b)ALL BENEFITS UNDER ANY PRESENT OR FUTURE LAWS EXEMPTING ANY PROPERTY, REAL OR PERSONAL, OR ANY PART OF ANY PROCEEDS THEREOF FROM ATTACHMENT, LEVY OR SALE UNDER EXECUTION, OR PROVIDING FOR ANY STAY OF EXECUTION TO BE ISSUED ON ANY JUDGMENT RECOVERED UNDER ANY OF THE CREDIT DOCUMENTS OR IN ANY REPLEVIN OR FORECLOSURE PROCEEDING, OR OTHERWISE PROVIDING FOR ANY VALUATION, APPRAISAL OR EXEMPTION;

(c)PRESENTMENT FOR PAYMENT, DEMAND, NOTICE OF DEMAND, NOTICE OF NON-PAYMENT, PROTEST AND NOTICE OF PROTEST OF ANY OF THE CREDIT DOCUMENTS, INCLUDING THE NOTE; AND

(d)ALL RIGHTS TO CLAIM OR RECOVER REASONABLE ATTORNEY’S FEES AND COSTS IN THE EVENT THAT BORROWER IS SUCCESSFUL IN ANY ACTION TO REMOVE OR SUSPEND A JUDGMENT ENTERED BY CONFESSION.

9.16.2.FORBEARANCE. BANK MAY RELEASE, COMPROMISE, FORBEAR WITH RESPECT TO, WAIVE, SUSPEND, EXTEND OR RENEW ANY OF THE TERMS OF THE CREDIT DOCUMENTS, WITHOUT NOTICE TO BORROWER.

9.16.3.LIMITATION ON LIABILITY. BORROWER SHALL BE RESPONSIBLE FOR AND BANK IS HEREBY RELEASED FROM ANY CLAIM OR LIABILITY IN CONNECTION WITH:

(a)SAFEKEEPING ANY PROPERTY (EXCEPT FOR PROPERTY IN BANK’S POSSESSION);

(b)ANY LOSS OR DAMAGE TO ANY PROPERTY (EXCEPT FOR PROPERTY IN BANK’S POSSESSION);

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(c)ANY DIMINUTION IN VALUE OF THE PROPERTY; OR

(d)ANY ACT OR DEFAULT OF ANOTHER PERSON.

BANK SHALL ONLY BE LIABLE FOR ANY ACT OR OMISSION ON ITS PART CONSTITUTING GROSS NEGLIGENCE OR WILLFUL MISCONDUCT AS DETERMINED BY A COURT OF COMPETENT JURISDICTION IN A FINAL AND NONAPPEALABLE JUDGMENT. IN THE EVENT BORROWER BRINGS SUIT AGAINST BANK IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREUNDER AND BANK IS FOUND NOT TO BE LIABLE, BORROWER WILL INDEMNIFY AND HOLD BANK HARMLESS FROM ALL COSTS AND EXPENSES, INCLUDING REASONABLE ATTORNEY FEES AND COSTS, INCURRED BY BANK IN CONNECTION WITH SUCH SUIT. THIS AGREEMENT IS NOT INTENDED TO OBLIGATE BANK TO INCUR EXPENSES OR PERFORM ANY OBLIGATION OR DUTY OF BORROWER.

Section 9.17.ACKNOWLEDGMENTS. BORROWER ACKNOWLEDGES THAT IT HAS HAD THE ASSISTANCE OF COUNSEL IN THE REVIEW AND EXECUTION OF THIS AGREEMENT AND, SPECIFICALLY, SECTION 9.16 HEREOF, AND FURTHER ACKNOWLEDGES THAT THE MEANING AND EFFECT OF THE FOREGOING WAIVER OF JURY TRIAL AND ADDITIONAL WAIVERS HAVE BEEN FULLY EXPLAINED TO BORROWER BY SUCH COUNSEL.

Section 9.18.U.S. Patriot Act/OFAC Notice. To help the government fight the funding of terrorism and money laundering activities, Federal law requires all financial institutions to obtain, verify, and record information that identifies each Person who establishes a formal relationship with such institution. Therefore, when Borrower enters into this business relationship with Bank, Bank will ask Borrower or its officers or owners their name, address, date of birth (for individuals) and other pertinent information that will allow Bank to identify Borrower. Bank may also ask to see Borrower’s organizational documents or other identifying information.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the undersigned, by their duly authorized officers, have executed and delivered this Credit Agreement under seal the day and year first above written.

BORROWER:

ATTEST:                CHESAPEAKE UTILITIES CORPORATION

a Delaware corporation

By:

Name:                    Name:

Title:                    Title:

ACKNOWLEDGEMENT

STATE OF     :    SS

:

COUNTY OF     :

On this, the _____ day of ______________, 2017, before me, a Notary Public, the undersigned officer, personally appeared ___________________, who acknowledged himself or herself to be the ___________________________________________ of Chesapeake Utilities Corporation, a Delaware corporation, and that he or she, in such capacity, being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing on behalf of said corporation.

WITNESS my hand and seal the day and year aforesaid.

Notary Public

My Commission Expires:

[Signature page 1 of 2 to Credit Agreement]

BANK:

ATTEST:                BRANCH BANKING AND TRUST COMPANY

By:

Name:                    Name:

Title:                    Title:

ACKNOWLEDGEMENT

STATE OF ____________        :    SS

:

COUNTY OF _____________        :

On this, the _____ day of ____________, 2017, before me, the undersigned officer, personally appeared ________________, a ____________________ of Branch Banking and Trust Company, and that he as such ______________ being authorized to do so, executed the foregoing instrument for the purposes therein contained by signing the name of the bank by himself or herself as a __________________.

WITNESS my hand and seal the day and year aforesaid.

Notary Public

My Commission Expires:

[Signature page 2 of 2 to Credit Agreement]

EXHIBIT A

Borrowing Notice

NOTICE OF BORROWING

[date]

Branch Banking and Trust Company

8200 Greensboro Dr. Suite 1000

McLean, VA 22102

Attention: Matt Davis, Senior Vice President

Facsimile No.: 888-707-3035

Telephone No.: 703-269-1653

Re:    Chesapeake Utilities Corporation

Reference is made to that certain Credit Agreement dated as of August 31, 2017 (as amended, restated, supplemented or otherwise modified from time to time, the “Credit Agreement”), by and between Chesapeake Utilities Corporation, a Delaware corporation (the “Borrower”) and Branch Banking and Trust Company (the “Bank”). Capitalized terms used and not defined elsewhere in this letter have the meanings assigned to them in the Credit Agreement.

Pursuant to Section 2.3.1 of the Credit Agreement, the Borrower hereby (i) gives you irrevocable notice that the Borrower hereby requests an Advance under the Credit Facility in the principal amount of $__________ to be disbursed to the Borrower on [date] (the “Borrowing Date”), (ii) the interest rate selection to be applicable to this Advance is ________________________ ([Libor Advantage Rate] [[one month]/[two month]/[three month] LIBOR Rate]) and (iii) certifies that such Advance will be in compliance with the requirements set forth in the Credit Agreement.

The Borrower hereby certifies that the following statements are true on the date hereof and shall be true on and as of the Borrowing Date both before and after giving affect thereto and to the application of proceeds therefrom:

1.    No Default or Event of Default has occurred and is continuing;

2.    As of the Borrowing Date, the Borrower has been, and will be, on a pro forma basis (assuming the Funded Debt outstanding on the applicable Borrowing Date after giving effect to the Advance on the Borrowing Date and the application of the proceeds of such Advance), in compliance with the covenant set forth in Article 6 of the Credit Agreement;

3.    Repayment of the Credit Facility has not been accelerated in accordance with Section 8.2 of the Credit Agreement;

4.    The Borrower is in compliance with all terms, covenants and conditions of each Credit Document;

5.    The representations and warranties of the Borrower contained in Article 3 of the Credit Agreement are true and correct in all material respects on and as of the date of the Credit Agreement and will be true and correct in all material respects on and as of any such date after the date of the Credit Agreement with the same effect as though made on and as of the date of each Advance; and

6.    Since the date of the last audited financial statements of the Borrower delivered to the Bank, there has been no Material Adverse Effect.

The Borrower irrevocably authorizes the Bank to disburse the proceeds of the requested Advance to the Borrower’s account provided to the Bank in writing prior to the initial Advance, for credit to the Borrower (or to such other account as to which the Borrower shall instruct the Bank via Federal funds wire transfer no later than 4:00 p.m. (Eastern Standard Time).

[SIGNATURE PAGE FOLLOWS]

The Borrower has caused this letter to be executed under by its Executive Officers as of the date first written above.

ATTEST:                CHESAPEAKE UTILITIES CORPORATION

a Delaware corporation

By:

Name:                    Name:

Title:                    Title:

EXHIBIT B

STANDARD LIBOR LANGUAGE

1.    Definitions.

a.    “Adjusted LIBOR Rate” means, relative to any LIBOR Rate Loan to be made, continued or maintained as a LIBOR Rate Loan for any LIBOR Interest Period, a rate per annum determined by dividing (x) the LIBOR Rate for such LIBOR Interest Period by (y) a percentage equal to one hundred percent (100%) minus the LIBOR Reserve Percentage.

b.    “Applicable Margin” means eighty five (85) basis points (0.85%).

c.    “Business Day” means:

(1)    any day which is neither a Saturday or Sunday nor a legal holiday on which commercial banks are authorized or required to be closed in Winston-Salem, North Carolina;

(2)    when such term is used to describe a day on which a borrowing, payment, prepaying, or repaying is to be made in respect of any LIBOR Rate Loan, any day which is: (i) neither a Saturday or Sunday nor a legal holiday on which commercial banks are authorized or required to be closed in New York City; and (ii) a London Banking Day; and

(3)    when such term is used to describe a day on which an interest rate determination is to be made in respect of any LIBOR Rate Loan, any day which is a London Banking Day.

d.    “Hedging Contracts” means interest rate swap agreements, interest rate cap agreements and interest rate collar agreements, or any other agreements or arrangements entered into between the Borrower and the Bank and designed to protect the Borrower against fluctuations in interest rates or currency exchange rates.

e.    “Hedging Obligations” means, with respect to the Borrower, all liabilities of the Borrower to the Bank under Hedging Contracts.

f.    “Interest Payment Date” means, relative to (i) any LIBOR Rate Loan with a one (1) month LIBOR Interest Period, the last Business Day of such LIBOR Interest Period and (ii) any LIBOR Rate Loan with a LIBOR Interest Period greater than one (1) month or any LIBOR Advantage Rate Loan or any Prime Rate Loan, the first day of each month.

g.    “LA Interest Period” means the Libor Advantage interest period commencing on (and including) the date of the Note (the “Start Date”) and ending on the numerically corresponding date one (1) month later, and thereafter each one (1) month period ending on the day of such month that numerically corresponds to the Start Date. If a LA Interest Period is to end in a month for which there is no day which numerically corresponds to the Start Date, the LA Interest Period will end on the last day of such month. Notwithstanding the date of commencement of any LA Interest Period, interest shall only begin to accrue as of the date the LIBOR Advantage Loan is made.

h.    “LIBOR Interest Period” means relative to any LIBOR Rate Loans:

(1)    initially, the period beginning on (and including) the date on which such LIBOR Rate Loan is made or continued as a LIBOR Rate Loan and ending on (but excluding) the day which numerically corresponds to such date one, two or three months thereafter (or, if such month has no numerically corresponding day, on the last Business Day of such month), in each case as selected by Borrower by irrevocable notice to the Bank pursuant to Section 2.1.3 of this Agreement; and

(2)    thereafter, each period commencing on the last day of the preceding LIBOR Interest Period applicable to such LIBOR Rate Loan and ending one, two or three months thereafter, as selected by Borrower by irrevocable notice to the Bank pursuant to Section 2.1.3 of this Agreement;

provided, however, that

(a)    at no time may there be more than four (4) LIBOR Interest Periods in effect with respect to the LIBOR Rate Loans;

(b)    LIBOR Interest Periods commencing on the same date for LIBOR Rate Loans comprising part of the same Advance under this Agreement shall be of the same duration;

(c)    LIBOR Interest Periods for LIBOR Rate Loans in connection with which Borrower has or may incur Hedging Obligations with the Bank shall be of the same duration as the relevant periods set under the applicable Hedging Contracts;

(d)    if such LIBOR Interest Period would otherwise end on a day which is not a Business Day, such LIBOR Interest Period shall end on the next following Business Day unless such day falls in the next calendar month, in which case such LIBOR Interest Period shall end on the first preceding Business Day; and

(e)    no LIBOR Interest Period may end later than the applicable Termination Date.

i.    “LIBOR Advantage Rate” means relative to any LA Interest Period, the offered rate for deposits of U.S. dollars for a term coextensive with the designated LA Interest Period, reset daily, which the ICE Benchmark Administration (or any successor administrator of LIBOR rates) fixes as its LIBOR rate as of 11:00 a.m. London time for its delivery in two London Banking Days; provided, that if the LIBOR Advantage Rate is less than zero, it shall be deemed to be zero for purposes of this Agreement. If such day is not a London Banking Day, the LIBOR Advantage Rate shall be determined on the next preceding day that is a London Banking Day. If for any reason the Bank cannot determine such offered rate fixed by the then current administrator of LIBOR rates, the Bank may, in its sole but reasonable discretion, use an alternative method to select a rate calculated by the Bank to reflect its cost of funds.

j.    “LIBOR Advantage Rate Loan” means any loan or advance the rate of interest applicable to which is based upon the LIBOR Advantage Rate.

k.    “LIBOR Rate” means, relative to any LIBOR Interest Period, the offered rate for deposits of U.S. Dollars for a term coextensive with the designated LIBOR Interest Period which the ICE Benchmark Administration (or any successor administrator of LIBOR rates) fixes as its LIBOR rate as of 11:00 a.m. London time on the day that is two London Banking Days prior to the beginning of such LIBOR Interest Period; provided, that if the LIBOR Rate is less than zero, it shall be deemed to be zero for purposes of this Agreement. If such day is not a London Banking Day, the LIBOR Rate shall be determined on the next preceding day which is a London Banking Day. If for any reason the Bank cannot determine such offered rate by the then current administrator of LIBOR rates, the Bank may, in its sole but reasonable discretion, use an alternative method to select a rate calculated by the Bank to reflect its cost of funds.

l.    “LIBOR Rate Loan” means any loan or advance the rate of interest applicable to which is based upon the LIBOR Rate.

m.    “LIBOR Reserve Percentage” means, relative to any day of any LIBOR Interest Period, the maximum aggregate (without duplication) of the rates (expressed as a decimal fraction) of reserve requirements (including all basic, emergency, supplemental, marginal and other reserves and taking into account any transitional adjustments or other scheduled changes in reserve requirements) under any regulations of the Board of Governors of the Federal Reserve System (the “Board”) or other governmental authority having jurisdiction with respect thereto as issued from time to time and then applicable to assets or liabilities consisting of “Eurocurrency Liabilities”, as currently defined in Regulation D of the Board, having a term approximately equal or comparable to such LIBOR Interest Period.

n.    “London Banking Day” means a day on which dealings in US dollar deposits are transacted in the London interbank market.

o.    “Prime Rate” means the annual interest rate publicly announced by Bank from time to time as its prime rate. The Prime Rate is determined from time to time by Bank as a means of pricing some loans to its borrowers. The Prime Rate is not tied to any external rate of interest or index, and does not necessarily reflect the lowest rate of interest actually charged by Bank to any particular class or category of customers. If and when the Prime Rate changes, the rate of interest with respect to any amounts hereunder to which the Prime Rate applies will change automatically without notice to Borrower, effective on the date of any such change.

p.    “Prime Rate Loan” means any loan for the period(s) when the rate of interest applicable to such Loan is calculated by reference to the Prime Rate.

q.    “Prime Rate Margin” means zero (0) basis points (0.00%) per annum.

2.Borrowing Procedure. Advances shall be made in accordance with the terms of the Agreement.

3.    Repayment, Prepayments and Interest.

a.    Repayments Continuations. All LIBOR Rate Loans shall mature and become payable in full on the last day of the LIBOR Interest Period relating to such LIBOR Rate Loan. Upon maturity, a LIBOR Rate Loan shall be continued for an additional LIBOR Interest Period.

b.    Interest Provisions. Interest on the outstanding principal amount of each loan, when classified as a: (i) LIBOR Rate Loan, shall accrue during each LIBOR Interest Period at a rate per annum equal to the sum of the Adjusted LIBOR Rate for such LIBOR Interest Period plus the Applicable Margin, and be due and payable on each Interest Payment Date and on the applicable Termination Date, (ii) LIBOR Advantage Rate Loan, shall accrue daily at a rate per annum equal to the sum of the LIBOR Advantage Rate plus the Applicable Margin, and be due and payable on each Interest Payment Date and on the applicable Termination Date and (iii) Prime Rate Loan, shall accrue at a rate per annum equal to the sum of the Prime Rate plus the Prime Rate Margin, and be due and payable on each Interest Payment Date and on the applicable Termination Date. The Bank shall determine each interest rate applicable to the Advances hereunder in accordance with the terms of this Agreement, and its determination thereof shall be conclusive in the absence of manifest error.

c.    Voluntary Prepayment of LIBOR Rate Loans. LIBOR Rate Loans and LIBOR Advantage Rate Loans may be prepaid upon the terms and conditions set forth herein. For LIBOR Rate Loans and LIBOR Advantage Rate Loans in connection with which the Borrower has or may incur Hedging Obligations, additional obligations may be associated with prepayment, in accordance with the terms and conditions of the applicable Hedging Contracts. The Borrower shall give the Bank, no later than 10:00 a.m., New York City time, at least four (4) Business Days notice of any proposed prepayment of any LIBOR Rate Loans and LIBOR Advantage Rate Loans, specifying the proposed date of payment of such LIBOR Rate Loans and LIBOR Advantage Rate Loans, and the principal amount to be paid. Each partial prepayment of the principal amount of LIBOR Rate Loans and LIBOR Advantage Rate Loans shall be in an integral multiple of $10,000 and accompanied by the payment of all charges outstanding on such LIBOR Rate Loans (including the LIBOR Breakage Fee) and LIBOR Advantage Rate Loans and of all accrued interest on the principal repaid to the date of payment.

d.    LIBOR Breakage Fees. Upon: (i) any default by Borrower in making any borrowing of or continuation of any LIBOR Rate Loan following Borrower’s delivery of a borrowing request or continuation notice hereunder or under the Agreement or (ii) any prepayment of a LIBOR Rate Loan on any day that is not the last day of the relevant LIBOR Interest Period (regardless of the source of such prepayment and whether voluntary, by acceleration or otherwise), the Borrower shall pay an amount (“LIBOR Breakage Fee”), as calculated by the Bank, equal to the amount of any losses, expenses and liabilities (including without limitation any loss of margin and anticipated profits) that Bank may sustain as a result of such default or payment. The Borrower understands, agrees and acknowledges that: (i) the Bank does not have any obligation to purchase, sell and/or match funds in connection with the use of the LIBOR Rate as a basis for calculating the rate of interest on a LIBOR Rate Loan, (ii) the LIBOR Rate may be used merely as a reference in determining such rate, and (iii) the Borrower has accepted the LIBOR Rate as a reasonable and fair basis for calculating the LIBOR Breakage Fee and other funding losses incurred by the Bank. Borrower further agrees to pay the LIBOR Breakage Fee and other funding losses, if any, whether or not the Bank elects to purchase, sell and/or match funds.

4.Miscellaneous LIBOR Rate Loan Terms.

a.    LIBOR Rate Lending Unlawful. If the Bank shall determine (which determination shall, upon notice thereof to the Borrower, be conclusive and binding on the Borrower) that the introduction of or any change in or in the interpretation of any law, rule, regulation or guideline, (whether or not having the force of law) makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for the Bank to make, continue or maintain any LIBOR Rate Loan as a LIBOR Rate Loan and/or a LIBOR Advantage Rate Loan as a LIBOR Advantage Rate Loan, the obligations of the Bank to make, continue or maintain any such LIBOR Rate Loans and/or LIBOR Advantage Rate Loans shall, upon such determination, forthwith be suspended until the Bank shall notify the Borrower that the circumstances causing such suspension no longer exist, and all LIBOR Rate Loans and/or LIBOR Advantage Rate Loans of such type shall automatically convert into Prime Rate Loans at the end of the then current LIBOR Interest Periods (or in the case of LIBOR Advantage Rate Loans, the same day) with respect thereto or sooner, if required by such law or assertion.

b.    Unavailability of LIBOR Rate. In the event that Borrower shall have requested a LIBOR Rate Loan and/or a LIBOR Advantage Rate Loan in accordance with the Note and this Agreement and the Bank, in its sole discretion, shall have determined that U.S. dollar deposits in the relevant amount and for the relevant LIBOR Interest Period are not available to the Bank in the London interbank market; or by reason of circumstances affecting the Bank in the London interbank market, adequate and reasonable means do not exist for ascertaining the LIBOR Rate and/or the LIBOR Advantage Rate applicable to the relevant LIBOR Interest Period; or the LIBOR Rate or the LIBOR Advantage Rate no longer adequately and fairly reflects the Bank’s cost of funding loans; upon notice from the Bank to the Borrower, the obligations of the Bank hereunder and under this Agreement to make or continue any loans as, or to convert any loans into, LIBOR Rate Loans and/or LIBOR Advantage Rate Loans of such duration shall forthwith be suspended until the Bank shall notify the Borrower that the circumstances causing such suspension no longer exist.

c.    Increased Costs. If, on or after the date hereof, the adoption of any applicable law, rule or regulation or guideline (whether or not having the force of law), or any change therein, or any change in the interpretation or administration thereof by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Bank with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency: (a) shall impose, modify or deem applicable any reserve, special deposit or similar requirement (including, without limitation, any such requirement imposed by the Board of Governors of the Federal Reserve System of the United States) against assets of, deposits with or for the account of, or credit extended by, the Bank or shall impose on the Bank or on the London interbank market any other condition affecting its LIBOR Rate Loans, LIBOR Advantage Rate Loans or its obligation to make LIBOR Rate Loans or LIBOR Advantage Rate Loans; or (b) shall impose on the Bank any other condition affecting its LIBOR Rate Loans, LIBOR Advantage Rate Loans or its obligation to make or maintain LIBOR Rate Loans or LIBOR Advantage Rate Loans (a “Change in Law”), and the result of any of the foregoing is to increase the cost to the Bank of making or maintaining any LIBOR Rate Loan or LIBOR Advantage Rate Loans hereunder, or to reduce the amount of any sum received or receivable by the Bank under this Agreement with respect thereto, by an amount deemed by the Bank to be material, then, the Borrower shall pay to the Bank, in accordance with terms herein, such additional amount or amounts as will compensate the Bank for such increased cost or reduction.

d.    Increased Capital Costs. If any change in, or the introduction, adoption, effectiveness, interpretation, reinterpretation or phase-in of, any law or regulation, directive, guideline, decision or request (whether or not having the force of law) of any court, central bank, regulator or other governmental authority affects or would affect the amount of capital required to be maintained by the Bank, or person controlling the Bank (a “Change in Capital Law”), and the Bank determines that the rate of return on its or such controlling person’s capital as a consequence of its commitments hereunder or the loans made by the Bank under this Agreement is reduced to a level below that which the Bank or such controlling person could have achieved but for the occurrence of such Change in Capital Law, then, in any such case upon notice from time to time by the Bank to the Borrower, the Borrower shall promptly pay directly to the Bank additional amounts sufficient to compensate the Bank or such controlling person for such reduction in rate of return.

e.    Procedures for Payment of Increased Costs.

(1)    A certificate of the Bank as to any additional amount or amounts (including calculations thereof in reasonable detail) to compensate the Bank, as specified in Section 4(c)or 4(d), shall be delivered to the Borrower and shall, in the absence of manifest error, be conclusive and binding on the Borrower. In determining such amount, the Bank may use any method of averaging and attribution that it (in good faith, but in its sole and absolute discretion) shall deem applicable. The Borrower shall pay the Bank the amount shown as due on any such certificate within fifteen (15) days after receipt thereof.

(2)    Failure or delay on the part of the Bank to demand compensation pursuant to the foregoing provisions of Section 4(c)or 4(d) shall not constitute a waiver of the Bank’s right to demand such compensation, provided that the Borrower shall not be required to compensate the Bank pursuant to the foregoing provisions of this Section for any increased costs incurred or reductions suffered more than three (3) months prior to the date that the Bank notifies the Borrower of the Change in Law or the Change in Capital Law giving rise to such increased costs or reductions and of the Bank’s intention to claim compensation therefor (except that, if the Change in Law or the Change in Capital Law giving rise to such increased costs or reductions is retroactive, then the three (3) month period referred to above shall be extended to include the period of retroactive effect thereof).

f.    Taxes. All payments by the Borrower of principal of, and interest on, LIBOR Rate Loans, LIBOR Advantage Rate Loans, Prime Rate Loans and all other amounts payable under the Credit Documents shall be made free and clear of and without deduction for any present or future income, excise, stamp or franchise taxes and other taxes, fees, duties, withholdings or other charges of any nature whatsoever imposed by any taxing authority, but excluding franchise taxes and taxes imposed on or measured by the Bank’s net income or receipts (such non-excluded items being called “Taxes”). In the event that any withholding or deduction from any payment to be made by the Borrower hereunder is required in respect of any Taxes pursuant to any applicable law, rule or regulation, then the Borrower will:

(1)    pay directly to the relevant authority the full amount required to be so withheld or deducted;

(2)    promptly forward to the Bank an official receipt or other documentation satisfactory to the Bank evidencing such payment to such authority; and

(3)    pay to the Bank such additional amount or amounts as is necessary to ensure that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section 4(f)) the net amount actually received by the Bank will equal the full amount the Bank would have received had no such withholding or deduction been required.

Moreover, if any Taxes are directly asserted against the Bank with respect to any payment received by the Bank hereunder, the Bank may pay such Taxes and the Borrower will promptly pay such additional amount (including any penalties, interest or expenses) as is necessary in order that the net amount received by the Bank after the payment of such Taxes (including any Taxes on such additional amount) shall equal the amount the Bank would have received had not such Taxes been asserted.

If the Borrower fails to pay any Taxes when due to the appropriate taxing authority or fails to remit to the Bank the required receipts or other required documentary evidence, the Borrower shall indemnify the Bank for any incremental Taxes, interest or penalties that may become payable by the Bank as a result of any such failure.

EXHIBIT C

Compliance Certificate

(INSERT DATE)

Branch Banking and Trust Company

8200 Greensboro Dr. Suite 1000

McLean, VA 22102

Attention: Matt Davis, Senior Vice President

Facsimile No.: 888-707-3035

Telephone No.: 703-269-1653

I, , _____(Title)_____, do hereby certify on behalf of Chesapeake Utilities Corporation (“Borrower”) as of the quarter ended (the “Report Date”), as follows:

1.) Funded Debt to Total Capitalization. The Funded Debt to Total Capitalization (as defined in the Credit Agreement) is ________________, which is in compliance with the required maximum Funded Debt to Total Capitalization of 65% for the test period end date of _____________________.

2.) The representations and warranties of the Borrower contained in the Credit Agreement and in the other Credit Documents (as defined in the Credit Agreement) are true on and as of this date with the same effect as though such representations and warranties have been made on and as of the date hereof and the Borrower has performed and complied in all respects with all covenants and conditions thereof.

3.) [No event has occurred and is continuing or exists as of the date hereof, which constitutes a Default or an Event of Default (as each term is defined in the Credit Agreement)]

IN WITNESS WHEREOF, the undersigned has executed this Certificate on this _____ day of _____________________, 20_____.

By:

Name:

Title:

22

WCSR 39139774v4

EX-10.23

Term Note
(LIBOR ONLY – DESIGNATED RATE RESET)

$30,000,000.00                                        December ____, 2018

FOR VALUE RECEIVED, CHESAPEAKE UTILITIES CORPORATION (the “Borrower”), with an address at 909 Silver Lake Boulevard, Dover, DE 19904, promises to pay to the order of PNC BANK,NATIONAL ASSOCIATION (the “Bank”), in lawful money of the United States of America in immediately available funds at its offices located at 222 Delaware Avenue, Wilmington, DE 19801, or at such other location as the Bank may designate from time to time, the principal sum of THIRTY MILLION AND 00/100 DOLLARS($30,000,000.00) (the “Facility”), together with interest accruing on the outstanding principal balance from the date hereof, all as provided below.

1.    Rate of Interest.  Amounts outstanding under this Note will bear interest at a rate per annum equal to the sum of (A) LIBOR in effect on each Reset Date plus (B) seventy-five (75) basis points (0.75%). Interest hereunder will be calculated based on the actual number of days that principal is outstanding over a year of 360 days. In no event will the rate of interest hereunder exceed the maximum rate allowed by law.

For purposes hereof, the following terms shall have the following meanings:

“Business Day” shall mean any day other than a Saturday or Sunday or a legal holiday on which commercial banks are authorized or required by law to be closed for business in New York, New York.

“LIBOR” shall mean, for each Reset Date, the interest rate per annum determined by the Bank by dividing (i) the rate which appears on the Bloomberg Page BBAM1 (or on such other substitute Bloomberg page that displays rates at which US dollar deposits are offered by leading banks in the London interbank deposit market), or the rate which is quoted by another source selected by the Bank as an authorized information vendor for the purpose of displaying rates at which US dollar deposits are offered by leading banks in the London interbank deposit market (an “Alternate Source”), at approximately 11:00 a.m., London time, two (2) Business Days prior to such Reset Date, as the one (1) monthLondon interbank offered rate for U.S. Dollars commencing on such Reset Date (or if there shall at any time, for any reason, no longer exist a Bloomberg Page BBAM1 (or any substitute page) or any Alternate Source, a comparable replacement rate determined by the Bank at such time (which determination shall be conclusive absent manifest error)), by (ii) a number equal to 1.00 minus the LIBOR Reserve Percentage; provided, however, if LIBOR, determined as provided above, would be less than zero, then LIBOR shall be deemed to be zero.

“LIBOR Reserve Percentage” shall mean the maximum effective percentage in effect on such day as prescribed by the Board of Governors of the Federal Reserve System (or any successor) for determining the reserve requirements (including, without limitation, supplemental, marginal and emergency reserve requirements) with respect to eurocurrency funding (currently referred to as “Eurocurrency liabilities”).

“Reset Date” shall mean (i) the date of this Note, and (ii) subject to the proviso below, the _____ day of every month thereafter, provided that: (a) if any such day is not a Business Day, then the first succeeding day that is a Business Day shall instead apply, unless that day falls in the next succeeding calendar month, in which case the next preceding day that is a Business Day shall instead apply, and (b) if any such day is a day of a calendar month for which there is no numerically corresponding day in certain other months (each, a “Non-Conforming Month”), then any Reset Date that falls within a Non-Conforming Month shall be the last Business Day of such Non-Conforming Month.

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

LIBOR shall be adjusted on and as of (a) each Reset Date, and (b) the effective date of any change in the LIBOR Reserve Percentage. The Bank shall give prompt notice to the Borrower of LIBOR as determined or adjusted in accordance herewith, which determination shall be conclusive absent manifest error.

If the Bank determines (which determination shall be final and conclusive) that, by reason of circumstances affecting the eurodollar market generally, deposits in dollars (in the applicable amounts) are not being offered to banks in the eurodollar market for the selected term, or adequate means do not exist for ascertaining LIBOR, then the Bank shall give notice thereof to the Borrower. Thereafter, until the Bank notifies the Borrower that the circumstances giving rise to such suspension no longer exist, (a) the availability of LIBOR shall be suspended, and (b) the interest rate for all amounts outstanding under this Note shall be converted on the next succeeding Reset Date to a rate of interest per annum equal to the Prime Rate (the “Base Rate”). For purposes hereof, the term“Prime Rate” shall mean the rate publicly announced by the Bank from time to time as its prime rate. The Prime Rate is determined from time to time by the Bank as a means of pricing some loans to its borrowers. The Prime Rate is not tied to any external rate of interest or index, and does not necessarily reflect the lowest rate of interest actually charged by the Bank to any particular class or category of customers. If and when the Prime Rate changes, the rate of interest with respect to any amounts hereunder to which the Base Rate applies will change automatically without notice to the Borrower, effective on the date of any such change.

In addition, if, after the date of this Note, the Bank shall determine (which determination shall be final and conclusive) that any enactment, promulgation or adoption of or any change in any applicable law, rule or regulation, or any change in the interpretation or administration thereof by a governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Bank with any guideline, request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency shall make it unlawful or impossible for the Bank to make or maintain or fund loans based on LIBOR, the Bank shall notify the Borrower. Upon receipt of such notice, until the Bank notifies the Borrower that the circumstances giving rise to such determination no longer apply, (a) the availability of LIBOR shall be suspended, and (b) the interest rate on all amounts outstanding under this Note shall be converted to the Base Rate either (i) on the next succeeding Reset Date if the Bank may lawfully continue to maintain or fund loans based on LIBOR to such day, or (ii) immediately if the Bank may not lawfully continue to maintain or fund loans based on LIBOR.

2.    Payment Terms. Interest shall be due and payable monthly, commencing on the first Reset Date after the date of this Note, and continuing on each succeeding Reset Date thereafter until January__, 2020(the “MaturityDate”), on which date all outstanding principal and accrued interest shall be due and payable in full. If any payment under this Note shall become due on a day other than a Business Day, such payment shall be made on the next succeeding Business Day, unless that day falls in the next succeeding calendar month, in which case such payment shall be made on the next preceding day that is a Business Day. The Borrower hereby authorizes the Bank to charge the Borrower’s deposit account at the Bank for any payment when due hereunder.Payments received will be applied to charges, fees and expenses (including attorneys’ fees), accrued interest and principal in any order the Bank may choose, in its sole discretion.

3.    Late Payments; Default Rate. If the Borrower fails to make any payment of principal, interest or other amount coming due pursuant to the provisions of this Note within fifteen (15) calendar days of the date due and payable, the Borrower also shall pay to the Bank a late charge equal to the lesser of five percent (5%) of the amount of such payment or $100.00 (the “Late Charge”). Such fifteen (15) day period shall not be construed in any way to extend the due date of any such payment. Upon maturity, whether by acceleration, demand or otherwise, and at the Bank’s option upon the occurrence of any Event of Default (as hereinafter defined) and during the continuance thereof, amounts outstanding under this Note shall bear interest at a rate per annum (based on the actual number of days that principal is outstanding over a year of 360 days) which shall be three percentage points (3%) in excess of the interest rate then in effect until the next succeeding Reset Date, and three percentage points (3%) in excess of the Base Rate at all times thereafter (or in the case of an Event of Default, until such time that such Event of Default has been cured by the Borrower or waived by the Bank), but in any such event not more than the maximum rate allowed by law (the “Default Rate”). The Default Rate shall continue to apply whether or not judgment shall be entered on this Note. Both the Late Charge and the Default Rate are imposed as liquidated damages for the purpose of defraying the Bank’s expenses incident to the handling of delinquent payments, but are in addition to, and not in lieu of, the Bank’s exercise of any rights and remedies hereunder, under the other Loan Documents or under applicable

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

law, and any fees and expenses of any agents or attorneys which the Bank may employ. In addition, the Default Rate reflects the increased credit risk to the Bank of carrying a loan that is in default. The Borrower agrees that the Late Charge and Default Rate are reasonable forecasts of just compensation for anticipated and actual harm incurred by the Bank, and that the actual harm incurred by the Bank cannot be estimated with certainty and without difficulty.

4.    Prepayment. The Borrower shall have the right to prepay any amount hereunder at any time and from time to time, in whole or in part; subject, however, to payment of any break funding indemnification amounts owing pursuant to paragraph 6 below.

5.Increased Costs; Yield Protection. On written demand, together with written evidence of the justification therefor, the Borrower agrees to pay the Bank all direct costs incurred, any losses suffered or payments made by the Bank as a result of any Change in Law (hereinafter defined), imposing any reserve, deposit, allocation of capital or similar requirement (including without limitation, Regulation D of the Board of Governors of the Federal Reserve System) on the Bank, its holding company or any of their respective assets relative to the Facility. “Change in Law” means the occurrence, after the date of this Note, of any of the following: (a) the adoption or taking effect of any law, rule, regulation or treaty, (b) any change in any law, rule, regulation or treaty or in the administration, interpretation, implementation or application thereof by any governmental authority or (c) the making or issuance of any request, rule, guideline or directive (whether or not having the force of law) by any governmental authority; provided that notwithstanding anything herein to the contrary, (x) the Dodd-Frank Wall Street Reform and Consumer Protection Act and all requests, rules, guidelines or directives thereunder or issued in connection therewith and (y) all requests, rules, guidelines or directives promulgated by the Bank for International Settlements, the Basel Committee on Banking Supervision (or any successor or similar authority) or the United States or foreign regulatory authorities, in each case pursuant to Basel III, shall in each case be deemed to be a “Change in Law”, regardless of the date enacted, adopted or issued.

6.    Break Funding Indemnification. The Borrower agrees to indemnify the Bank against any liabilities, losses or expenses (including, without limitation, loss of margin, any loss or expense sustained or incurred in liquidating or employing deposits from third parties, and any loss or expense incurred in connection with funds acquired to effect, fund or maintain any amounts hereunder (or any part thereof) bearing interest based on LIBOR) which the Bank sustains or incurs as a consequence of either (i) the Borrower’s failure to make a payment on the due date thereof, (ii) the Borrower’s revocation (expressly, by later inconsistent notices or otherwise) in whole or in part of any notice given to Bank to request, convert, renew or prepay any amounts bearing interest based on LIBOR, or (iii) the Borrower’s payment or prepayment (whether voluntary, after acceleration of the maturity of this Note or otherwise) or conversion of any amounts bearing interest based on LIBOR on a day other than the regularly scheduled due date therefor. A notice as to any amounts payable pursuant to this paragraph given to the Borrower by the Bank shall, in the absence of manifest error, be conclusive and shall be payable upon demand. The Borrower’s indemnification obligations hereunder shall survive the payment in full of all amounts payable hereunder.

7.    Other Loan Documents. This Note is issued in connection with a Letter Agreement between the Borrower and the Bank, dated on September 26, 2003, as amended, and the other agreements and documents executed and/or delivered in connection therewith or referred to therein, the terms of which are incorporated herein by reference (as amended, modified or renewed from time to time, collectively the “Loan Documents”), and is secured by the property (if any) described in the Loan Documents and by such other collateral as previously may have been or may in the future be granted to the Bank to secure this Note.

8.    Events of Default. The occurrence of any of the following events will be deemed to be an “Event of Default” under this Note: (i) the nonpayment of any principal, interest or other indebtedness under this Note when due; (ii) the occurrence of any event of default or any default and the lapse of any notice or cure period, or any Obligor’s failure to observe or perform any covenant or other agreement, under or contained in any Loan Document or any other document now or in the future evidencing or securing any debt, liability or obligation of any Obligor to the Bank; (iii) the filing by or against any Obligor of any proceeding in bankruptcy, receivership, insolvency, reorganization, liquidation, conservatorship or similar proceeding (and, in the case of any such proceeding instituted against any Obligor, such proceeding is not dismissed or stayed within 30 days of the commencement thereof, provided that the Bank shall not be obligated to advance additional funds hereunder during such period); (iv) any

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

assignment by any Obligor for the benefit of creditors, or any levy, garnishment, attachment or similar proceeding is instituted against any property of any Obligor held by or deposited with the Bank; (v) a default with respect to any other indebtedness of any Obligor for borrowed money in excess of $5,000,000, individually or in the aggregate, if the effect of such default is to cause or permit the acceleration of such debt; (vi) the commencement of any foreclosure or forfeiture proceeding, execution or attachment against any collateral securing the obligations of any Obligor to the Bank; (vii) the entry of one or more final judgment(s) against any Obligor in excess of $5,000,000, individually or in the aggregate and the failure of such Obligor to discharge the judgment within thirty (30) days of the entry thereof; (viii) any change in any Obligor’s business, assets, operations, financial condition or results of operations that has or could reasonably be expected to have any material adverse effect on any Obligor; (ix) any Obligor ceases doing business as a going concern; (x) any representation or warranty made by any Obligor to the Bank in any Loan Document or any other documents now or in the future evidencing or securing the obligations of any Obligor to the Bank, is false, erroneous or misleading in any material respect; (xi) if this Note or any guarantee executed by any Obligor is secured (other than security described in section 5 of the Amended and Restated Working Cash, Line of Credit, Investment Sweep Rider dated as of February 26, 2016 between the Borrower and the Bank), the failure of any Obligor to provide the Bank with additional collateral if in the Bank’s opinion at any time or times, the market value of any of the collateral securing this Note or any guarantee has depreciated below that required pursuant to the Loan Documents or, if no specific value is so required, then in an amount deemed material by the Bank; (xii) the revocation or attempted revocation, in whole or in part, of any guarantee by any Obligor; or (xiii) the death, incarceration, indictment or legal incompetency of any individual Obligor or, if any Obligor is a partnership or limited liability company, the death, incarceration, indictment or legal incompetency of any individual general partner or member. As used herein, the term “Obligor” means any Borrower and any guarantor of, or any pledgor, mortgagor or other person or entity providing collateral support for, the Borrower’s obligations to the Bank existing on the date of this Note or arising in the future.

Upon the occurrence of an Event of Default: (a) the Bank shall be under no further obligation to make advances hereunder; (b) if an Event of Default specified in clause (iii) or (iv) above shall occur, the outstanding principal balance and accrued interest hereunder together with any additional amounts payable hereunder shall be immediately due and payable without demand or notice of any kind; (c) if any other Event of Default shall occur, the outstanding principal balance and accrued interest hereunder together with any additional amounts payable hereunder, at the Bank’s option and without demand or notice of any kind, may be accelerated and become immediately due and payable; (d) at the Bank’s option, this Note will bear interest at the Default Rate from the date of the occurrence of the Event of Default; and (e) the Bank may exercise from time to time any of the rights and remedies available under the Loan Documents or under applicable law.

9.    Power to Confess Judgment. The Borrower hereby empowers any attorney of any court of record, after the occurrence of any Event of Default hereunder, to appear for the Borrower and, with or without complaint filed, confess judgment, or a series of judgments, against the Borrower in favor of the Bank or any holder hereof for the entire principal balance of this Note, all accrued interest and all other amounts due hereunder, together with costs of suit and an attorney’s commission of the greater of 10% of such principal and interest or $1,000 added as a reasonable attorney’s fee, and for doing so, this Note or a copy verified by affidavit shall be a sufficient warrant. The Borrower hereby forever waives and releases all errors in said proceedings and all rights of appeal and all relief from any and all appraisement, stay or exemption laws of any state now in force or hereafter enacted. The Borrower acknowledges and agrees that, pursuant to the foregoing power to confess judgment granted to the Bank, the Borrower is voluntarily and knowingly waiving its right to notice and a hearing prior to the entry of a judgment by the Bank against the Borrower. Interest on any such judgment shall accrue at the Default Rate.

No single exercise of the foregoing power to confess judgment, or a series of judgments, shall be deemed to exhaust the power, whether or not any such exercise shall be held by any court to be invalid, voidable, or void, but the power shall continue undiminished and it may be exercised from time to time as often as the Bank shall elect until such time as the Bank shall have received payment in full of the debt, interest and costs. Notwithstanding the attorney’s commission provided for in the preceding paragraph (which is included in the warrant for purposes of establishing a sum certain), the amount of attorneys’ fees that the Bank may recover from the Borrower shall not exceed the actual attorneys’ fees incurred by the Bank.

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

10.    Right of Setoff. In addition to all liens upon and rights of setoff against the Borrower’s money, securities or other property given to the Bank by law, the Bank shall have, with respect to the Borrower’s obligations to the Bank under this Note and to the extent permitted by law, a contractual possessory security interest in and a contractual right of setoff against, and the Borrower hereby grants the Bank a security interest in, and hereby assigns, conveys, delivers, pledges and transfers to the Bank, all of the Borrower’s right, title and interest in and to, all of the Borrower’s deposits, moneys, securities and other property now or hereafter in the possession of or on deposit with, or in transit to, the Bank or any other direct or indirect subsidiary of The PNC Financial Services Group, Inc., whether held in a general or special account or deposit, whether held jointly with someone else, or whether held for safekeeping or otherwise, excluding, however, all IRA, Keogh, and trust accounts. Every such security interest and right of setoff may be exercised without demand upon or notice to the Borrower. Every such right of setoff shall be deemed to have been exercised immediately upon the occurrence of an Event of Default hereunder without any action of the Bank, although the Bank may enter such setoff on its books and records at a later time.

11.Anti-Money Laundering/International Trade Law Compliance. The Borrower represents and warrants to the Bank, as of the date of this Note, the date of each advance of proceeds under the Facility, the date of any renewal, extension or modification of the Facility, and at all times until the Facility has been terminated and all amounts thereunder have been indefeasibly paid in full, that: (a) no Covered Entity (i) is a Sanctioned Person; (ii) has any of its assets in a Sanctioned Country or in the possession, custody or control of a Sanctioned Person; or (iii) does business in or with, or derives any of its operating income from investments in or transactions with, any Sanctioned Country or Sanctioned Person in violation of any law, regulation, order or directive enforced by any Compliance Authority; (b) the proceeds of the Facility will not be used to fund any operations in, finance any investments or activities in, or, make any payments to, a Sanctioned Country or Sanctioned Person in violation of any law, regulation, order or directive enforced by any Compliance Authority; (c) the funds used to repay the Facility are not derived from any unlawful activity; and (d) each Covered Entity is in compliance with, and no Covered Entity engages in any dealings or transactions prohibited by, any laws of the United States, including but not limited to any Anti-Terrorism Laws. Borrower covenants and agrees that it shall immediately notify the Bank in writing upon the occurrence of a Reportable Compliance Event.

As used herein: “Anti-Terrorism Laws” means any laws relating to terrorism, trade sanctions programs and embargoes, import/export licensing, money laundering, or bribery, all as amended, supplemented or replaced from time to time; “Compliance Authority”means each and all of the (a) U.S. Treasury Department/Office of Foreign Assets Control, (b) U.S. Treasury Department/Financial Crimes Enforcement Network, (c) U.S. State Department/Directorate of Defense Trade Controls, (d) U.S. Commerce Department/Bureau of Industry and Security, (e) U.S. Internal Revenue Service, (f) U.S. Justice Department, and (g) U.S. Securities and Exchange Commission; “Covered Entity” means the Borrower, its affiliates and subsidiaries, all guarantors, pledgors of collateral, all owners of the foregoing, and all brokers or other agents of the Borrower acting in any capacity in connection with the Facility; “Reportable Compliance Event” means that any Covered Entity becomes a Sanctioned Person, or is indicted, arraigned, investigated or custodially detained, or receives an inquiry from regulatory or law enforcement officials, in connection with any Anti-Terrorism Law or any predicate crime to any Anti-Terrorism Law, or self-discovers facts or circumstances implicating any aspect of its operations with the actual or possible violation of any Anti-Terrorism Law; “Sanctioned Country” means a country subject to a sanctions program maintained by any Compliance Authority; and “Sanctioned Person” means any individual person, group, regime, entity or thing listed or otherwise recognized as a specially designated, prohibited, sanctioned or debarred person or entity, or subject to any limitations or prohibitions (including but not limited to the blocking of property or rejection of transactions), under any order or directive of any Compliance Authority or otherwise subject to, or specially designated under, any sanctions program maintained by any Compliance Authority.

12.    Indemnity. The Borrower agrees to indemnify each of the Bank, each legal entity, if any, who controls, is controlled by or is under common control with the Bank, and each of their respective directors, officers and employees (the “Indemnified Parties”), and to defend and hold each Indemnified Party harmless from and against any and all claims, damages, losses, liabilities and expenses (including all fees and charges of internal or external counsel with whom any Indemnified Party may consult and all expenses of litigation and preparation therefor) which any Indemnified Party may incur or which may be asserted against any Indemnified Party by any person, entity or governmental authority (including any person or entity claiming derivatively on behalf of the Borrower), in connection

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

with or arising out of or relating to the matters referred to in this Note or in the other Loan Documents or the use of any advance hereunder, whether (a) arising from or incurred in connection with any breach of a representation, warranty or covenant by the Borrower, or (b) arising out of or resulting from any suit, action, claim, proceeding or governmental investigation, pending or threatened, whether based on statute, regulation or order, or tort, or contract or otherwise, before any court or governmental authority; provided, however, that the foregoing indemnity agreement shall not apply to any claims, damages, losses, liabilities and expenses solely attributable to an Indemnified Party's gross negligence or willful misconduct. The indemnity agreement contained in this Section shall survive the termination of this Note, payment of any amounts hereunder and the assignment of any rights hereunder. The Borrower may participate at its expense in the defense of any such action or claim.

13.    Miscellaneous. All notices, demands, requests, consents, approvals and other communications required or permitted hereunder (“Notices”) must be in writing (except as may be agreed otherwise above with respect to borrowing requests or as otherwise provided in this Note) and will be effective upon receipt. Notices may be given in any manner to which the parties may agree. Without limiting the foregoing, first-class mail, postage prepaid, facsimile transmission and commercial courier service are hereby agreed to as acceptable methods for giving Notices. In addition, the parties agree that Notices may be sent electronically to any electronic address provided by a party from time to time. Notices may be sent to a party’s address as set forth above or to such other address as any party may give to the other for such purpose in accordance with this paragraph. No delay or omission on the Bank’s part to exercise any right or power arising hereunder will impair any such right or power or be considered a waiver of any such right or power, nor will the Bank’s action or inaction impair any such right or power. The Bank’s rights and remedies hereunder are cumulative and not exclusive of any other rights or remedies which the Bank may have under other agreements, at law or in equity. No modification, amendment or waiver of, or consent to any departure by the Borrower from, any provision of this Note will be effective unless made in a writing signed by the Bank, and then such waiver or consent shall be effective only in the specific instance and for the purpose for which given. Notwithstanding the foregoing, the Bank may modify this Note for the purposes of completing missing content or correcting erroneous content, without the need for a written amendment, provided that the Bank shall send a copy of any such modification to the Borrower (which notice may be given by electronic mail). The Borrower agrees to pay on demand, to the extent permitted by law, all costs and expenses incurred by the Bank in the enforcement of its rights in this Note and in any security therefor, including without limitation reasonable fees and expenses of the Bank’s counsel. If any provision of this Note is found to be invalid, illegal or unenforceable in any respect by a court, all the other provisions of this Note will remain in full force and effect. The Borrower and all other makers and indorsers of this Note hereby forever waive presentment, protest, notice of dishonor and notice of non-payment. The Borrower also waives all defenses based on suretyship or impairment of collateral. If this Note is executed by more than one Borrower, the obligations of such persons or entities hereunder will be joint and several. This Note shall bind the Borrower and its heirs, executors, administrators, successors and assigns, and the benefits hereof shall inure to the benefit of the Bank and its successors and assigns; provided, however, that the Borrower may not assign this Note in whole or in part without the Bank’s written consent and the Bank at any time may assign this Note in whole or in part.

This Note has been delivered to and accepted by the Bank and will be deemed to be made in the State where the Bank’s office indicated above is located. THIS NOTE WILL BE INTERPRETED AND THE RIGHTS AND LIABILITIES OF THE BANK AND THE BORROWER DETERMINED IN ACCORDANCE WITH THE LAWS OF THE STATE WHERE THE BANK’S OFFICE INDICATED ABOVE IS LOCATED, EXCLUDING ITS CONFLICT OF LAWS RULES, INCLUDING WITHOUT LIMITATION THE ELECTRONIC TRANSACTIONS ACT (OR EQUIVALENT) IN EFFECT IN THE STATE WHERE THE BANK’S OFFICE INDICATED ABOVE IS LOCATED (OR, TO THE EXTENT CONTROLLING, THE LAWS OF THE UNITED STATES OF AMERICA, INCLUDING WITHOUT LIMITATION THE ELECTRONIC SIGNATURES IN GLOBAL AND NATIONAL COMMERCE ACT).The Borrower hereby irrevocably consents to the exclusive jurisdiction of any state or federal court in the county or judicial district where the Bank’s office indicated above is located; provided that nothing contained in this Note will prevent the Bank from bringing any action, enforcing any award or judgment or exercising any rights against the Borrower individually, against any security or against any property of the Borrower within any other county, state or other foreign or domestic jurisdiction. The Borrower acknowledges and agrees that the venue provided above is the most convenient forum for both the Bank and the Borrower. The Borrower waives any objection to venue and any objection based on a more convenient forum in any action instituted under this Note.

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

14.    Commercial Purpose. The Borrower represents that the indebtedness evidenced by this Note is being incurred by the Borrower solely for the purpose of acquiring or carrying on a business, professional or commercial activity, and not for personal, family or household purposes.

15.    USA PATRIOT Act Notice. To help the government fight the funding of terrorism and money laundering activities, Federal law requires all financial institutions to obtain, verify and record information that identifies each Borrower that opens an account. What this means: when the Borrower opens an account, the Bank will ask for the business name, business address, taxpayer identifying number and other information that will allow the Bank to identify the Borrower, such as organizational documents. For some businesses and organizations, the Bank may also need to ask for identifying information and documentation relating to certain individuals associated with the business or organization.

16.    Authorization to Obtain Credit Reports. By signing below, each Borrower who is an individual provides written authorization to the Bank or its designee (and any assignee or potential assignee hereof) to obtain the Borrower’s personal credit profile from one or more national credit bureaus. Such authorization shall extend to obtaining a credit profile in considering this Note and subsequently for the purposes of update, renewal or extension of such credit or additional credit and for reviewing or collecting the resulting account.

17.Electronic Signatures and Records. Notwithstanding any other provision herein, the Borrower agrees that this Note, the Loan Documents, any amendments thereto, and any other information, notice, signature card, agreement or authorization related thereto (each, a “Communication”) may, at the Bank’s option, be in the form of an electronic record. Any Communication may, at the Bank’s option, be signed or executed using electronic signatures. For the avoidance of doubt, the authorization under this paragraph may include, without limitation, use or acceptance by the Bank of a manually signed paper Communication which has been converted into electronic form (such as scanned into PDF format) for transmission, delivery and/or retention.

REMAINDER OF PAGE INTENTIONALLY LEFT BLANK

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

18.    WAIVER OF JURY TRIAL.THE BORROWER IRREVOCABLY WAIVES ANY AND ALL RIGHTS THE BORROWER MAY HAVE TO A TRIAL BY JURY IN ANY ACTION, PROCEEDING OR CLAIM OF ANY NATURE RELATING TO THIS NOTE, ANY DOCUMENTS EXECUTED IN CONNECTION WITH THIS NOTE OR ANY TRANSACTION CONTEMPLATED IN ANY OF SUCH DOCUMENTS. THE BORROWER ACKNOWLEDGES THAT THE FOREGOING WAIVER IS KNOWING AND VOLUNTARY.

The Borrower acknowledges that it has read and understood all the provisions of this Note, including the confession of judgment and the waiver of jury trial, and has been advised by counsel as necessary or appropriate.

WITNESS the due execution hereof as a document under seal, as of the date first written above, with the intent to be legally bound hereby.

WITNESS / ATTEST:	CHESAPEAKE UTILITIES CORPORATION
_________________________________	By:__________________________________
	Beth Cooper (SEAL) Senior Vice President and CFO
Print Name:_______________________
Title:____________________________
(Include title only if an officer of entity signing to the right)

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Form 8G – DE/MD/PA (COJ) Rev. 6/17

EX-10.24

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, 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 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

4843-6634-5054.3

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.

(h)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

4843-6634-5054.3

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.

4843-6634-5054.3

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

4843-6634-5054.3

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:

4843-6634-5054.3

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. Northwest Natural Gas Company

6. Northwestern Corporation

7. OneGas, Inc.

8. RGC Resources, Inc.

9. South Jersey Industries, Inc.

10. Spire, Inc.

11. Unitil Corporation

4843-6634-5054.3

EX-10.25

EXECUTIVE EMPLOYMENT AGREEMENT

This Executive Employment Agreement (the "Agreement") dated this 25^th day of February, 2019, is hereby made by and between Chesapeake Utilities Corporation, a Delaware corporation (the "Company"), and Jeffry M. Householder (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 President and Chief Executive Officer;

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 President and Chief Executive Officer (“CEO”); 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 President and CEO 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 President and Chief Executive Officer, 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, operating the Company in compliance with the goals, policies, and objectives established by the Board of Directors. The Executive shall report directly to the Board of Directors 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 [ ] year(s) commencing on January 1, 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

1

Initials ____

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).

(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

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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 occurred with respect to the Executive by reason of (1) any event involving a transaction in which the Executive or a group of persons or entities with which the Executive acts in concert, acquires, directly or indirectly, more than thirty percent (30%) of the Common Stock of the business or assets of the Company; or (2) any event involving or arising out of a proceeding under Title 11 of the United States Code (or the provisions of any future United States bankruptcy law), or an assignment for the benefit of creditors or an insolvency proceeding under state or local law.

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 withheld.

4.    Office.

(a)    Current Term. During the Current Term, the Executive shall serve as the Company's President and Chief Executive Officer 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.

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(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 Dover, Delaware, and Executive shall not be required, without his written consent, to change his office location or to be absent therefrom on business for more than sixty (60) working days in any year.

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 $600,000 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 2013 Stock and Incentive Compensation Plan. Executive shall be eligible for an incentive compensation award as granted on an annual basis by the Board during the Term of this Agreement with a target award based upon one hundred percent (100%) of the Executive’s Base Compensation, 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 during the Term of this Agreement.

(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 sixty percent (60%) of Executive’s Base Compensation, as determined on an

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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,

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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.

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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 Executive resulting or intended to result directly or indirectly in material gain to or personal enrichment of Executive at the Company's expense;

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(iii)    a willful failure by Executive (except by reason of incapacity due to illness or accident) to to perform his/her duties as CEO and/or to comply with the provisions of Paragraph 1; 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 or that is in material violation of the policies of the Company.

Termination of the Executive’s employment shall not be deemed to be for Cause unless and until the Company delivers a written notice to the Executive finding that the Executive has engaged in the conduct described above. Except for a failure or refusal that, by its nature, cannot reasonably be expected to be cured, the Executive shall have ten (10) business days from the delivery of the written notice by the Company within which to cure any acts constituting Cause. However, if the Company reasonably expects irreparable harm from a delay of ten (10) business days, the Company may give the Executive notice of such shorter period (or no period) within which to cure as is reasonable under the circumstances. The Company’s decision regarding the basis for termination, if concluded, shall be final and binding on the parties.

(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 thirty-six (36) 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

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years immediately preceding the calendar year in which the Extended Termination Date occurs by three (3) 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 the Release (referenced in Paragraph 6(a) above) 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

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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 employment following the occurrence of any of the following events:

(A)    failure to elect or re-elect Executive to, or removal of Executive from, the office or offices set forth in Paragraph 1, or failure to nominate Executive for election to the Board if Executive shall have been a member of the Board immediately prior to a Change in Control of the Company, provided, however, that election or appointment of another person as President shall not be considered a violation of this provision if Executive continues to serve as CEO;

(B)    a significant change in the nature or scope of the Executive’s authorities, powers, functions, duties or responsibilities attached to the positions contemplated in Paragraph 1, or a reduction in his compensation or in the benefits available to the Executive and his family, as provided in Paragraph 5, unless such reduction in compensation or benefits is part of and consistent with an across-the-board reduction applicable to all executive officers that does not exceed 10% in amount, and 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

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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 Corporate Secretary, 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

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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:

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(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.

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(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

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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.

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(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), including the advance of expenses permitted herein. In the event that the Executive is made a party or threatened to be made a party to any action, suit, or proceeding, whether civil, criminal, administrative, or investigative (a “Proceeding”), other than any Proceeding initiated by the Executive or the Company related to any contest or dispute between the Executive and the Company or any of its affiliates with respect to this Agreement or the Executive’s employment hereunder, by reason of the fact that the Executive is or was a director or officer of the Company, or any affiliate of the Company, or is or was serving at the request of the Company as a director, officer, member, employee, or agent of another corporation or a partnership, joint venture, trust, or other enterprise, the Executive shall be indemnified and held harmless by the Company to the maximum extent permitted under applicable law and the Company’s

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

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

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

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

24.    Prior Agreement. The Company and the Executive are parties to an Executive Employment Agreement executed on January 1, 2015 (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 acknowledge that each has read this Agreement and understands the same and that each enters into this Agreement freely and voluntarily.

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

CHESAPEAKE UTILITIES CORPORATION

[CORPORATE SEAL]            By:    ______________________________

Title: ______________________________

ATTEST:                        

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__________________________

EXECUTIVE:

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EX-10.26

TERM LOAN CREDIT AGREEMENT

by and between

BRANCH BANKING AND TRUST COMPANY

and

CHESAPEAKE UTILITIES CORPORATION

January 31, 2019

TERM LOAN CREDIT AGREEMENT

THIS TERM LOAN CREDIT AGREEMENT (the “Agreement”) is made as of the 31st day of January, 2019, by and between CHESAPEAKE UTILITIES CORPORATION, a Delaware corporation (“Borrower”), and BRANCH BANKING AND TRUST COMPANY (“Bank”). Borrower and Bank agree, under seal, as follows:

BACKGROUND

A.    Borrower desires that Bank extend to Borrower a $30,000,000.00 term loan (the “Term Loan”).

B.    Bank is willing to make the Term Loan available to Borrower, subject to the terms and conditions hereof.

ARTICLE 1
DEFINITIONS

Section 1.1.Definitions. When used in this Agreement, the following terms shall have the respective meanings set forth below.

1.1.1.Reserved.

1.1.2.Reserved.

1.1.3.Reserved.

1.1.4.“Affiliate” means as to any Person, each other Person that directly or indirectly, through one or more intermediaries, controls, is controlled by or is under common control with the Person in question. For purposes of this definition, “control” means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of an entity, whether through the ownership of voting securities, by contract, or otherwise.

1.1.5.“Agreement” means this Term Loan Credit Agreement and all exhibits and schedules hereto, as each may be amended, renewed, replaced, supplemented or otherwise modified from time to time in accordance with the terms of this Agreement.

1.1.6.“Applicable Margin” has the meaning ascribed to such term on Exhibit A attached hereto and made a part hereof.

1.1.7.“Bank” means Branch Banking and Trust Company, and its successors and assigns pursuant to Section 9.3 hereof.

1.1.8.“Bank Indebtedness” means all obligations and indebtedness of Borrower to Bank, whether now or hereafter owing or existing, including without limitation all obligations under the Credit Documents, all obligations under any interest rate swap agreements or arrangements with the Bank designed to protect the Borrower against fluctuations in interest rates or currency exchange rates, and all other obligations or undertakings now or hereafter made by or for the benefit of Borrower under any other agreement, promissory note or undertaking now existing or hereafter entered into by Borrower with Bank related to the Credit Documents, including, without limitation, all obligations of Borrower to Bank under any guaranty or surety agreement and all obligations of Borrower to immediately pay to Bank the amount of any overdraft on any deposit account maintained with Bank, together with all interest and other sums payable in connection with any of the foregoing (including without limitation interest and fees that accrue after the commencement by or against Borrower or any Affiliate thereof of any proceeding under any Debtor Relief Law naming such Person as the debtor in such proceeding, regardless of whether such interest and fees are allowed claims in such proceeding).

1.1.9.“Beneficial Ownership Certification” means a certification regarding beneficial ownership as required by the Beneficial Ownership Regulation.

1.1.10.“Beneficial Ownership Regulation” means 31 C.F.R. § 1010.230.

1.1.11.“Borrower” means Chesapeake Utilities Corporation, a Delaware corporation.

1.1.12.“Business Day” has the meaning ascribed to such term on Exhibit A attached hereto.

1.1.13.“Closing Date” means the date on which all the conditions set forth in Article4 have been satisfied.

1.1.14. “Code” means the Internal Revenue Code of 1986, as amended from time to time, and all rules and regulations with respect thereto in effect from time to time.

1.1.15. “Credit Documents” means this Agreement, the Note and any other agreements, documents, instruments and writings now or hereafter existing, creating, evidencing, guarantying, securing or relating to any of the liabilities of Borrower to the Bank together with all amendments, modifications, renewals or extensions thereof.

1.1.16. “Debtor Relief Law” means the Bankruptcy Code of the United States, and all other liquidation, conservatorship, bankruptcy, assignment for the benefit of creditors, moratorium, rearrangement, receivership, insolvency, reorganization, or similar debtor relief laws of the United States or other applicable jurisdictions from time to time in effect and affecting the rights of creditors generally.

1.1.17.“Default” means an event, condition or circumstance the occurrence of which would, with the giving of notice or the passage of time, or both, constitute an Event of Default.

1.1.18.“Default Rate” has the meaning set forth in Section 2.2 hereof.

1.1.19.“Dollars” or “$” means the lawful currency of the United States.

1.1.20.“Environmental Control Statutes” means any federal, state, county, regional or local laws governing the control, storage, removal, spill, release or discharge of Hazardous Substances, including without limitation CERCLA, the Solid Waste Disposal Act, as amended by the Resource Conservation and Recovery Act of 1976 and the Hazardous and Solid Waste Amendments of 1984, the Federal Water Pollution Control Act, as amended by the Clean Water Act of 1976, the Hazardous Materials Transportation Act, the Emergency Planning and Community Right to Know Act of 1986, the National Environmental Policy Act of 1975, the Oil Pollution Act of 1990, any similar or implementing state law, and in each case including all amendments thereto and all rules and regulations promulgated thereunder and permits issued in connection therewith.

1.1.21.“EPA” means the United States Environmental Protection Agency, or any successor thereto.

1.1.22. “ERISA” means the Employee Retirement Income Security Act of 1974, as amended from time to time, any successor statute of similar import, and all rules and regulations with respect thereto in effect from time to time.

1.1.23.“ERISA Affiliate” means any Person that is a member of any group or organization within the meaning of Code sections 414(b), (c), (m) or (o) of which Borrower is a member.

1.1.24.“Event of Default” means an event described in Section 8.1 hereof.

1.1.25.“Existing Credit Agreement” means that certain Credit Agreement, dated as of October 8, 2015, by and among the Borrower, the lenders party thereto and PNC Bank, National Association as administrative agent, swing loan lender and issuing lender, as amended, restated, refinanced, extended, replaced, supplemented or otherwise modified from time to time.

1.1.26.“Funded Debt” means all indebtedness for borrowed money having an original term of more than one year, including, but not limited to, capitalized lease obligations, reimbursement obligations in respect of letters of credit, and guaranties of any such indebtedness.

1.1.27.“GAAP” means generally accepted accounting principles as in effect in the United States of America set forth in the Opinions of the Accounting Principles Board of the American Institute of Certified Public Accountants and in statements of the Financial Accounting Standards Board and in such other statements by such other entity as Bank may reasonably approve, which are applicable in the circumstances as of the date in question; and such principles observed in a current period shall be comparable in all material respects to those applied in a preceding period.

1.1.28. “Hazardous Substance” means petroleum products and items defined in the Environmental Control Statutes as “hazardous substances”, “hazardous wastes”, “pollutants” or “contaminants” and any other toxic, reactive, corrosive, carcinogenic, flammable or hazardous substance or other pollutant.

1.1.29.“Indebtedness” means:

(a)means (i) all obligations of such Person for borrowed money or with respect to deposits or advances of any kind, (ii) all obligations of such Person evidenced by bonds, debentures, notes or similar instruments, (iii) all obligations of such Person upon which interest charges are customarily paid, (iv) all obligations of such Person in respect of the deferred purchase price of property or services (excluding current accounts payable incurred in the ordinary course of business), (v) all obligations, contingent or otherwise, of such Person as an account party in respect of letters of credit and letters of guaranty and (vi) all obligations, contingent or otherwise, of such Person in respect of bankers’ acceptance.

(b)all indebtedness, obligations, and liabilities secured by any mortgage, pledge, lien, conditional sale or other title retention agreement or other security interest to which any property or asset owned or held by such Person is subject, whether or not the indebtedness, obligations or liabilities secured thereby shall have been assumed by such Person; and

(c)to the extent not included in the foregoing, all indebtedness, obligations and liabilities of others which such Person has directly or indirectly guaranteed, endorsed (other than for collection or deposit in the ordinary course of business), sold with recourse, or agreed (contingently or otherwise) to purchase or repurchase or otherwise acquire or in respect of which such Person has agreed to supply or advance funds (whether by way of loan, stock purchase, capital contribution or otherwise) or otherwise to become directly or indirectly liable.

1.1.30.“Interest Rate” means the LIBOR Rate or, if applicable pursuant to Exhibit A attached hereto, the Prime Rate.

1.1.31.“Late Charge” has the meaning set forth in Section 2.2 hereof.

1.1.32.“Material Adverse Effect” means either singly or in the aggregate, the occurrence of any event, condition, circumstance or proceeding that materially and adversely affects the financial condition or operations of the Borrower and its Subsidiaries taken as a whole or the Borrower’s ability to perform its obligations under this Agreement and the other Credit Documents.

1.1.33.Reserved.

1.1.34.“Maturity Date” means February 28, 2020.

1.1.35.“Most Favored Lender Provision” means a provision in any agreement with respect to any Indebtedness for borrowed money of the Borrower (or its Subsidiaries) which requires that such agreement be amended or deemed amended to incorporate any covenant or provision in any other agreement with respect to any other Indebtedness for borrowed money of the Borrower (or its Subsidiaries) that is more restrictive on the Borrower (or its Subsidiaries) or more beneficial to the holder thereof.

1.1.36.“Note” shall mean the promissory note, dated of even date herewith, of the Borrower payable to the order of the Bank, as the same may be amended, renewed, replaced, or supplemented from time to time, evidencing the Term Loan.

1.1.37.“PBGC” means the Pension Benefit Guaranty Corporation, or any successor thereto.

1.1.38.“Person” means an individual, corporation, trust, limited partnership, general partnership, limited liability company or unincorporated association, governmental entity, agency, instrumentality, or political subdivision thereof, or any other form of entity or organization.

1.1.39.“Plan” means any pension benefit or welfare benefit plan as defined in sections 3(1), (2) or (3) of ERISA maintained or sponsored by, contributed to, or covering employees of, Borrower or any ERISA Affiliate.

1.1.40.“Prime Rate” has the meaning ascribed on Exhibit A attached hereto.

1.1.41.“Regulation D” means Regulation D of the Board of Governors of the Federal Reserve System, comprising Part 204 of Title 12, Code of Federal Regulations, as amended from time to time, and any successor thereto.

1.1.42.“Release” means any spill, leak, emission, discharge, release or the pumping, pouring, emptying, disposing, injecting, escaping, leaching or dumping of a Hazardous Substance.

1.1.43. “Subsidiary” of any Person at any time means any corporation, trust, partnership, limited liability company or other business entity (i) of which more than 50% of the outstanding voting securities or other interests normally entitled to vote for the election of one or more directors, managers, managing members, trustees or similar positions (regardless of any contingency which does or may suspend or dilute the voting rights) is at such time owned directly or indirectly by such Person or one or more of such Person’s Subsidiaries, or (ii) which is controlled or capable of being controlled by such Person or one or more of such Person's Subsidiaries.

1.1.44. “Term Loan Commitment” has the meaning set forth in Section 2.1.

Section 1.2.Rules of Construction, Interpretation.

1.2.1.GAAP. Except as otherwise provided herein, financial and accounting terms used in the foregoing definitions or elsewhere in this Agreement, shall be defined in accordance with GAAP. Where the character or amount of any asset or liability or item of income or expense is required to be determined or any consolidation or other accounting computation is required to be made for the purposes of this Agreement, the same shall be done in accordance with GAAP, to the extent applicable, except where such principles are inconsistent with the requirements of this Agreement.

1.2.2.Directly or Indirectly. Where any provision in this Agreement refers to action to be taken by any Person, or that such person is prohibited from taking, such provision shall be applicable whether the action in question is taken directly or indirectly by such Person.

1.2.3.Plural / Singular. Except as otherwise provided herein, capitalized terms used in the foregoing definitions or elsewhere in this Agreement that are defined in the singular may also be used in the plural and any such terms which are defined in the plural may also be used in the singular.

1.2.4.Uniform Commercial Code. Except as otherwise provided herein, capitalized terms used in the foregoing definitions or elsewhere in this Agreement that are defined in the Uniform Commercial Code, including without limitation, “Accounts,” “Documents,” “Instruments,” “General Intangibles,” and “Chattel Paper” shall have the respective meanings ascribed to such terms in the Uniform Commercial Code as in effect in the State of Delaware from time to time (“UCC”).

ARTICLE 2
TERM LOAN

Section 2.1.The Term Loan. The Bank agrees, subject to the terms and conditions set forth hereof and in reliance on the representations and warranties set forth herein, to make a Term Loan to Borrower on the Closing Date in the principal amount of Thirty Million and NO/100 Dollars ($30,000,000) (the “Term Loan Commitment”). Amounts repaid or prepaid under the Term Loan may not be reborrowed. Bank shall have no obligation to advance funds in excess of the amount of the Term Loan Commitment or to advance the Term Loan after the Closing Date.

2.1.1.Promissory Note. The indebtedness of the Borrower to the Bank under the Term Loan is evidenced by the Note. The original principal amount of the Note will be the amount of the Term Loan Commitment.

2.1.1.Use of Proceeds. Funds advanced under the Term Loan shall be used solely for Borrower’s working capital and other general corporate purposes.

2.1.2.Interest and Principal Payments.

(a)Interest on the outstanding principal amount of the Term Loan shall accrue at a rate equal to the LIBOR Rate. Interest shall be calculated on the basis of the actual number of days elapsed over a year of three hundred sixty (360) days. Notwithstanding anything contained herein to the contrary, all of the provisions contained in Exhibit A attached hereto shall apply to the Term Loan. In the event that there are any inconsistencies between the terms of this Agreement and the terms contained in Exhibit A attached hereto, the terms contained in Exhibit A shall control.

(b)Commencing on the first Interest Payment Date after the date of the Closing Date and on each consecutive Interest Payment Date thereafter until and including the Interest Payment Date in February 2020, a payment shall be made equal to the sum of accrued interest on the outstanding principal balance of the Term Loan. The entire unpaid principal amount of the Term Loan, together with accrued and unpaid interest thereon and all other amounts payable in connection with the Term Loan, shall be due and payable in full on the Maturity Date.

All capitalized terms used in this Section 2.1.3 and not otherwise defined in this Agreement shall have the meanings ascribed to such terms in Exhibit A.

Section 2.2.Late Charge and Default Rate. Notwithstanding the foregoing, if the Borrower fails to make any payment of principal, interest or other amount coming due pursuant to the provisions of this Agreement or the Note within ten (10) calendar days of the date due and payable, the Borrower also shall pay to the Bank a late charge equal to three percent (3.0%) of the amount of such payment (the “Late Charge”). Such ten (10) day period shall not be construed in any way to extend the due date of any such payment. Upon maturity, whether by acceleration, demand or otherwise, and at the Bank’s option upon the occurrence of any Event of Default and during the continuance thereof, the Note shall bear interest at a rate that shall be three percentage points (3.0%) in excess of the interest rate in effect from time to time under the Note but not more than the maximum rate allowed by law (the “Default Rate”). The Default Rate shall continue to apply whether or not judgment shall be entered on this Agreement or the Note. Both the Late Charge and the Default Rate are imposed as liquidated damages for the purpose of defraying the Bank’s expenses incident to the handling of delinquent payments, but are in addition to, and not in lieu of, the Bank’s exercise of any rights and remedies hereunder, under the other Credit Documents or under applicable law, and any fees and expenses of any agents or attorneys which the Bank may employ. In addition, the Default Rate reflects the increased credit risk to the Bank of carrying a loan that is in default. The Borrower agrees that the Late Charge and Default Rate are reasonable forecasts of just compensation for anticipated and actual harm incurred by the Bank, and that the actual harm incurred by the Bank cannot be estimated with certainty and without difficulty.

Section 2.3.Reserved.

Section 2.4.Reserved.

Section 2.5.Prepayment; Mandatory Repayment.

2.5.1.Borrower may prepay the outstanding principal balance under the Term Loan at any time without premium or penalty, provided that Borrower shall comply with the prepayment provisions set forth on Exhibit A attached hereto.

Section 2.6.Payments; Application. All payments of principal, interest, fees and other amounts due hereunder, including any prepayments thereof, shall be made by Borrower to the Bank in immediately available funds before twelve o’clock (12:00) noon on any Business Day at the office of the Bank set forth in Section 9.9 hereof or to such other office or location as the Bank from time to time so notifies Borrower. All payments to be made by the Borrower shall be made without condition or deduction for any counterclaim, defense, recoupment or setoff. Borrower hereby authorizes the Bank to charge any account maintained by Borrower with the Bank from time to time for all payments of principal, interest, fees and costs when due hereunder. Any and all payments on account of the Term Loan will be applied to accrued and unpaid interest, outstanding principal and other sums due hereunder or under the Credit Documents, in such order as Bank, in its discretion, elects. If Borrower makes a payment or payments and such payment or payments, or any part thereof, are subsequently invalidated, declared to be fraudulent or preferential, set aside or are required to be repaid to a trustee, receiver, or any other person under any bankruptcy act, state, provincial or federal law, common law or equitable cause, then to the extent of such payment or payments, the obligations or part thereof hereunder intended to be satisfied shall be revived and continued in full force and effect as if said payment or payments had not been made.

ARTICLE 3
REPRESENTATIONS AND WARRANTIES

Borrower represents and warrants as follows:

Section 3.1.Organization; Good Standing; Qualification. Borrower is a corporation duly formed and validly existing under the laws of the State of Delaware. Each Subsidiary is a corporation, limited liability company, partnership or other entity duly formed and validly existing under the laws of its state of incorporation or organization. Borrower has full power and authority to execute, deliver and comply with the Credit Documents, and each of Borrower and its Subsidiaries has full power and authority to carry on its business as it is now being conducted. Each of Borrower and its Subsidiaries is duly licensed or qualified as a corporation, limited liability company, partnership or other entity in each jurisdiction where the failure to be so qualified would have a Material Adverse Effect.

Section 3.2.Licenses. Each of Borrower and its Subsidiaries has all licenses, registrations, approvals and other authority as may be necessary to enable it to own and operate its business and perform all services and business that it has agreed to perform in any state, municipality or other jurisdiction, and the same are valid, binding and enforceable without any adverse limitations thereon, except where the failure to have any or all such licenses, registrations, approvals or other authority would not have a Material Adverse Effect.

Section 3.3.Most Favored Lender Provision. No agreement with respect to any Indebtedness for borrowed money of Borrower or its Subsidiaries with an original maturity of five (5) years or less includes a Most Favored Lender Provision.

Section 3.4.Accuracy of Information; Full Disclosure.

3.4.1All financial statements furnished to Bank concerning the Borrower and its Subsidiaries in accordance with the terms of the Agreement have been prepared in accordance with GAAP and fairly present the financial condition of Borrower and such Subsidiaries as of the dates and for the periods covered, subject, in each case of any unaudited interim financial statements to normal year-end adjustments, and there has been no material adverse change in the financial condition or business of Borrower, its Subsidiaries or such other entities considered as a whole from the date of such statements to the date hereof; and

3.4.2    All financial statements and other documents furnished by Borrower to the Bank in connection with this Agreement do not and will not contain any untrue statement of material fact or omit to state a material fact necessary in order to make the statements contained therein not misleading. As of the date of this Agreement, no Material Adverse Effect has occurred or is continuing to occur.

Section 3.5.Pending Litigation or Proceedings. As of the date of this Agreement, there are no judgments outstanding or actions, suits or proceedings pending or, to Borrower’s knowledge, threatened against or affecting Borrower or any of its Subsidiaries, at law or in equity or before or by any federal, provincial, state, municipal or other governmental department, commission, board, bureau, court, agency or instrumentality, domestic or foreign, which, if adversely determined, could reasonably be expected to have a Material Adverse Effect.

Section 3.6.Due Authorization; No Legal Restrictions. Borrower has the power and authority under the laws of the state of its organization, and under its organizational documents, to enter into and perform this Agreement, the Note, the other Credit Documents and other agreements and documents required hereunder and to which it is a party. The execution and delivery by Borrower of the Credit Documents to which it is a party, the consummation of the transactions contemplated by the Credit Documents and the fulfillment and compliance with the respective terms, conditions and provisions of the Credit Documents: (a) have been duly authorized by all requisite corporate action of Borrower and (b) will not conflict with or result in a breach of, or constitute a default (or might, upon the passage of time or the giving of notice or both, constitute a default) under, any of the terms, conditions or provisions of any statute, law, rule, regulation or ordinance applicable to Borrower or any Subsidiary of Borrower or Borrower’s incorporation documents or by-laws, or any material indenture, mortgage, loan or credit agreement or instrument to which Borrower or any Subsidiary of Borrower is a party or by which it may be bound or affected, or any judgment or order of any court or governmental department, commission, board, bureau, agency or instrumentality, domestic or foreign, except in the case of clause (b) where such conflict, breach, default or violation would not have a Material Adverse Effect.

Section 3.7.Enforceability. The Credit Documents have been duly executed by Borrower and delivered to Bank and constitute legal, valid and binding obligations of Borrower, enforceable in accordance with their terms.

Section 3.8.Compliance with Laws, Agreements, Other Obligations, Orders or Governmental Regulations. Neither Borrower nor any of its Subsidiaries is in default of its respective formation documents or by-laws or other applicable organizational documents. Neither Borrower has nor any of its Subsidiaries have been declared in default of the performance or observance of any of its obligations, covenants or conditions contained in any material indenture or other agreement creating, evidencing or securing any Indebtedness or pursuant to which any such Indebtedness is issued. Neither Borrower is nor any of its Subsidiaries are in violation of or in default under any other agreement or instrument or any judgment, decree, order, statute, rule or governmental regulation, applicable to it or by which its properties may be bound or affected, except to the extent such violation or default is not reasonably likely to have a Material Adverse Effect.

Section 3.9.Governmental Consents, No Violations of Laws or Agreements. No consent, approval or authorization of or designation, declaration or filing with any governmental authority on the part of Borrower or any Subsidiary of Borrower which has not already been obtained is required in connection with the execution, delivery or performance by Borrower of the Credit Documents or the consummation of the transactions contemplated thereby.

Section 3.10.Taxes. Each of Borrower and its Subsidiaries has filed all material tax returns which it is required to file, if any, and has paid, or made provision for the payment of, all taxes which have or may have become due pursuant to such returns or pursuant to any assessment received by it. Such tax returns are complete and accurate in all material respects.

Section 3.11.Addresses. As of the date of this Agreement, during the past twelve (12) months, Borrower has not been known by any names (including trade names) other than its current name and the chief executive office of Borrower has not been located at any addresses other than the address of Borrower identified in Section 9.9.

Section 3.12.Current Compliance. Borrower is currently in compliance with all of the terms and conditions of the Credit Documents.

Section 3.13.Reserved.

Section 3.14.Intellectual Property. Each of Borrower and its Subsidiaries owns or possesses the right to use all of the material patents, trademarks, service marks, trade names, copyrights, licenses, franchises and permits and rights with respect to the foregoing necessary to own and operate its properties and to carry on its business as presently conducted and presently planned to be conducted without conflict with the rights of others, except for those conflicts that, individually or in the aggregate, would not have a Material Adverse Effect.

Section 3.15.Business Interruptions. Except for natural disasters such as hurricanes and similar significant weather events, within five (5) years prior to the date hereof, neither the business nor operations of Borrower or any of its Subsidiaries have been materially and adversely affected in any way by any casualty, strike, lockout, combination of workers, order of the United States of America or any state or local government, or any political subdivision or agency thereof, directed against Borrower or any of its Subsidiaries. There are no pending or threatened labor disputes, strikes, lockouts or similar occurrences or grievances against the businesses being operated by Borrower or its Affiliates.

Section 3.16.Accuracy of Representations and Warranties. No representation or warranty by Borrower contained herein or in any certificate or other document furnished by Borrower pursuant hereto or in connection herewith fails to contain any statement of material fact necessary to make such representation or warranty not misleading in light of the circumstances under which it was made. There is no fact which Borrower knows or should know and has not disclosed to Bank, which does or may materially and adversely affect Borrower or any of its Subsidiaries or any of Borrower’s or any of its Subsidiaries’ operations.

Section 3.17.Reserved.

Section 3.18.No Extension of Credit for Securities. Neither Borrower nor any of its Subsidiaries is now, nor at any time has it been engaged principally, or as one of its important activities, in the business of extending or arranging for the extension of credit, for the purpose of purchasing or carrying any “margin stock” or “margin securities” within the meaning of Regulations U, G, T or X of the Board of Governors of the Federal Reserve System; nor will the proceeds of the Term Loan be used by Borrower or any of its Subsidiaries directly or indirectly, for such purposes.

Section 3.19.Hazardous Wastes, Substances and Petroleum Products.

3.19.1.Each of Borrower and its Subsidiaries (i) have received all material permits and filed all material notifications required by the Environmental Control Statutes to carry on its respective business(es); and (ii) are in compliance with all Environmental Control Statutes, except where the failure to comply would not, individually or in the aggregate, reasonably be expected to result in a Material Adverse Effect.

3.19.2.Neither Borrower nor any of its Subsidiaries has received written notice that it is potentially responsible for clean-up, remediation, costs of clean-up or remediation, fines or penalties with respect to any actual or imminently threatened Release of Hazardous Substances pursuant to any Environmental Control Statute, except as would not reasonably be expected to result in a Material Adverse Effect.

Section 3.20.Foreign Assets Control Regulations. Neither the borrowing of the Term Loan by Borrower nor the use of the proceeds thereof by the Borrower or any of its Subsidiaries will violate foreign assets, trade or similar control regulations.

Section 3.21.Investment Company Act. Neither Borrower nor any of its Subsidiaries is directly or indirectly controlled by or acting on behalf of any person which is an “investment company” within the meaning of the Investment Company Act of 1940, as amended.

ARTICLE 4
CONDITIONS

Section 4.1.Disbursement of the Term Loan. The obligation of the Bank to make the Term Loan shall be subject to the Bank’s receipt of the following documents, each in form and substance satisfactory to the Bank:

4.1.1.Delivery of Credit Documents. The Credit Documents shall have been properly executed, as applicable, and delivered to the Bank.

4.1.1.Organizational and Authorization Documents. Certified copies of the organizational documents of Borrower and resolutions authorizing the execution, delivery and performance of the Credit Documents by Borrower.

4.1.2.Certificates of Good Standing. Certificate of good standing issued by the Delaware Secretary of State for Borrower.

4.1.3.Insurance. Certificates of insurance with respect to all of the Borrower’s fire, casualty, liability and other insurance covering its respective property and business required under Section 5.6 hereof.

4.1.4.Beneficial Ownership. If the Borrower qualifies as a “legal entity customer” under the Beneficial Ownership Regulation, Bank shall have received, or had access to, at least three (3) Business Days prior to the Closing Date, a Beneficial Ownership Certification in relation to the Borrower.

4.1.5.Other Documents. The execution and delivery by Borrower to Bank at Borrower’s sole cost and expense of any and all documents, agreements and corporate resolutions, as Bank shall reasonably request in connection with the execution and delivery of this Agreement, the Credit Documents or any other documents in connection herewith, each of which shall be in form and content reasonably acceptable to Bank.

4.1.6.Searches. Uniform Commercial Code, tax, judgment, litigation and lien searches against Borrower in those offices and jurisdictions as the Bank shall reasonably request.

4.1.7.Opinion. A legal opinion from Borrower’s counsel in form and substance satisfactory to Bank.

4.1.8.Closing Certificate. A certificate, dated as of the Closing Date, signed by an authorized officer of the Borrower to the effect that (i) no Default or Event of Default hereunder has occurred and is continuing on such date or after giving effect to this Agreement and the other Credit Documents and the disbursement of the Term Loan occurring on such date and (ii) the representations and warranties of the Borrower contained in this Agreement and the other Credit Documents are true on and as of such date and after giving effect to this Agreement and the other Credit Documents and the disbursement of the Term Loan occurring on such date.

4.1.9.Other Documents. Such additional documents as the Bank reasonably may request, including, but not limited to, the items set forth on the closing checklist delivered by Bank to Borrower.

4.1.10.Upfront Fee; Expenses. The Borrower shall have paid to the Bank an up-front fee of Five Thousand and 00/100 Dollars ($5,000.00) and shall have paid, or reimbursed the Bank for, all fees, costs and expenses of closing the transactions contemplated hereunder and under the other Credit Documents, including the legal and other document preparation costs incurred by Bank.

Section 4.2.Reserved.

Section 4.3.Reserved.

ARTICLE 5
GENERAL COVENANTS

Borrower covenants and agrees that so long as the Term Loan or any Bank Indebtedness is outstanding, Borrower will perform and comply with, and cause each of its Subsidiaries to perform and comply with, the following covenants:

Section 5.1.Payment of Principal, Interest and Other Amounts Due. Borrower will pay when due all Bank Indebtedness and all other amounts payable by it hereunder.

Section 5.2.Merger; Consolidation. Neither Borrower nor any of its Subsidiaries will merge into or consolidate with any Person or permit any Person to merge into or consolidate with it unless (a) Borrower or such Subsidiary is the surviving entity or (b) the surviving Person after such merger or consolidation is a direct or indirect wholly-owned Subsidiary of Borrower; provided, that, with respect to clauses (a) and (b), in the event that Borrower is a constituent party to any such merger or consolidation, the Borrower shall be the surviving entity.

Section 5.3.Taxes; Claims for Labor and Materials. Each of the Borrower and its Subsidiaries will pay or cause to be paid when due all taxes, assessments, governmental charges or levies imposed upon it or its income, profits, payroll or any property belonging to it, including without limitation all withholding taxes, and all claims for labor, materials and supplies which, if unpaid, might become a lien or charge upon any of its properties or assets; provided that Borrower and its Subsidiaries shall not be required to pay any such tax (other than real estate taxes which must be paid regardless of challenge), assessment, charge, levy or claim so long as (a) the validity thereof shall be contested in good faith by appropriate proceedings promptly initiated and diligently conducted by it, and neither execution nor foreclosure sale or similar proceedings shall have been commenced in respect thereof (or such proceedings shall have been stayed pending the disposition of such contest of validity), and it shall have set aside on its books adequate reserves with respect thereto or (b) the nonpayment thereof would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 5.4.Existence; Approvals; Qualification; Business Operations; Compliance with Laws; Notification.

5.4.1.Each of the Borrower and its Subsidiaries (i) will obtain, preserve and keep in full force and effect (A) its separate existence except as otherwise permitted by Section 5.2 and (B) all rights, licenses, registrations and franchises necessary to the proper conduct of its business or affairs, the absence of which could result in a Material Adverse Effect; (ii) will qualify and remain qualified as a foreign corporation, limited liability company, partnership or other entity in each jurisdiction in which the character or location of the properties owned by it or the business transacted by it requires such qualification; (iii) will not change the nature of its present business substantially as presently conducted; and (iv) will comply with the requirements of all applicable laws and all rules, regulations (including environmental regulations) and orders of regulatory agencies and authorities having jurisdiction over it, except, in the cases of clauses (ii) and (iv), where the lack of such qualification or compliance would not, individually or in the aggregate, have a Material Adverse Effect.

5.4.2.With respect to any Environmental Control Statute, Borrower will promptly notify Bank when, in connection with the conduct of the Borrower’s or any of its Subsidiaries’ business or operations, any Person (including, without limitation, any United States federal, state or local agency) provides oral or written notification to Borrower or any Subsidiary of Borrower, or Borrower or any Subsidiary of Borrower otherwise becomes aware, of a condition with regard to an actual or imminently threatened Release of Hazardous Substances which could reasonably be expected to have a Material Adverse Effect; and notify Bank in detail promptly upon the receipt by Borrower or any of its Subsidiaries of an assertion of liability under the Environmental Control Statutes, of any actual or alleged failure to comply with, failure to perform, breach, violation or default under (with or without the passage of time) any such statutes or regulations which could reasonably be expected to have a Material Adverse Effect.

Section 5.5.Maintenance of Properties. Each of Borrower and its Subsidiaries will maintain, preserve, protect and keep or cause to be maintained, preserved, protected and kept its real and tangible personal property used or useful in the conduct of its business in good working order and condition, reasonable wear and tear excepted, and will pay and discharge when due the cost of repairs to and maintenance of the same; provided that this Section 5.5 shall not prevent the Borrower or any Subsidiary from discontinuing the operation and the maintenance of any of its properties if such discontinuance is desirable in the conduct of its business and the Borrower has concluded that such discontinuance would not, individually or in the aggregate, reasonably be expected to have a Material Adverse Effect.

Section 5.6.Insurance. Each of Borrower and its Subsidiaries will maintain insurance with commercially acceptable insurance companies as is customary for similarly situated businesses.

Section 5.7.Inspections; Examinations.

5.7.1.To the extent permitted by applicable law, Borrower authorizes all federal, state and municipal authorities to furnish to Bank copies of reports or examinations relating to Borrower or any of its Subsidiaries, whether made by Borrower or otherwise.

5.7.2.The officers of Bank, or such Persons as any of them may reasonably designate, may visit and inspect any of the properties of Borrower and any of its Subsidiaries, examine (either by Bank’s employees or by independent accountants) the books of account of Borrower and any of its Subsidiaries, and discuss the affairs, finances and accounts of Borrower and any of its Subsidiaries with their officers at such times as Bank may reasonably request; provided, however, so long as no Event of Default or Default then exists, Bank shall provide Borrower with twenty four (24) hours prior notice thereof.

Section 5.8.Reserved.

Section 5.9.Change in Control / Change to Organizational Documents. Borrower shall not permit a Change in Control of its ownership or make any amendment to its organizational documents that would have a Material Adverse Effect without the prior written consent of Bank; provided, however, that Bank shall not unreasonably withhold its consent. As used herein, “Change in Control” means any Person or group of Persons within the meaning of § 13(d)(3) of the Securities Exchange Act of 1934, as amended, becoming the beneficial owner, directly or indirectly, of 50% or more of the outstanding equity interests of Borrower.

Section 5.10.Transactions with Affiliates. Neither Borrower nor any of its Subsidiaries will enter into any material transaction or material group of related transactions (including without limitation the purchase, lease, sale or exchange of properties of any kind or the rendering of any service) with any Affiliate (other than the Borrower or a Subsidiary of the Borrower), except pursuant to the reasonable requirements of the Borrower’s or such Subsidiary’s business and upon fair and reasonable terms no less favorable to the Borrower or such Subsidiary than would be obtainable in a comparable arm’s-length transaction with a Person not an Affiliate; provided that the foregoing restriction shall not apply to the payment or grant of reasonable compensation, benefits and indemnities to any director or officer of the Borrower or any of its Subsidiaries. Notwithstanding the foregoing, nothing in this Section 5.10 shall restrict transactions with any Affiliate that have been approved by or are entered into pursuant to any orders or decisions of any governmental authority having jurisdiction over the Borrower or the applicable Subsidiary.

Section 5.11.Name or Address Change. Borrower shall not change its name or address except upon thirty (30) days prior written notice to Bank and delivery to Bank of any items reasonably requested by Bank to access to Borrower’s books and records.

Section 5.12.Notices. Borrower will promptly notify Bank of (a) the occurrence of any Event of Default, (b) the occurrence of a Default, (c) the failure of Borrower to observe any of its undertakings under the Credit Documents, or (d) any Material Adverse Effect. Any notice given pursuant to this section shall not cure or otherwise affect any Event of Default.

Section 5.13.Additional Documents and Future Actions. Borrower will, at its sole cost, take such actions and provide Bank from time to time with such agreements, documents or information as the Bank may in its reasonable discretion deem necessary or advisable to carry out the terms of the Credit Documents.

Section 5.14.Restrictions on Use of Proceeds. Neither Borrower nor any of its Subsidiaries will carry or purchase with the proceeds of the Term Loan any “margin stock” or “margin security” within the meaning of Regulations U, G, T or X of the Board of Governors of the Federal Reserve System.

Section 5.15.Reserved.

ARTICLE 6
FINANCIAL COVENANT

Except as otherwise consented in writing in advance by Bank, Borrower and its Subsidiaries will comply with the following covenant, which, unless otherwise specified, shall be tested using amounts that have been determined in accordance with GAAP:

Section 6.1.Funded Debt / Total Capitalization. The Borrower will maintain at all times a ratio of Funded Debt of the Borrower and its consolidated Subsidiaries to the sum of Funded Debt of the Borrower and its consolidated Subsidiaries plus stockholder’s equity of the Borrower and its consolidated Subsidiaries of not more than sixty five percent (65%) (the “Funded Debt to Total Capitalization”), to be tested at the end of each fiscal quarter.

ARTICLE 7
ACCOUNTING RECORDS, REPORTS AND FINANCIAL STATEMENTS

Borrower will maintain books of record and account in which full, correct and current entries in accordance with GAAP will be made of all of its dealings, business and affairs of Borrower and its Subsidiaries and will deliver to Bank the following:

Section 7.1.10K and Covenant Compliance Certificate. Within fifteen (15) days of filing, the Form 10K of Borrower filed with the Securities and Exchange Commission. Together with the delivery of each Form 10K, Borrower shall provide to Bank a compliance certificate in the form attached hereto as Exhibit B, including a certificate of Borrower’s chief financial officer that no Event of Default or Default then exists or if an Event of Default or Default exists, the nature and duration thereof and Borrower’s intention with respect thereto.

Section 7.2.10Q and Covenant Compliance Certificate. Within fifteen (15) days of filing, the Form 10Q of Borrower filed with the Securities and Exchange Commission. Together with the delivery of each Form 10Q, Borrower shall provide to Bank a compliance certificate in the form attached hereto as Exhibit B, including a certificate of Borrower’s chief financial officer that no Event of Default or Default then exists or if an Event of Default or Default exists, the nature and duration thereof and Borrower’s intention with respect thereto.

Section 7.3.Requested Information. With reasonable promptness, all such other data and information in respect of the condition, operation and affairs of Borrower and its Subsidiaries as Bank may reasonably request from time to time.

ARTICLE 8
DEFAULT

Section 8.1.Events of Default. Each of the following events shall be an Event of Default hereunder:

8.1.1.If Borrower shall fail to pay (i) as and when due any amount of principal hereunder or on the Note, or (ii) any interest, fees, costs, expenses or any other sum payable to the Bank hereunder or otherwise, whether on demand, at the stated maturity or due date thereof, or by reason of any requirement for prepayment thereof, by acceleration or otherwise, within five (5) days of the date when due;

8.1.1.The failure of Borrower to observe the covenants set forth in Article 6 hereof.

8.1.2.The failure of Borrower to duly perform or observe any obligation, covenant or agreement on its or their part contained herein or in any other Credit Document not otherwise specifically constituting an Event of Default under this Section 8.1 and the continuance of such failure for a period of thirty (30) days after the notice from Bank to Borrower, provided that, in the event such failure is incapable of remedy or consists of a default of the financial covenant in Article 6, Borrower shall not be entitled to any notice or grace hereunder;

8.1.3.A breach, default or event of default shall occur at any time under the terms of the Existing Credit Agreement, and such breach, default or event of default either (i) consists of the failure to pay (beyond any period of grace permitted with respect thereto, whether waived or not) any indebtedness under or in connection with the Existing Credit Agreement when due (whether at stated maturity, by acceleration or otherwise) or (ii) causes, or permits the holder or holders of such indebtedness (or a trustee or agent on behalf of such holder or holders) to cause, with the giving of notice if required, such indebtedness to be demanded or to become due or to be repurchased, prepaid, defeased or redeemed (automatically or otherwise), or an offer to repurchase, prepay, defease or redeem such indebtedness to be made, prior to its stated maturity;

8.1.4.The adjudication of Borrower as a “debtor” or insolvent, or the entry of an order for relief against Borrower or the entry of an order appointing a receiver or trustee for Borrower of any of its property or approving a petition seeking reorganization or other similar relief under the bankruptcy or other similar laws of the United States or any state or any other competent jurisdiction;

8.1.5.A proceeding under any bankruptcy, reorganization, arrangement of debt, insolvency, readjustment of debt or receivership law is filed by or (unless dismissed within 90 days) against Borrower or Borrower makes an assignment for the benefit of creditors, or Borrower takes any action to authorize any of the foregoing;

8.1.6.The suspension of the operation of Borrower’s present business, or Borrower becoming unable to meet its debts as they mature, or the admission in writing by Borrower to such effect, or Borrower calling any meeting of all or any material portion of its creditors for the purpose of debt restructure;

8.1.7.All or any part of the assets of Borrower that are material to the operation of Borrower’s business are attached, seized, subjected to a writ or distress warrant, or levied upon, or come within the possession or control of any receiver, trustee, custodian or assignee for the benefit of creditors, or any other assets of Borrower are attached, seized, subject to a writ or distress warrant, or levied upon, or come within the possession or control of any receiver, trustee, custodian or assignee for the benefit of creditors and any such action is not, within thirty (30) days after such action is instituted, discharged or stayed pending appeal, or shall not have been discharged within twenty (20) days after the expiration of any such stay;

8.1.8.The entry of final judgment(s) for the payment of money aggregating in excess of $15,000,000 against Borrower which, within twenty (20) days after such entry, shall not have been discharged or execution thereof stayed pending appeal or shall not have been discharged, insured or bonded within five (5) days after the expiration of any such stay;

8.1.9.Any representation or warranty of Borrower in any of the Credit Documents is discovered to be untrue in any material respect or any statement, certificate or data furnished by Borrower pursuant hereto is discovered to be untrue in any material respect as of the date as of which the facts therein set forth are stated or certified;

8.1.10.A Material Adverse Effect occurs in Borrower’s operations or to the financial condition of Borrower;

8.1.11.Borrower voluntarily or involuntarily dissolves or is dissolved, terminates or is terminated;

8.1.12.Borrower is enjoined, restrained, or in any way prevented by the order of any court or any administrative or regulatory agency, the effect of which order restricts Borrower from conducting all or any material part of its business;

8.1.13.Any material uninsured damage to, or loss, theft, or destruction of, any of Borrower’s property that has a Material Adverse Effect;

8.1.14.The loss, suspension, revocation or failure to renew any license or permit now held or hereafter acquired by Borrower, which loss, suspension, revocation or failure to renew has a Material Adverse Effect;

8.1.15.The validity or enforceability of this Agreement or any of the Credit Documents is contested by Borrower.

Section 8.2.Remedies Generally. Upon the happening of any Event of Default and at any time during the continuance thereof and by notice by Bank to Borrower (except if an Event of Default described in Subsection 8.1.5 or 8.1.6 shall occur in which case acceleration shall occur automatically without notice), the Bank may declare the entire unpaid balance, principal, interest and fees of all Bank Indebtedness, hereunder or otherwise, to be immediately due and payable. In addition, the Bank may increase the interest rate on the Term Loan to the applicable Default Rate set forth herein, without notice; and the Bank shall have all the rights and remedies granted by any applicable law, all of which shall be cumulative in nature.

Section 8.3.Set-Off. At any time and from time to time following the occurrence and during the continuance of a Default or an Event of Default, Bank may without notice or demand, set off and apply any and all deposits (general or special, time or demand, provisional or final) at any time held and other indebtedness at any time owing by Bank to or for the credit of Borrower against any or all of the Bank Indebtedness and the Borrower’s obligations under the Credit Documents.

ARTICLE 9
MISCELLANEOUS

Section 9.1.Indemnification and Release Provisions; Costs and Expenses. Except to the extent of the gross negligence or willful misconduct on the part of the specific party indemnified hereunder as determined by a court of competent jurisdiction in a final and nonappealable judgment, Borrower hereby indemnifies and agrees to protect, defend and hold harmless Bank and its Affiliates, directors, officers, officials, agents, employees and counsel and their respective heirs, administrators, executors, successors and assigns (each, “Indemnified Person”), from and against, any and all losses, liabilities (including without limitation settlement costs and amounts, transfer taxes, documentary taxes, or assessments or charges made by any governmental authority), claims, damages, interest, judgments, costs, or expenses, including without limitation reasonable fees and disbursements of counsel, incurred by any Indemnified Person or asserted against any Indemnified Person by any Person (including Borrower or any Subsidiary of Borrower) arising out of or in connection with or by reason of this Agreement, the Term Loan or any other Credit Document, including without limitation, any and all losses, liabilities, claims, damages, interests, judgments, costs or expenses relating to or arising under any Environmental Control Statute or the application of any such Statute to Borrower’s or any Affiliate’s properties or assets. Borrower hereby releases Bank and its respective Affiliates, directors, officers, agents, employees and counsel from any and all claims for loss, damages, costs or expenses caused or alleged to be caused by any act or omission on the part of any of them, except to the extent caused by the gross negligence or willful misconduct of any party to be released hereunder as determined by a court of competent jurisdiction in a final and nonappealable judgment. All obligations provided for in this Section 9.1 shall survive any termination of this Agreement or the Term Loan and the repayment of the Term Loan.

Section 9.2.Certain Fees, Costs, Expenses and Expenditures. Borrower agrees to pay on demand all reasonable costs and expenses of Bank related to the Term Loan, including without limitation:

9.2.1.all reasonable costs and expenses to third parties in connection with the preparation, review, negotiation, execution and delivery of the Credit Documents, and the other documents to be delivered in connection therewith, or any amendments, extensions and increases to any of the foregoing (including, without limitation, reasonable attorney’s fees and expenses), and following an Event of Default, the cost of periodic lien searches and tax clearance certificates, as Bank deems advisable; and

9.2.2.all losses, reasonable costs and reasonable expenses in connection with the enforcement, protection and preservation of the Bank’s rights or remedies under the Credit Documents, or any other agreement relating to any Bank Indebtedness, or in connection with legal advice relating to the rights or responsibilities of Bank (including without limitation court costs, reasonable attorneys’ fees and reasonable expenses of accountants and appraisers).

In the event Borrower shall fail to pay taxes, insurance, assessments, costs or expenses which it is required to pay hereunder, or otherwise breaches any obligations under the Credit Documents, Bank in its discretion, may (but shall not be obligated to) make expenditures for such purposes and the amount so expended (including reasonable attorney’s fees and expenses, filing fees and other charges) shall be payable by Borrower on demand and shall constitute part of the Bank Indebtedness.

With respect to any amount required to be paid by Borrower under this Section 9.2, in the event Borrower fail to pay such amount within five (5) days of demand, Borrower shall also pay to Bank interest thereon at the Default Rate. Borrower’s obligations under this Section 9.2 shall survive termination of this Agreement.

Section 9.3.Participations and Assignments. Borrower hereby acknowledges and agrees that the Bank may at any time:

9.3.1.at Bank’s sole cost and expense, grant participations in all or any portion of the Term Loan or the Note or of its right, title and interest therein or in or to this Agreement to any other lending office or to any other bank, lending institution or other entity; and

9.3.1. assign all or any portion of its rights under the Term Loan; and

9.3.2.pledge or assign its interest in the Term Loan, the Note or any participation interest to any Federal Reserve Bank in accordance with applicable law.

Section 9.4.Binding and Governing Law. This Agreement, the other Credit Documents and all documents executed hereunder shall be binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns (provided that the Borrower may not assign or otherwise transfer any of its rights or obligations under this Agreement or the other Credit Documents without the prior written consent of Bank) and shall be governed as to their validity, interpretation and effect by the laws of the State of New York.

Section 9.5.Survival. All agreements, representations, warranties and covenants of Borrower contained herein or in any documentation required hereunder shall survive the execution of this Agreement and the making of the Term Loan hereunder and except for Section 9.1, which provides otherwise, will continue in full force and effect as long as any indebtedness or other obligation of Borrower to the Bank remains outstanding.

Section 9.6.No Waiver; Delay. If the Bank shall waive any power, right or remedy arising hereunder or under any applicable law, such waiver shall not be deemed to be a waiver of the later occurrence or recurrence of any of said events. No delay by the Bank in the exercise of any power, right or remedy shall, under any circumstances, constitute or be deemed to be a waiver, express or implied, of the same and no course of dealing between the parties hereto shall constitute a waiver of the Bank’s powers, rights or remedies. The remedies herein provided are cumulative and not exclusive of any remedies provided by law.

Section 9.7.Modification; Waiver. Except as otherwise provided in this Agreement, no modification or amendment hereof, or waiver or consent hereunder, shall be effective unless made in a writing signed by appropriate officers of the parties hereto. Whenever any consent, approval or waiver is requested hereunder, the determination to grant such request shall be in the Bank’s sole discretion (unless otherwise indicated).

Section 9.8.Headings. The various headings in this Agreement are inserted for convenience only and shall not affect the meaning or interpretation of this Agreement or any provision hereof.

Section 9.9.Notices. Any notice, request, consent or other communication made, given or required hereunder or in connection herewith shall be deemed satisfactorily given if in writing (including facsimile transmissions) and delivered by hand, mail (registered or certified mail) or overnight courier to the parties at their respective addresses or facsimile number set forth below or such other addresses or facsimile numbers as may be given by any party to the others in writing:

To Borrower:

Chesapeake Utilities Corporation

909 Silver Lake Boulevard

Dover, Delaware 19904

Attention: Beth W. Cooper, Chief Financial Officer

Facsimile No.: 302-734-6750

Telephone No.: 302-734-6022

With a copy to:

Baker & Hostetler LLP

Key Tower

127 Public Square, Suite 2000

Cleveland, Ohio 44114-1214

Attention: Phillip M. Callesen and Matthew G. Oliver

Facsimile No.: 216-696-0740

To Bank:

Branch Banking and Trust Company

8200 Greensboro Dr. Suite 1000

McLean, VA 22102

Attention: Matt Davis, Senior Vice President

Facsimile No.: 888-707-3035

Telephone No.: 703-269-1653

Section 9.10.Payment on Non-Business Days. Whenever any payment to be made hereunder shall be stated to be due on a day other than a Business Day, such payment may be made on the next succeeding Business Day, provided however that such extension of time shall be included in the computation of interest due in conjunction with such payment or other fees due hereunder, as the case may be.

Section 9.11.Time of Day. Except as expressly provided otherwise herein, all time of day restrictions imposed herein shall be calculated using the local time in Wilmington, Delaware.

Section 9.12.Severability. If any provision of this Agreement or the application thereof to any person or circumstance shall be invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provisions to other persons or circumstances shall not be affected thereby and shall be enforced to the greatest extent permitted by law.

Section 9.13.Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all the signatures on such counterparts appeared on one document, and each such counterpart shall be deemed to be an original.

Section 9.14.Consent to Jurisdiction and Service of Process. Borrower hereby consents to the exclusive jurisdiction of any courts of the State of New York sitting in New York County and of the United States District Court of the Southern District of New York, and of any appellate court from any thereof, and irrevocably agrees that, subject to the Bank’s election, all actions or proceedings relating to the Credit Documents or the transactions contemplated hereunder shall be litigated in such courts, and Borrower waives any objection which it may have based on lack of personal jurisdiction, improper venue or forum non conveniens to the conduct of any proceeding in any such court. Nothing contained in this Section 9.14 shall affect the right of Bank to serve legal process in any other manner permitted by law or affect the right of Bank to bring any action or proceeding against Borrower or its property in the courts of any other jurisdiction.

Section 9.15.WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO HEREBY KNOWINGLY, VOLUNTARILY, AND INTENTIONALLY WAIVES ANY RIGHTS IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION BASED HEREON OR ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AGREEMENT OR THE NOTE OR ANY COURSE OF CONDUCT, COURSE OF DEALING, STATEMENTS (WHETHER ORAL OR WRITTEN) OR ACTIONS OF BANK. THIS PROVISION IS A MATERIAL INDUCEMENT FOR THE BANK ENTERING INTO THIS AGREEMENT.

Section 9.16.ADDITIONAL WAIVERS; LIMITATIONS.

9.16.1.IN CONNECTION WITH ANY PROCEEDINGS UNDER THE CREDIT DOCUMENTS, INCLUDING WITHOUT LIMITATION ANY ACTION BY BANK IN REPLEVIN, FORECLOSURE OR OTHER COURT PROCESS OR IN CONNECTION WITH ANY OTHER ACTION RELATED TO THE CREDIT DOCUMENTS OR THE TRANSACTIONS CONTEMPLATED HEREUNDER, BORROWER WAIVES:

(a)ALL PROCEDURAL ERRORS, DEFECTS AND IMPERFECTIONS IN SUCH PROCEEDINGS;

(b)ALL BENEFITS UNDER ANY PRESENT OR FUTURE LAWS EXEMPTING ANY PROPERTY, REAL OR PERSONAL, OR ANY PART OF ANY PROCEEDS THEREOF FROM ATTACHMENT, LEVY OR SALE UNDER EXECUTION, OR PROVIDING FOR ANY STAY OF EXECUTION TO BE ISSUED ON ANY JUDGMENT RECOVERED UNDER ANY OF THE CREDIT DOCUMENTS OR IN ANY REPLEVIN OR FORECLOSURE PROCEEDING, OR OTHERWISE PROVIDING FOR ANY VALUATION, APPRAISAL OR EXEMPTION;

(c)PRESENTMENT FOR PAYMENT, DEMAND, NOTICE OF DEMAND, NOTICE OF NON-PAYMENT, PROTEST AND NOTICE OF PROTEST OF ANY OF THE CREDIT DOCUMENTS, INCLUDING THE NOTE; AND

(d)ALL RIGHTS TO CLAIM OR RECOVER REASONABLE ATTORNEY’S FEES AND COSTS IN THE EVENT THAT BORROWER IS SUCCESSFUL IN ANY ACTION TO REMOVE OR SUSPEND A JUDGMENT ENTERED BY CONFESSION.

9.16.2.FORBEARANCE. BANK MAY RELEASE, COMPROMISE, FORBEAR WITH RESPECT TO, WAIVE, SUSPEND, EXTEND OR RENEW ANY OF THE TERMS OF THE CREDIT DOCUMENTS, WITHOUT NOTICE TO BORROWER.

9.16.3.LIMITATION ON LIABILITY. BORROWER SHALL BE RESPONSIBLE FOR AND BANK IS HEREBY RELEASED FROM ANY CLAIM OR LIABILITY IN CONNECTION WITH:

(a)SAFEKEEPING ANY PROPERTY (EXCEPT FOR PROPERTY IN BANK’S POSSESSION);

(b)ANY LOSS OR DAMAGE TO ANY PROPERTY (EXCEPT FOR PROPERTY IN BANK’S POSSESSION);

(c)ANY DIMINUTION IN VALUE OF THE PROPERTY; OR

(d)ANY ACT OR DEFAULT OF ANOTHER PERSON.

BANK SHALL ONLY BE LIABLE FOR ANY ACT OR OMISSION ON ITS PART CONSTITUTING GROSS NEGLIGENCE OR WILLFUL MISCONDUCT AS DETERMINED BY A COURT OF COMPETENT JURISDICTION IN A FINAL AND NONAPPEALABLE JUDGMENT. IN THE EVENT BORROWER BRINGS SUIT AGAINST BANK IN CONNECTION WITH THE TRANSACTIONS CONTEMPLATED HEREUNDER AND BANK IS FOUND NOT TO BE LIABLE, BORROWER WILL INDEMNIFY AND HOLD BANK HARMLESS FROM ALL COSTS AND EXPENSES, INCLUDING REASONABLE ATTORNEY FEES AND COSTS, INCURRED BY BANK IN CONNECTION WITH SUCH SUIT. THIS AGREEMENT IS NOT INTENDED TO OBLIGATE BANK TO INCUR EXPENSES OR PERFORM ANY OBLIGATION OR DUTY OF BORROWER.

Section 9.17.ACKNOWLEDGMENTS. BORROWER ACKNOWLEDGES THAT IT HAS HAD THE ASSISTANCE OF COUNSEL IN THE REVIEW AND EXECUTION OF THIS AGREEMENT AND, SPECIFICALLY, SECTION 9.16 HEREOF, AND FURTHER ACKNOWLEDGES THAT THE MEANING AND EFFECT OF THE FOREGOING WAIVER OF JURY TRIAL AND ADDITIONAL WAIVERS HAVE BEEN FULLY EXPLAINED TO BORROWER BY SUCH COUNSEL.

Section 9.18.U.S. Patriot Act/OFAC Notice. To help the government fight the funding of terrorism and money laundering activities, Federal law requires all financial institutions to obtain, verify, and record information that identifies each Person who establishes a formal relationship with such institution. Therefore, when Borrower enters into this business relationship with Bank, Bank will ask Borrower or its officers or owners their name, address, date of birth (for individuals) and other pertinent information that will allow Bank to identify Borrower. Bank may also ask to see Borrower’s organizational documents or other identifying information.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, the undersigned, by their duly authorized officers, have executed and delivered this Term Loan Credit Agreement under seal the day and year first above written.

BORROWER:

ATTEST:                CHESAPEAKE UTILITIES CORPORATION

a Delaware corporation

Thomas E. Mahn            By: Beth W. Cooper

Name: Thomas E. Mahn        Name: Beth W. Cooper

Title: Treasurer and Vice President Title: Senior Vice President and Chief Financial

Officer

[Signature page 1 of 2 to Term Loan Credit Agreement]

BANK:

ATTEST:                BRANCH BANKING AND TRUST COMPANY

By:

Name:                    Name:

Title:                    Title:

[Signature page 2 of 2 to Term Loan Credit Agreement]

EXHIBIT A

STANDARD LIBOR LANGUAGE

1. Definitions.

a. “Applicable Margin” means seventy five (75) basis points (0.75%).

b. “Business Day” means:

(1)    any day which is neither a Saturday or Sunday nor a legal holiday on which commercial banks are authorized or required to be closed in Winston-Salem, North Carolina;

(2)    when such term is used to describe a day on which a borrowing, payment, prepaying, or repaying is to be made in respect of any LIBOR Rate Loan, any day which is: (i) neither a Saturday or Sunday nor a legal holiday on which commercial banks are authorized or required to be closed in New York City; and (ii) a London Banking Day; and

(3)    when such term is used to describe a day on which an interest rate determination is to be made in respect of any LIBOR Rate Loan, any day which is a London Banking Day.

c.“Hedging Contracts” means interest rate swap agreements, interest rate cap agreements and interest rate collar agreements, or any other agreements or arrangements entered into between the Borrower and the Bank and designed to protect the Borrower against fluctuations in interest rates or currency exchange rates.

d.“Hedging Obligations” means, with respect to the Borrower, all liabilities of the Borrower to the Bank under Hedging Contracts.

e.“Interest Payment Date” means the last Business Day of each LIBOR Interest Period.

f.“LIBOR Interest Period” is a period of one month, which period shall commence on the first day of each month (provided that the initial LIBOR Interest Period shall commence on the Closing Date) and ending on the date that is immediately prior to the numerically corresponding day of each month thereafter, subject to the terms of this Agreement and shall be determined by Lender in accordance with this Agreement and Lender’s loan systems and procedures periodically in effect, including, without limitation, in accordance with the following terms and conditions, as applicable:

(1)Any LIBOR Interest Period which would otherwise end on a day which is not a Business Day shall end on the next following Business Day unless such day falls in the next calendar month, in which case such LIBOR Interest Period shall end on the first preceding Business Day; and

(2)Any LIBOR Interest Period which begins on a day for which there is no numerically corresponding day in a subsequent month shall end on the last Business Day of each subsequent month.

g.“LIBOR Rate” means a rate of interest per annum equal to the sum obtained (rounded upwards, if necessary, to the next higher 1/100^th of 1.0%) by adding (i) the One Month LIBOR plus (ii) the Applicable Margin per annum, which shall be adjusted monthly on the first day of each LIBOR Interest Period. The LIBOR Rate shall be adjusted for any change in the LIBOR Reserve Percentage so that Lender shall receive the same yield. The interest rate will in no instance exceed the maximum rate permitted by applicable law. Notwithstanding the foregoing, in no event shall the LIBOR Rate be less than the Applicable Margin.

h.“LIBOR Rate Loan” means the Term Loan for the period(s) when the rate of interest applicable thereto is based upon the LIBOR Rate.

i.“LIBOR Reserve Percentage” means, relative to any day of any LIBOR Interest Period, the maximum aggregate (without duplication) of the rates (expressed as a decimal fraction) of reserve requirements (including all basic, emergency, supplemental, marginal and other reserves and taking into account any transitional adjustments or other scheduled changes in reserve requirements) under any regulations of the Board of Governors of the Federal Reserve System (the “Board”) or other governmental authority having jurisdiction with respect thereto as issued from time to time and then applicable to assets or liabilities consisting of “Eurocurrency Liabilities”, as currently defined in Regulation D of the Board, having a term approximately equal or comparable to such LIBOR Interest Period.

j.“London Banking Day” means a day on which dealings in US dollar deposits are transacted in the London interbank market.

k.“One Month LIBOR” means the average quoted by Bloomberg Finance L.P., or any quoting service or commonly available source utilized by the Lender, on the determination date for deposits in U. S. Dollars offered in the London interbank market for one month determined at approximately 11:00 am London time two (2) Business Days prior to the commencement of the applicable LIBOR Interest Period; provided that if the above method for determining one month LIBOR shall not be available, the rate quoted in The Wall Street Journal, or a rate determined by a substitute method of determination agreed on by Borrower and Bank; and provided further that if One Month LIBOR determined as provided above would be less than zero percent (0%) then One Month LIBOR shall be deemed to be zero percent (0%).

l.“Prime Rate” means the annual interest rate publicly announced by Bank from time to time as its prime rate. The Prime Rate is determined from time to time by Bank as a means of pricing some loans to its borrowers. The Prime Rate is not tied to any external rate of interest or index, and does not necessarily reflect the lowest rate of interest actually charged by Bank to any particular class or category of customers. If and when the Prime Rate changes, the rate of interest with respect to any amounts hereunder to which the Prime Rate applies will change automatically without notice to Borrower, effective on the date of any such change.

m.“Prime Rate Loan” means the Term Loan for the period(s) when the rate of interest applicable to such Loan is calculated by reference to the Prime Rate.

n.“Prime Rate Margin” means zero (0) basis points (0.00%) per annum.

2. Reserved.

3. Repayment, Prepayments and Interest.

a.Reserved.

b.Interest Provisions. Interest on the outstanding principal amount of the Term Loan, when classified as a: (i) LIBOR Rate Loan, shall accrue during each LIBOR Interest Period at a rate per annum equal to the sum of the LIBOR Rate for such LIBOR Interest Period, and be due and payable on each Interest Payment Date and on the Maturity Date, and (ii) Prime Rate Loan, shall accrue at a rate per annum equal to the sum of the Prime Rate plus the Prime Rate Margin, and be due and payable on each Interest Payment Date and on the Maturity Date. The Bank shall determine each interest rate applicable to the Term Loan in accordance with the terms of this Agreement, and its determination thereof shall be conclusive in the absence of manifest error.

c.Voluntary Prepayment of LIBOR Rate Loans. A LIBOR Rate Loan may be prepaid upon the terms and conditions set forth herein. For a LIBOR Rate Loan in connection with which the Borrower has or may incur Hedging Obligations, additional obligations may be associated with prepayment, in accordance with the terms and conditions of the applicable Hedging Contracts. The Borrower shall give the Bank, no later than 10:00 a.m., New York City time, at least four (4) Business Days notice of any proposed prepayment of a LIBOR Rate Loan, specifying the proposed date of payment of such LIBOR Rate Loan, and the principal amount to be paid. Each partial prepayment of the principal amount of a LIBOR Rate Loan shall be in an integral multiple of $10,000 and accompanied by the payment of all charges outstanding on such LIBOR Rate Loan (including the LIBOR Breakage Fee) and of all accrued interest on the principal repaid to the date of payment.

d.LIBOR Breakage Fees. Upon any prepayment of a LIBOR Rate Loan on any day that is not the last day of the relevant LIBOR Interest Period (regardless of the source of such prepayment and whether voluntary, by acceleration or otherwise), the Borrower shall pay an amount (“LIBOR Breakage Fee”), as calculated by the Bank, equal to the amount of any losses, expenses and liabilities (including without limitation any loss of margin and anticipated profits) that Bank may sustain as a result of such payment. The Borrower understands, agrees and acknowledges that: (i) the Bank does not have any obligation to purchase, sell and/or match funds in connection with the use of One Month LIBOR as a basis for calculating the rate of interest on a LIBOR Rate Loan, (ii) One Month LIBOR may be used merely as a reference in determining such rate, and (iii) the Borrower has accepted One Month LIBOR as a reasonable and fair basis for calculating the LIBOR Breakage Fee and other funding losses incurred by the Bank. Borrower further agrees to pay the LIBOR Breakage Fee and other funding losses, if any, whether or not the Bank elects to purchase, sell and/or match funds.

4. Miscellaneous LIBOR Rate Loan Terms.

a.LIBOR Rate Lending Unlawful. If the Bank shall determine (which determination shall, upon notice thereof to the Borrower, be conclusive and binding on the Borrower) that the introduction of or any change in or in the interpretation of any law, rule, regulation or guideline, (whether or not having the force of law) makes it unlawful, or any central bank or other governmental authority asserts that it is unlawful, for the Bank to make, continue or maintain the Term Loan as a LIBOR Rate Loan, the obligations of the Bank to make, continue or maintain the Term Loan as a LIBOR Rate Loan shall, upon such determination, forthwith be suspended until the Bank shall notify the Borrower that the circumstances causing such suspension no longer exist, and all the Term Loan shall automatically convert into a Prime Rate Loan at the end of the then current LIBOR Interest Period or sooner, if required by such law or assertion.

b.Unavailability of LIBOR Rate. In the event that the Bank, in its sole discretion, shall have determined that U.S. dollar deposits in the relevant amount and for any LIBOR Interest Period are not available to the Bank in the London interbank market; or by reason of circumstances affecting the Bank in the London interbank market, adequate and reasonable means do not exist for ascertaining One Month LIBOR applicable to the relevant LIBOR Interest Period; or One Month LIBOR no longer adequately and fairly reflects the Bank’s cost of funding loans; upon notice from the Bank to the Borrower, the obligations of the Bank hereunder and under this Agreement to make or continue the Term Loan as a LIBOR Rate Loan shall forthwith be suspended until the Bank shall notify the Borrower that the circumstances causing such suspension no longer exist, and the Term Loan shall automatically convert into a Prime Rate Loan at the end of the then current LIBOR Interest Period or sooner, if required by such law or assertion.

c.Increased Costs. If, on or after the date hereof, the adoption of any applicable law, rule or regulation or guideline (whether or not having the force of law), or any change therein, or any change in the interpretation or administration thereof by any governmental authority, central bank or comparable agency charged with the interpretation or administration thereof, or compliance by the Bank with any request or directive (whether or not having the force of law) of any such authority, central bank or comparable agency: (a) shall impose, modify or deem applicable any reserve, special deposit or similar requirement (including, without limitation, any such requirement imposed by the Board of Governors of the Federal Reserve System of the United States) against assets of, deposits with or for the account of, or credit extended by, the Bank or shall impose on the Bank or on the London interbank market any other condition affecting loans based on One Month LIBOR or its obligation to make loans based on One Month LIBOR; or (b) shall impose on the Bank any other condition affecting its loans based on One Month LIBOR or its obligation to make or maintain loans based on One Month LIBOR (a “Change in Law”), and the result of any of the foregoing is to increase the cost to the Bank of making or maintaining the Term Loan as a LIBOR Rate Loan hereunder, or to reduce the amount of any sum received or receivable by the Bank under this Agreement with respect thereto, by an amount deemed by the Bank to be material, then, the Borrower shall pay to the Bank, in accordance with terms herein, such additional amount or amounts as will compensate the Bank for such increased cost or reduction.

d.Increased Capital Costs. If any change in, or the introduction, adoption, effectiveness, interpretation, reinterpretation or phase-in of, any law or regulation, directive, guideline, decision or request (whether or not having the force of law) of any court, central bank, regulator or other governmental authority affects or would affect the amount of capital required to be maintained by the Bank, or person controlling the Bank (a “Change in Capital Law”), and the Bank determines that the rate of return on its or such controlling person’s capital as a consequence of its commitments hereunder or the loans made by the Bank under this Agreement is reduced to a level below that which the Bank or such controlling person could have achieved but for the occurrence of such Change in Capital Law, then, in any such case upon notice from time to time by the Bank to the Borrower, the Borrower shall promptly pay directly to the Bank additional amounts sufficient to compensate the Bank or such controlling person for such reduction in rate of return.

e.Procedures for Payment of Increased Costs.

(1)    A certificate of the Bank as to any additional amount or amounts (including calculations thereof in reasonable detail) to compensate the Bank, as specified in Section 4(c)or 4(d), shall be delivered to the Borrower and shall, in the absence of manifest error, be conclusive and binding on the Borrower. In determining such amount, the Bank may use any method of averaging and attribution that it (in good faith, but in its sole and absolute discretion) shall deem applicable. The Borrower shall pay the Bank the amount shown as due on any such certificate within fifteen (15) days after receipt thereof.

(2)    Failure or delay on the part of the Bank to demand compensation pursuant to the foregoing provisions of Section 4(c)or 4(d) shall not constitute a waiver of the Bank’s right to demand such compensation, provided that the Borrower shall not be required to compensate the Bank pursuant to the foregoing provisions of this Section for any increased costs incurred or reductions suffered more than three (3) months prior to the date that the Bank notifies the Borrower of the Change in Law or the Change in Capital Law giving rise to such increased costs or reductions and of the Bank’s intention to claim compensation therefor (except that, if the Change in Law or the Change in Capital Law giving rise to such increased costs or reductions is retroactive, then the three (3) month period referred to above shall be extended to include the period of retroactive effect thereof).

f.    Taxes. All payments by the Borrower of principal of, and interest on, the Term Loan and all other amounts payable under the Credit Documents shall be made free and clear of and without deduction for any present or future income, excise, stamp or franchise taxes and other taxes, fees, duties, withholdings or other charges of any nature whatsoever imposed by any taxing authority, but excluding franchise taxes and taxes imposed on or measured by the Bank’s net income or receipts (such non-excluded items being called “Taxes”). In the event that any withholding or deduction from any payment to be made by the Borrower hereunder is required in respect of any Taxes pursuant to any applicable law, rule or regulation, then the Borrower will:

(1)    pay directly to the relevant authority the full amount required to be so withheld or deducted;

(2)    promptly forward to the Bank an official receipt or other documentation satisfactory to the Bank evidencing such payment to such authority; and

(3)    pay to the Bank such additional amount or amounts as is necessary to ensure that after such deduction or withholding has been made (including such deductions and withholdings applicable to additional sums payable under this Section 4(f)) the net amount actually received by the Bank will equal the full amount the Bank would have received had no such withholding or deduction been required.

Moreover, if any Taxes are directly asserted against the Bank with respect to any payment received by the Bank hereunder, the Bank may pay such Taxes and the Borrower will promptly pay such additional amount (including any penalties, interest or expenses) as is necessary in order that the net amount received by the Bank after the payment of such Taxes (including any Taxes on such additional amount) shall equal the amount the Bank would have received had not such Taxes been asserted.

If the Borrower fails to pay any Taxes when due to the appropriate taxing authority or fails to remit to the Bank the required receipts or other required documentary evidence, the Borrower shall indemnify the Bank for any incremental Taxes, interest or penalties that may become payable by the Bank as a result of any such failure.

EXHIBIT B

Compliance Certificate

(INSERT DATE)

Branch Banking and Trust Company

8200 Greensboro Dr. Suite 1000

McLean, VA 22102

Attention: Matt Davis, Senior Vice President

Facsimile No.: 888-707-3035

Telephone No.: 703-269-1653

I, , _____(Title)_____, do hereby certify on behalf of Chesapeake Utilities Corporation (“Borrower”) as of the quarter ended (the “Report Date”), as follows:

1.) Funded Debt to Total Capitalization. The Funded Debt to Total Capitalization (as defined in the Term Loan Credit Agreement) is ________________, which is in compliance with the required maximum Funded Debt to Total Capitalization of 65% for the test period end date of _____________________.

2.) The representations and warranties of the Borrower contained in the Term Loan Credit Agreement and in the other Credit Documents (as defined in the Term Loan Credit Agreement) are true on and as of this date with the same effect as though such representations and warranties have been made on and as of the date hereof and the Borrower has performed and complied in all respects with all covenants and conditions thereof.

3.) [No event has occurred and is continuing or exists as of the date hereof, which constitutes a Default or an Event of Default (as each term is defined in the Term Loan Credit Agreement)]

IN WITNESS WHEREOF, the undersigned has executed this Certificate on this _____ day of _____________________, 20_____.

By:

Name:

Title:

WBD (US) 44974205v3

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
Grove Energy, Inc.	Delaware
Austin Cox Home Services, Inc.	Delaware
Aspire Energy of Ohio, LLC	Delaware
Aspire Energy, LLC	Florida
Aspire Energy Express, LLC	Delaware
Marlin Gas Services, 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
Subsidiary of Chesapeake OnSight Services, LLC	State Incorporated
Eight Flags 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, 2019, 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, 2018.

/s/ Baker Tilly Virchow Krause, LLP

Philadelphia, Pennsylvania

February 26, 2019

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, 2018 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, 2019

/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, 2018 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, 2019

/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, 2018, 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, 2019

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, 2018, 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, 2019

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.

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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2018	Feb. 15, 2019	Jun. 30, 2018
Document Document And Entity Information [Abstract]
Entity Central Index Key	0000019745
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-K
Document Period End Date	Dec. 31, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	FY
Trading Symbol	CPK
Amendment Flag	false
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Common Stock, Shares Outstanding	CHESAPEAKE UTILITIES CORP
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1.2
Entity Common Stock, Shares Outstanding		16,378,821
Entity Shell Company	false

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Consolidated Statements of Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues
Regulated Energy	$ 345,281	$ 326,310	$ 305,689
Unregulated Energy	420,617	324,595	203,778
Other	(48,409)	(33,322)	(10,607)
Total operating revenues	717,489	617,583	498,860
Operating Expenses
Regulated Energy cost of sales	121,828	118,769	109,609
Unregulated Energy and other cost of sales	288,913	219,145	128,434
Operations	138,441	125,994	115,684
Cost, Maintenance	14,387	12,701	12,391
Gain from a settlement	(130)	(130)	(130)
Depreciation and amortization	40,802	36,599	32,159
Other taxes	18,628	17,085	14,730
Total operating expenses	622,869	530,163	412,877
Operating Income	94,620	87,420	85,983
Other expense, net	(615)	(2,342)	(2,328)
Interest charges	16,431	12,645	10,639
Income Before Income Taxes	77,574	72,433	73,016
Income taxes	20,994	14,309	28,341
Net Income	$ 56,580	$ 58,124	$ 44,675
Weighted Average Common Shares Outstanding:
Basic (in shares)	16,369,616	16,336,789	15,570,539
Diluted (in shares)	16,419,870	16,383,352	15,613,091
Earnings Per Share of Common Stock:
Basic (in usd per share)	$ 3.46	$ 3.56	$ 2.87
Diluted (in usd per share)	3.45	3.55	2.86
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 1.4350	$ 1.2800	$ 1.2025

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Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Net Income	$ 56,580	$ 58,124	$ 44,675
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(22), $(31) and $(29), respectively	(55)	(46)	(48)
Net (loss)/gain, net of tax of $(49), $432, and $178, respectively	(108)	663	268
Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(555), $(8) and $496, respectively	(1,371)	(11)	742
Total Other Comprehensive Income (Loss)	(1,534)	606	962
Comprehensive Income	$ 55,046	$ 58,730	$ 45,637

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Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ (22,000)	$ (31,000)	$ (29,000)
Tax expense recognized on the net gain (loss)	(49,000)	432,000	178,000
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ (555,000)	$ (8,000)	$ 496,000

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
Operating Activities
Net Income		$ 56,580	$ 58,124		$ 44,675
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization		40,802	36,599		32,159
Depreciation and accretion included in operations expenses		8,535	8,122		7,334
Deferred income taxes, net	[1]	21,226	11,085		31,257
Realized loss on sale of assets/investments/commodity contracts		5,497	3,179		695
Unrealized loss (gain) on investments/commodity contracts		429	(1,001)		(385)
Employee benefits and compensation		856	1,577		1,887
Share-based compensation		2,813	2,490		2,367
Other, net		0	(750)		(79)
Changes in assets and liabilities:
Accounts receivable and accrued revenue		(16,311)	(19,506)		(27,013)
Propane inventory, storage gas and other inventory		2,107	(9,036)		(2,531)
Regulatory assets/liabilities, net		2,250	(2,855)		(7,523)
Prepaid expenses and other current assets		(7,421)	(7,001)		(1,387)
Accounts payable and other accrued liabilities		35,907	15,596		19,599
Income taxes receivable (payable)		(522)	8,110		2,466
Customer deposits and refunds		(596)	5,513		2,065
Accrued compensation		708	2,488		358
Other assets and liabilities, net		(6,082)	(2,645)		(1,803)
Net cash provided by operating activities		146,778	110,089		104,141
Investing Activities
Property, plant and equipment expenditures		(269,767)	(175,329)		(169,861)
Proceeds from sale of assets		782	708		174
Acquisitions, net of cash acquired		(16,654)	(11,945)		0
Environmental expenditures		(625)	(329)		(350)
Net cash used in investing activities		(286,264)	(186,895)		(170,037)
Financing Activities
Common stock dividends		(22,043)	(19,928)		(17,482)
Issuance of stock for Dividend Reinvestment Plan		(706)	89		811
Proceeds from issuance of common stock, net of expenses		0	(10)	[2]	57,360	[2]
Payments Related to Tax Withholding for Share-based Compensation		(1,210)	(692)		(770)
Change in cash overdrafts due to outstanding checks		(5,943)	1,738		3,920
Net borrowing under line of credit agreements		49,432	39,338		32,526
Proceeds from issuance of long-term debt		154,819	69,807		0
Repayment of long-term debt and capital lease obligation		(34,388)	(12,100)		(9,146)
Net cash provided by financing activities		139,961	78,242		67,219
Net Increase in Cash and Cash Equivalents		475	1,436		1,323
Cash and Cash Equivalents — Beginning of Period		5,614	4,178		2,855
Cash and Cash Equivalents — End of Period		$ 6,089	$ 5,614		$ 4,178

[1] (1) Includes $3.5 million, $873,000 and $2.1 million of deferred state income taxes for the years 2018, 2017 and 2016, respectively.

[2] On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

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Consolidated Balance Sheets - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment
Regulated Energy		$ 1,297,416	$ 1,073,736
Unregulated Energy		237,682	210,682
Other businesses and eliminations		34,585	27,699
Total property, plant and equipment		1,569,683	1,312,117
Less: Accumulated depreciation and amortization		(294,295)	(270,599)
Plus: Construction work in progress		108,584	84,509
Net property, plant and equipment		1,383,972	1,126,027
Current Assets
Cash and cash equivalents		6,089	5,614
Accounts receivable (less allowance for uncollectible accounts of $1,108 and $936, respectively)		85,404	77,223
Accrued revenue		27,499	22,279
Propane inventory, at average cost		9,791	8,324
Other inventory, at average cost		7,127	12,022
Regulatory assets		4,796	10,930
Storage gas prepayments		6,603	5,250
Income taxes receivable		15,300	14,778
Prepaid expenses		10,079	13,621
Derivative assets, at fair value		13,165	1,286
Other current assets		5,684	7,260
Total current assets		191,537	178,587
Deferred Charges and Other Assets
Goodwill		25,837	19,604
Other intangible assets, net		6,207	4,686
Investments, at fair value		6,711	6,756
Regulatory assets		72,422	75,575
Receivables and other deferred charges		6,985	3,699
Total deferred charges and other assets		118,162	110,320
Total Assets		1,693,671	1,414,934
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)		7,971	7,955
Additional paid-in capital		255,651	253,470
Retained earnings		261,530	229,141
Accumulated other comprehensive loss		(6,713)	(4,272)
Deferred compensation obligation		3,854	3,395
Treasury stock		(3,854)	(3,395)
Total stockholders’ equity	[1]	518,439	486,294
Long-term debt, net of current maturities		316,020	197,395
Total capitalization		834,459	683,689
Current Liabilities
Current portion of long-term debt		11,935	9,421
Short-term borrowing		294,458	250,969
Accounts payable		129,804	74,688
Customer deposits and refunds		34,155	34,751
Accrued interest		2,317	1,742
Dividends payable		6,060	5,312
Accrued compensation		13,923	13,112
Regulatory liabilities		7,883	6,485
Derivative liabilities, at fair value		14,871	6,247
Other accrued liabilities		12,828	10,273
Total current liabilities		528,234	413,000
Deferred Credits and Other Liabilities
Deferred income taxes		156,820	135,850
Regulatory liabilities		135,039	140,978
Environmental liabilities		7,638	8,263
Other pension and benefit costs		28,513	29,699
Deferred investment tax credits and other liabilities		2,968	3,455
Total deferred credits and other liabilities		330,978	318,245
Commitments and Contingencies
Total Capitalization and Liabilities		$ 1,693,671	$ 1,414,934

[1] Includes 97,053, 90,961 and 76,745 shares at December 31, 2018, 2017 and 2016, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,108	$ 936
Common stock, par value	$ 0.4867	$ 0.4867
Common stock, shares authorized	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01

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Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands		Total		Common Stock [Member]		Additional Paid-In Capital [Member]		Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]		Treasury Stock [Member]
Beginning Balances at Dec. 31, 2015		$ 358,138	[1]	$ 7,432		$ 190,311		$ 166,235	$ (5,840)	$ 1,883		$ (1,883)
Beginning Balances, shares at Dec. 31, 2015	[1],[2]			15,270,659
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		44,675						44,675
Other comprehensive loss		962							962
Dividends		(18,848)						(18,848)
Proceeds from issuance of common stock, net of expenses	[3]	$ 57,360		$ 467		56,893
Stock Issued During Period, Shares, New Issues		960,488		960,488	[3]
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		$ 2,242		$ 17		2,225
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan				36,253
Share-based compensation	[4],[5]	1,557		$ 19		1,538
Share-based compensation, shares	[4],[5]			36,099
Treasury stock activities	[1]									533		(533)
Ending Balances at Dec. 31, 2016		446,086	[1]	$ 7,935		250,967		192,062	(4,878)	2,416		(2,416)
Ending 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	[3]	(10)		$ 0		(10)
Stock Issued During Period, Shares, New Issues	[3]			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	[4],[5]	1,798		$ 15		1,783
Share-based compensation, shares	[4],[5]			30,172
Treasury stock activities		0								979	[1]	(979)	[1]
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	(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	[1]	$ 7,971		$ 255,651		$ 261,530	$ (6,713)	$ 3,854		$ (3,854)
Ending Balances, shares at Dec. 31, 2018	[1],[2]			16,378,545

[1] Includes 97,053, 90,961 and 76,745 shares at December 31, 2018, 2017 and 2016, 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 Statements of Stockholders’ Equity.

[3] On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

[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 2018, 2017 and 2016, we withheld 10,436, 10,269 and 12,031 shares, respectively, for taxes.

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Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	97,053	90,961	76,745
Dividends Declared	$ 1.4350	$ 1.2800	$ 1.2025
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	10,436	10,269	12,031

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Organization and Basis of Presentation

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Organization and Basis of Presentation

ORGANIZATIONAND BASISOF 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 natural gas marketing operation providing natural gas supply directly to commercial and industrial customers in Florida, Delaware, Maryland, Pennsylvania, Ohio and other states; (c) our unregulated natural gas transmission/supply operation in central and eastern Ohio; (d) our CHP plant in Florida that generates electricity and steam; and (e) our newest subsidiary, based in Florida, that provides mobile compressed natural gas ("CNG") utility and pipeline solutions to commercial, industrial and other utility customers throughout the Southeast and Midwest portions of the country.

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.

We reclassified certain amounts in the consolidated statement of income for the years ended December 31, 2017 and 2016 to conform to the current year’s presentation.

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Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Summary of Significant Accounting Policies

SUMMARYOF 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 by classification as of December 31, 2018 and 2017 is provided in the following table:

	As of December 31,
(in thousands)	2018			2017
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	657,630		$	589,149
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	537,654			384,360
Electric distribution – Florida	102,133			100,227
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	123,632			108,177
Natural gas transmission – Ohio	70,225			66,037
Electricity and Steam generation – Florida	35,239			35,239
Mobile CNG utility and pipeline solutions	7,240			—
Other unregulated energy	1,346			1,229
Other	34,584			27,699
Total property, plant and equipment	1,569,683			1,312,117
Less: Accumulated depreciation and amortization	(294,295		)	(270,599		)
Plus: Construction work in progress	108,584			84,509
Net property, plant and equipment	$	1,383,972		$	1,126,027

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, 2018, 2017 and 2016, the non-refundable contributions totaled $2.8 million, $2.1 million and $1.0 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 year ended December 31, 2018, AFUDC totaled $1.9 million, which was reflected as a reduction of interest charges. During the years ended December 31, 2017 and 2016, AFUDC was not material.

Assets Used in Leases

Property, plant and equipment for the Florida natural gas transmission operation included $1.4 million of assets, at December 31, 2018 and 2017, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a 20-year term. Accumulated depreciation for these assets totaled $720,000 and $652,000 at December 31, 2018 and 2017, respectively.

Capital Lease Assets

Property, plant and equipment include capital lease assets related to: (i) a lease arrangement entered into by our Delmarva Peninsula natural gas distribution operation associated with Sandpiper's capacity, supply and operating agreement and (ii) our Mid-Atlantic propane operation's lease arrangement for property in Anne Arundel County Maryland which it intends to purchase during the first quarter of 2019. Information regarding the impact of the capital leases in our financial statements is shown below. Additional information can be found in Note 21, Other Commitments and Contingencies.

	As of December 31,
(in thousands)	2018		2017
Fair value of asset at lease inception	$	7,816	$	7,126
Less: Accumulated amortization	6,506		5,056
Capital lease asset	$	1,310	$	2,070

	For the years ended December 31,
(in thousands)	2018	2017	2016
Amortization included in fuel cost recovery mechanism	$1,451	$1,401	$1,353

Jointly-owned Pipeline

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2018 and 2017, 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 the operating expenses of the income statement. Accumulated depreciation for this pipeline totaled $1.4 million and $1.3 million, at December 31, 2018 and 2017, respectively.

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.

In May 2016, we received $650,000 in cash pursuant to a settlement agreement with a vendor related to implementation of a customer billing system which is reflected as "Gain from a settlement" in the accompanying consolidated statements of income. The retention of this amount is contingent upon engaging this vendor to provide agreed-upon services through May 2020.

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, 2018, 2017 and 2016:

	2018	2017	2016
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.8%	2.7%
Natural gas transmission – Florida	2.3%	3.5%	3.9%
Electric distribution – Florida	3.4%	3.4%	3.5%

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, 2018, 2017 and 2016, we reported $8.5 million, $8.1 million and $7.3 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. Eastern Shore’s revenues are based on rates approved by the FERC. 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. 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.

For the unregulated propane operation business, we record revenue in the period the products are delivered and/or services are rendered for bulk delivery customers without meters. For propane customers with meters and natural gas marketing customers 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 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.

Our natural gas marketing operation recognizes revenue based on the volume of natural gas delivered to its customers.

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

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, the level of 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 2018, 2017 or 2016.

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 2018, 2017 and 2016 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 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 reviewed periodically and is based on the actuarial table that best reflects of 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. Our natural gas marketing operation enters into natural gas futures and swap contracts to mitigate any price risk associated with the purchase and/or sale of natural gas to specific customers. 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, call option or natural gas futures contract, 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 and natural gas marketing 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 marketing operations 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

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of adoption of the new revenue standard was immaterial to our net income.

This standard required entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration that the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 5, Revenue Recognition, for additional information.

The following highlights the impact of the adoption of ASC 606 on our income statement for the year ended December 31, 2018 and consolidated balance sheet as of December 31, 2018:

	Year Ended   December 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	345,281	$	346,289	$	(1,008	)
Regulated Energy cost of sales	121,828		122,463		(635		)
Depreciation and amortization	40,802		40,767		35
Income before income taxes	77,574		77,981		(407		)
Income taxes	20,994		21,106		(112		)
Net income	56,580		56,875		(295		)

	As of December 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenue	$	27,499	$	29,461	$	(1,962	)
Long-term receivables and other deferred charges	$	6,985	$	6,816	$	169
Capitalization
Retained earnings	$	261,530	$	263,323	$	(1,793	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in operating income during the year ended December 31, 2018, to future years, and a cumulative adjustment that decreased retained earnings and other assets by $1.8 million at December 31, 2018, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included in operating expenses. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the other components of net benefit costs, retrospectively. As our plans have been frozen for some time, there is no service cost component. The components of net benefit costs have been reclassified to other expense. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 16, Stockholders' Equity, for additional information.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. We adopted ASU 2017-12, effective July 1, 2018, with no material impact on our financial statements. See Note 8, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021, although early adoption is permitted. We early adopted and updated our disclosures during the annual period ended December 31, 2018. Since the guidance impacted disclosures only, there was no impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

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 ("ROU") model that requires a lessee to recognize a ROU 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; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019, and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the respective lease components.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $11.0 to $13.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

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. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not 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. Since the changes only impact disclosures, there will be no financial impact.

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Earnings Per Share

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Weighted average shares outstanding	16,369,616		16,336,789		15,570,539
Basic Earnings Per Share	$	3.46	$	3.56	$	2.87
Calculation of Diluted Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,369,616		16,336,789		15,570,539
Effect of dilutive securities — Share-based compensation	50,254		46,563		42,552
Adjusted denominator — Diluted	16,419,870		16,383,352		15,613,091
Diluted Earnings Per Share	$	3.45	$	3.55	$	2.86

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Acquisitions

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Acquisitions

ACQUISITIONS

Acquisitions in 2018

Marlin Gas Services and Ohl Fuel Oil Acquisitions

In December 2018, Marlin Gas Services, LLC (“Marlin Gas Services”), our newly created subsidiary, acquired certain operating assets of Marlin Gas Transport, Inc. (“Marlin Gas Transport”), a supplier of mobile compressed natural gas utility and pipeline solutions. The acquisition will enable Chesapeake Utilities to offer solutions to address supply interruption scenarios and tailor other alternatives where pipeline supplies are not available or cannot meet customer requirements.

In December 2018, Sharp acquired certain propane operating assets and customers of R. F. Ohl Fuel Oil, Inc. ("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 $18.4 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. The amounts recorded in conjunction with these acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period. Due to the timing of these acquisitions, the revenue and net income from these acquisitions in 2018 were immaterial.

Acquisitions in 2017

ARM, Chipola and Central Gas Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM Energy Management, LLC ("ARM"). The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $4.3 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on a projection that the acquired business would achieve a gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our consolidated financial statements. Based on actual gross margin results in 2018, we were not required to make additional payments under the contingent consideration provisions of the purchase agreement.

In August and December of 2017, Flo-gas acquired certain operating assets of Chipola Propane Gas Company ("Chipola") and Central Gas Company of Okeechobee, Incorporated ("Central Gas"), adding approximately 1,125 residential and commercial propane delivery service customers in Florida.

The acquisition accounting amounts recorded in conjunction with the above transactions are final. The revenue and net income from these acquisitions included in our consolidated statements of income were not material.

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Revenue Recognition Revenue Recognition (Notes)

12 Months Ended

Dec. 31, 2018

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 our revenue by major source based on product and service type for the twelve months endedDecember 31, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	70,338		$	—		$	—		$	70,338
Florida natural gas division	25,341			—			—			25,341
FPU electric distribution	79,803			—			—			79,803
FPU natural gas distribution	81,118			—			—			81,118
Maryland natural gas division	24,172			—			—			24,172
Sandpiper natural gas/propane operations	22,088			—			—			22,088
Total energy distribution	302,860			—			—			302,860
Energy transmission
Aspire Energy	—			35,407			—			35,407
Eastern Shore	64,248			—			—			64,248
Peninsula Pipeline	11,927			—			—			11,927
Total energy transmission	76,175			35,407			—			111,582
Energy generation
Eight Flags	—			17,302			—			17,302
Propane operations
Mid-Atlantic propane operations	—			102,321			—			102,321
Florida propane operations	—			21,282			—			21,282
Total propane operations	—			123,603			—			123,603
Energy services
Marlin Gas Services	—			121			—			121
PESCO - Natural Gas Marketing	—			258,713			—			258,713
	—			258,834			—			258,834
Other and eliminations
Eliminations	(33,754		)	(16,486		)	(49,062		)	(99,302		)
Other	—			1,957			653			2,610
Total other and eliminations	(33,754		)	(14,529		)	(48,409		)	(96,692		)
Total operating revenues (1)	$	345,281		$	420,617		$	(48,409	)	$	717,489

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $236,000 and $334,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Regulated Energy Segment

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

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

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

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

Unregulated Energy Segment

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

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

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

PESCO provides natural gas supply and asset management services to customers (including affiliates of Chesapeake Utilities) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on monthly customer meter readings. We accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period.

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, 2018 and 2017 were as follows:

	Trade Receivables		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962	$	1,270	$	407
Balance at 12/31/2018	83,214		2,614		480
Increase (decrease)	$	8,252	$	1,344	$	73

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. At December 31, 2018 and 2017, we had a contract liability of $480,000 and $407,000, respectively, which was included in other accrued liabilities in the consolidated balance sheet, and which relates to non-refundable prepaid fixed fees for our Mid-Atlantic propane operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the twelve months endedDecember 31, 2018, we recognized revenue of $697,000.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized as performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2018 are expected to be recognized as follows:

(in thousands)	2019		2020		2021		2022		2023		2024 and thereafter
Eastern Shore and Peninsula Pipeline	$	38,505	$	36,768	$	33,510	$	26,566	$	21,146	$	212,620
Natural gas distribution operations	4,109		3,586		3,358		3,320		2,924		30,826
PESCO - Natural Gas Marketing	8,886		4,702		1,728		23		—		—
FPU electric distribution	297		297		297		109		—		—
Total revenue contracts with remaining performance obligations	$	51,797	$	45,353	$	38,893	$	30,018	$	24,070	$	243,446

Practical expedients

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

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Segment Information

12 Months Ended

Dec. 31, 2018

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 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, the new mobile CNG utility and pipeline solutions subsidiary, and other energy services (natural gas marketing and related services). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that wound down its operations shortly after the first quarter of 2017. 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.

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,
	2018			2017			2016
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	332,749		$	316,971		$	302,402
Unregulated Energy	384,740			300,612			196,458
Total operating revenues, unaffiliated customers	$	717,489		$	617,583		$	498,860
Intersegment Revenues(1)
Regulated Energy	$	12,532		$	9,339		$	3,287
Unregulated Energy	35,877			23,983			7,321
Other businesses	653			774			880
Total intersegment revenues	$	49,062		$	34,096		$	11,488
Operating Income
Regulated Energy	$	79,215		$	74,584		$	71,515
Unregulated Energy	16,901			12,631			14,066
Other businesses and eliminations	(1,496		)	205			402
Operating Income	94,620			87,420			85,983
Other expense	(615		)	(2,342		)	(2,328		)
Interest charges	16,431			12,645			10,639
Income Before Income taxes	77,574			72,433			73,016
Income taxes	20,994			14,309			28,341
Net Income	$	56,580		$	58,124		$	44,675
Depreciation and Amortization
Regulated Energy	$	31,876		$	28,554		$	25,677
Unregulated Energy	8,845			7,954			6,386
Other businesses and eliminations	81			91			96
Total depreciation and amortization	$	40,802		$	36,599		$	32,159
Capital Expenditures
Regulated Energy	$	235,912		$	159,011		$	139,994
Unregulated Energy	38,700			26,190			23,984
Other businesses	8,364			5,902			5,398
Total capital expenditures	$	282,976		$	191,103		$	169,376

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

	As of December 31,
	2018		2017
Identifiable Assets
Regulated Energy	$	1,345,805	$	1,121,673
Unregulated Energy	306,045		259,041
Other businesses	41,821		34,220
Total identifiable assets	$	1,693,671	$	1,414,934

Our operations are entirely domestic.

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Supplemental Cash Flow Disclosures

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Supplemental Cash Flow Disclosures

SUPPLEMENTAL CASH FLOW DISCLOSURES

Cash paid for interest and income taxes during the years ended December 31, 2018, 2017 and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017			2016
(in thousands)
Cash paid for interest	$	16,741	$	12,420		$	10,315
Cash paid for income taxes, net of refunds	$	477	$	(4,114	)	$	(5,308	)

Non-cash investing and financing activities during the years ended December 31, 2018, 2017, and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017		2016
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	39,402	$	15,457	$	9,791
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	777
Common stock issued under the SICP	$	2,006	$	1,127	$	1,027
Capital lease obligation	$	1,310	$	2,070	$	3,471

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Derivative Instruments

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Derivative Instruments

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)		2018			2017			2016
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts and options (1)	Revenue	$	—		$	112		$	(546	)
Natural gas futures contracts	Cost of sales	(3,189		)	(3,633		)	(541		)
Propane swap agreements	Cost of sales	(13		)	8			7
Natural gas swap contracts	Cost of sales	—			1			—
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			(9		)	49
Natural gas futures contracts	Natural gas inventory	—			—			(233		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(647		)	1,607			(364		)
Propane swap agreements	Other comprehensive income (loss)	(2,773		)	487			1,016
Natural gas futures contracts	Cost of sales	(2,010		)	(456		)	345
Natural gas swap contracts	Cost of sales	197			(822		)	—
Natural gas futures contracts	Other comprehensive income (loss)	532			(1,476		)	222
Natural gas swap contracts	Other comprehensive income	200			986			—
Total		$	(7,703	)	$	(3,195	)	$	(45	)

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

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Fair Value of Financial Instruments

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Fair Value of Financial Instruments

FAIR VALUEOF 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 values of forward contracts are measured using market transactions in either the listed or over-the-counter markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts 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, 2018 and 2017, respectively:

			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	13,165		—		13,165		—
Total assets	$	19,876	$	6,025	$	13,165	$	686
Liabilities:
Derivative liabilities	$	14,871	$	—	$	14,871	$	—

			Fair Value Measurements Using:
As of December 31, 2017	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	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	68			79
Transfers/disbursements	(41		)	(53		)
Investment income	11			61
Ending Balance	$	686		$	648

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

At December 31, 2018 and 2017, 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 and 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, 2018, long-term debt, which includes the current maturities but excludes capital lease obligations, had a carrying value of $327.2 million, compared to the estimated fair value of $323.8 million, 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, adjusted for duration, optionality and risk profile. At December 31, 2017, long-term debt, which includes the current maturities but excludes a capital lease obligation, had a carrying value of $205.2 million, compared to a fair value of $215.4 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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

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Investments

12 Months Ended

Dec. 31, 2018

Investments [Abstract]

Investments

INVESTMENTS

The investment balances at December 31, 2018 and 2017, consisted of the following:

	As of December 31,
(in thousands)	2018		2017
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	6,689	$	6,734
Investments in equity securities	22		22
Total	$	6,711	$	6,756

We classify these investments as trading securities and report them at their fair value. For the year ended December 31, 2018, we recorded net unrealized losses of $428,000 and for the years ended December 31, 2017 and 2016, we recorded net unrealized gains of $1.0 million and $379,000, respectively, in other income (expense) in the consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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Goodwill and Other Intangible Assets

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Goodwill and Other Intangible Assets

GOODWILLAND OTHER INTANGIBLE ASSETS

The carrying value of goodwill as of December 31, 2018 and 2017 was as follows:

	As of December 31,
(in thousands)	2018		2017
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy
Mid-Atlantic Propane Operations	2,147		674
Florida Propane Operations	1,188		1,188
Aspire Energy	10,119		10,119
Marlin Gas Services	4,760		—
Natural Gas Marketing - PESCO	4,270		4,270
Total Goodwill	$	25,837	$	19,604

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

The annual impairment testing for 2018 and 2017 indicated no impairment of goodwill.

The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2018 and 2017 are as follows:

	As of December 31,
	2018				2017
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	7,757	$	3,664	$	7,393	$	2,880
Non-Compete agreements	2,245		202		270		175
Other	270		199		270		192
Total	$	10,272	$	4,065	$	7,933	$	3,247

The customer lists, non-compete agreements and other intangibles acquired in the purchases of the operating assets of several companies are being amortized over five to 41 years.

For the years ended December 31, 2018, 2017 and 2016, amortization expense of intangible assets was $818,000, $537,000, and $380,000, respectively. Amortization expense of intangible assets is expected to be $1.1 million for each of the years 2019, 2020 and 2021, $820,000 for 2022 and $813,000 for 2023.

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Income Taxes

12 Months Ended

Dec. 31, 2018

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, 2018, the 2015 and 2016 federal income tax returns are under examination, and no report has been issued at this time.

We had no net operating loss for federal income tax purposes as of December 31, 2018 and 2017. For state income tax purposes, we had net operating losses in various states of $60.1 million and $34.2 million as of December 31, 2018 and 2017, respectively, almost all of which will expire in 2037. We have recorded deferred tax assets of $2.0 million and $1.6 million related to state net operating loss carry-forwards at December 31, 2018 and 2017, 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 are effective for taxable years beginning on or after January 1, 2018. The provisions significantly impacting 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. We have completed the assessment of the impact as it relates to 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 2018, 2017, and 2016; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2018, 2017, and 2016; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2018 and 2017.

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Current Income Tax Expense
Federal	$	(845	)	$	2,803		$	(4,898	)
State	660			492			2,053
Other	(47		)	(71		)	(71		)
Total current income tax expense	(232		)	3,224			(2,916		)
Deferred Income Tax Expense (1)
Property, plant and equipment	19,164			8,314			31,062
Deferred gas costs	(1,435		)	2,002			1,163
Pensions and other employee benefits	463			180			237
FPU merger-related premium cost and deferred gain	(528		)	(1,148		)	(572		)
Net operating loss carryforwards	(331		)	193			(9		)
Other	3,893			1,544			(624		)
Total deferred income tax expense	21,226			11,085			31,257
Total Income Tax Expense	$	20,994		$	14,309		$	28,341

⁽¹⁾ Includes $3.5 million, $873,000 and $2.1 million of deferred state income taxes for the years 2018, 2017 and 2016, respectively.

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	16,291		$	25,351		$	22,759
State income taxes, net of federal benefit	4,088			1,894			3,422
ESOP dividend deduction	(158		)	(257		)	(264		)
Revaluation of deferred tax assets and liabilities	—			(14,299		)	—
Other	773			1,620			2,424
Total Income Tax Expense	$	20,994		$	14,309		$	28,341
Effective Income Tax Rate (2)	27.06		%	19.75		%	38.81		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2018 and 35 percent for 2017 and 2016.

⁽²⁾Effective tax rate 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,
	2018		2017
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	153,423	$	133,581
Acquisition adjustment	8,896		9,323
Loss on reacquired debt	32		153
Deferred gas costs	1,139		2,574
Natural gas conversion costs	3,987		2,760
Other	2,641		2,662
Total deferred income tax liabilities	170,118		151,053
Deferred income tax assets:
Pension and other employee benefits	3,711		4,698
Environmental costs	1,710		1,744
Net operating loss carryforwards	2,010		1,625
Self-insurance	151		164
Storm reserve liability	—		717
Other	5,716		6,255
Total deferred income tax assets	13,298		15,203
Deferred Income Taxes Per Consolidated Balance Sheets	$	156,820	$	135,850

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Long-Term Debt

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Long-Term Debt

LONG-TERM DEBT

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,986		$	7,982
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	4,000			6,000
5.93% note, due October 31, 2023	15,000			18,000
5.68% note, due June 30, 2026	23,200			26,100
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			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			—
3.58% note, due November 30, 2038	50,000			—
Term Note due January 21, 2020 (1)	30,000			—
Promissory notes	26			97
Capital lease obligations	1,310			2,070
Less: debt issuance costs	(567		)	(433		)
Total long-term debt	327,955			206,816
Less: current maturities	(11,935		)	(9,421		)
Total long-term debt, net of current maturities	$	316,020		$	197,395

⁽¹⁾ In December of 2018 we issued a $30.0 million unsecured Term Note through PNC Bank N.A. The maturity date of the Term Note is January 21, 2020. The Term Note bears interest at a rate equal to the one month LIBOR rate plus 75 basis points. The interest rate at December 31, 2018 was 3.23%

Annual maturities

Annual maturities and principal repayments of long-term debt, excluding the capital lease obligation, are as follows:

Year	2019		2020		2021		2022		2023		Thereafter		Total
(in thousands)
Payments	$	10,626	$	45,600	$	13,600	$	25,100	$	20,600	$	211,700	$	327,226

See Note 15, Lease Obligations, for future payments related to the capital lease obligation.

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 percent unsecured debt in April 2017. The Prudential Shelf Agreement was amended in September 2018 to increase the borrowing capacity to $150.0 million after which Prudential accepted our request to purchase our unsecured debt of $100.0 million at an interest rate of 3.98 percent on or before August 20, 2019. The NYL Shelf Agreement totaling $100.0 million was entered 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, 2018, we had not requested that MetLife purchase unsecured senior debt under the MetLife Shelf Agreement.

The following table summarizes our shelf agreements borrowing information at December 31, 2018:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments			Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

The Prudential Shelf Agreement and the NYL Shelf Agreement 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.

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, 2018, FPU’s cumulative net income base was $155.8 million, offset by restricted payments of $37.6 million, leaving $118.2 million of available dividend capacity.

The dividend restrictions in FPU’s first mortgage bonds resulted in approximately $42.2 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2018. This represents approximately 8.1 percent 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

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 in December 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50.0 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the Senior Note agreements.

Certain uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93 percent Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2018, the cumulative consolidated net income base was $444.3 million, offset by restricted payments of $201.5 million, leaving $242.8 million of cumulative net income free of restrictions. As of December 31, 2018, we are in compliance with all of our debt covenants.

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Short-Term Borrowing

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Short-Term Borrowing

SHORT-TERM BORROWINGS

At December 31, 2018 and 2017, we had $294.5 million and $251.0 million, respectively, of short-term borrowings outstanding at the weighted average interest rates of 3.44 percent and 2.42 percent, respectively. We have an aggregate of $370.0 million in credit lines comprised of five 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 on October 31, 2019 with the exception of the Revolver which is available through October 8, 2020. We incurred commitment fees of $93,300, $131,000 and $145,000 in 2018, 2017 and 2016, respectively. The following table summarizes our short-term borrowing facilities information at December 31, 2018 and 2017.

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2018		December 31, 2017		Available at December 31, 2018
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 1.00 percent	$	25,000	$	55,000	$	30,000
Committed revolving credit facility B	30,000		plus 1.00 percent	15,431		20,500		14,569
Short-term revolving credit note C	50,000		plus 0.80 percent	50,000		50,000		—
Committed revolving credit facility D	45,000		plus 0.85 percent	34,672		40,171		10,328
Committed revolving credit facility E	40,000		plus 0.85 percent	40,000		—		—
Committed revolving credit facility F(2)	150,000		plus up to 1.25 percent	125,000		75,000		25,000
Total short term credit facilities	$	370,000		$	290,103	$	240,671	$	79,897
Book overdrafts(1)				4,355		10,298
Total short-term borrowing				$	294,458	$	250,969

.

⁽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 $200.0 million.

We are authorized by our Board of Directors to borrow up to $350.0 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. We are in compliance with all of our debt covenants.

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Lease Obligations

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Lease Obligations

LEASE OBLIGATIONS

We have entered into several operating lease arrangements for office space, land, equipment and pipeline facilities. Rent expense related to these leases for 2018, 2017 and 2016 was $3.8 million, $3.6 million and $2.5 million, respectively. As of December 31, 2018, future minimum payments under our current lease agreements are as follows:

Year(s)	2019	2020	2021	2022	2023	Thereafter	Total
(in thousands)
Expected payments	$2,349	$1,998	$1,761	$1,689	$1,642	$5,398	$14,837

For the years ended December 31, 2018, 2017 and 2016 we paid $2.4 million ,$1.5 million and $1.5 million respectively, for capital lease arrangements related to Sandpiper's capacity, supply and operating agreement and our Mid-Atlantic propane operations' lease arrangement for property in Anne Arundel County, Maryland which it intends to purchase during the first quarter of 2019. Future minimum payments under these lease arrangements are $1.3 million in 2019.

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Stockholders' Equity

12 Months Ended

Dec. 31, 2018

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 contracts cash flow hedges.

The following table present the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2018 and 2017. All amounts in the following tables are presented net of tax.

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contracts Cash Flow Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income before reclassifications	281			159			440
Amounts reclassified from accumulated other comprehensive income/(loss)	336			(170		)	166
Net current-period other comprehensive income/(loss)	617			(11		)	606
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	)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the years ended December 31, 2018, 2017 and 2016. 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)	2018			2017			2016
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(579		)	(636		)	(871		)
Total before income taxes	(502		)	(559		)	(794		)
Income tax benefit	63			223			320
Net of tax	$	(439	)	$	(336	)	$	(474	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(647	)	$	1,607		$	(322	)
Natural gas swaps (2)	197			(822		)	—
Natural gas futures (2)	(2,010		)	(456		)	345
Total before income taxes	(2,460		)	329			23
Income tax impact	701			(159		)	(3		)
Net of tax	$	(1,759	)	$	170		$	20
Total reclassifications for the period	$	(2,198	)	$	(166	)	$	(454	)

⁽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.

Amortization of defined benefit pension and postretirement plan items is included in other expense, net and gains and losses on propane swap agreements, call options and natural gas futures contracts are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

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Employee Benefit Plans

12 Months Ended

Dec. 31, 2018

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.

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 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, 2018 and 2017, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedule sets forth the funded status at December 31, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017 and 2016 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2018			2017			2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,443		$	11,355		$	64,664		$	63,832		$	2,428		$	2,428
Interest cost	384			402			2,339			2,482			83			89
Actuarial loss (gain)	(610		)	454			(4,739		)	1,199			(74		)	63
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Benefit obligation — end of year	10,712			11,443			59,377			64,664			2,285			2,428
Change in plan assets:
Fair value of plan assets — beginning of year	9,350			8,668			48,396			43,272			—			—
Actual return on plan assets	(647		)	1,144			(3,113		)	6,025			—			—
Employer contributions	451			306			1,205			1,948			152			152
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Fair value of plan assets — end of year	8,649			9,350			43,601			48,396			—			—
Reconciliation:
Funded status	(2,063		)	(2,093		)	(15,776		)	(16,268		)	(2,285		)	(2,428		)
Accrued pension cost	$	(2,063	)	$	(2,093	)	$	(15,776	)	$	(16,268	)	$	(2,285	)	$	(2,428	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%	4.00		%	3.50		%
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,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic pension cost:
Interest cost	$	384		$	402		$	421		$	2,339		$	2,482		$	2,525		$	83		$	89		$	91
Expected return on assets	(542		)	(495		)	(501		)	(3,091		)	(2,779		)	(2,702		)	—			—
Amortization of actuarial loss	343			399			459			404			513			519			101			87			87
Settlement expense	—			—			161			—			—			—
Net periodic pension cost(1)	185			306			540			(348		)	216			342			184			176			178
Amortization of pre-merger regulatory asset	—			—			—			761			761			761			—			—			—
Total periodic cost	$	185		$	306		$	540		$	413		$	977		$	1,103		$	184		$	176		$	178
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	6.50		%	—		%	—		%	—		%

(1) As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the consolidated statements of income.

Included in the net periodic costs for the FPU Pension Plan is continued 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. The unamortized balance of this regulatory asset was $543,000 and $1.3 million at December 31, 2018 and 2017, respectively.

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 following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2018, 2017 and 2016:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2018		2017		2016		2018		2017		2016
Asset Category
Equity securities	49.02	%	52.70	%	52.93	%	50.04	%	55.17	%	53.18	%
Debt securities	40.98	%	37.79	%	37.64	%	41.06	%	36.56	%	37.74	%
Other	10.00	%	9.51	%	9.43	%	8.90	%	8.27	%	9.08	%
Total	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%

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 long-term investment return in excess of the growth of the plans’ retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain a diversified portfolio to reduce the risk of large losses.

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

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, 2018 and 2017, 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, 2018								At December 31, 2017
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)	$	3,399	$	—	$	—	$	3,399	$	4,245	$	—	$	—	$	4,245
U.S. Mid Cap (1)	1,478		—		—		1,478		1,775		—		—		1,775
U.S. Small Cap (1)	670		—		—		670		918		—		—		918
International (2)	9,226		—		—		9,226		11,916		—		—		11,916
Alternative Strategies (3)	5,726		—		—		5,726		5,528		—		—		5,528
	20,499		—		—		20,499		24,382		—		—		24,382
Mutual Funds - Debt securities
Fixed income (4)	18,630		—		—		18,630		18,454		—		—		18,454
High Yield (4)	2,818		—		—		2,818		2,772		—		—		2,772
	21,448		—		—		21,448		21,226		—		—		21,226
Mutual Funds - Other
Commodities (5)	1,902		—		—		1,902		2,154		—		—		2,154
Real Estate (6)	2,216		—		—		2,216		2,300		—		—		2,300
Guaranteed deposit (7)	—		—		627		627		—		—		436		436
	4,118		—		627		4,745		4,454		—		436		4,890
Total Pension Plan Assets in fair value hierarchy	$	46,065	$	—	$	627	46,692		$	50,062	$	—	$	436	50,498
Investments measured at net asset value (8)							5,558								7,248
Total Pension Plan Assets							$	52,250							$	57,746

⁽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, 2018 and 2017, 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, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Balance, beginning of year	$	436		$	498
Purchases	1,674			2,271
Transfers in	2,375			1,743
Disbursements	(3,872		)	(4,101		)
Investment income	14			25
Balance, end of year	$	627		$	436

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, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017, and 2016:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,128		$	1,132		$	1,287		$	1,349
Interest cost	38			41			47			50
Plan participants contributions	136			118			41			48
Actuarial loss (gain)	(131		)	72			(89		)	(48		)
Benefits paid	(169		)	(235		)	(99		)	(112		)
Benefit obligation — end of year	1,002			1,128			1,187			1,287
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	33			117			58			64
Plan participants contributions	136			118			41			48
Benefits paid	(169		)	(235		)	(99		)	(112		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,002		)	(1,128		)	(1,187		)	(1,287		)
Accrued postretirement cost	$	(1,002	)	$	(1,128	)	$	(1,187	)	$	(1,287	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%

⁽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 2018, 2017, and 2016 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	38		$	41		$	43		$	47		$	50		$	55
Amortization of actuarial loss	58			53			64			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	19			17			30			47			50			55
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost(1)	$	19		$	17		$	30		$	55		$	58		$	63
Assumptions
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%

(1) As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

Similar to the FPU Pension Plan, continued amortization of the FPU Medical Plan regulatory asset related to the unrecognized cost prior to the merger with Chesapeake Utilities was included in the net periodic cost. The unamortized balance of this regulatory asset was $14,000 and $22,000 at December 31, 2018 and 2017, respectively.

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, 2018:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(524	)	$	—		$	(524	)
Net loss (gain)	3,865		18,544		559		578			(79		)	23,467
Total	$	3,865	$	18,544	$	559	$	54		$	(79	)	$	22,943
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,865	$	3,523	$	559	$	54		$	(15	)	$	7,986
Post-merger regulatory asset	—		15,021		—		—			(64		)	14,957
Subtotal	3,865		18,544		559		54			(79		)	22,943
Pre-merger regulatory asset	—		543		—		—			14			557
Total unrecognized cost	$	3,865	$	19,087	$	559	$	54		$	(65	)	$	23,500

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2018 is net of income tax benefits of $2.1 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations, which is included in the above table as a post-merger regulatory asset. FPU also continues to maintain and amortize a portion of the unrecognized pension and postretirement benefit costs prior to the merger with Chesapeake Utilities related to its regulated operations, which is shown as a pre-merger regulatory asset.

Assumptions

The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2018, 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, 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 2018 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 2019, we expect to contribute $163,000 and $1.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $383,000 to the Chesapeake SERP. We also expect to contribute $96,000 and $94,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2019.

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)
2019	$	528	$	3,091	$	383	$	96	$	94
2020	$	529	$	3,221	$	150	$	85	$	87
2021	$	736	$	3,299	$	148	$	82	$	91
2022	$	595	$	3,485	$	147	$	81	$	93
2023	$	1,244	$	3,558	$	145	$	64	$	80
Years 2024 through 2028	$	3,866	$	18,570	$	744	$	275	$	402

⁽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, 2018, 2017 and 2016, 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 $5.5 million, $5.0 million, and $4.5 million for the years ended December 31, 2018, 2017 and 2016, respectively. As of December 31, 2018, 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 $6.7 million at both December 31, 2018 and 2017. (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 $3.9 million and $3.4 million at December 31, 2018 and 2017, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheet.

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Share-Based Compensation Plans

12 Months Ended

Dec. 31, 2018

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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 475,099 shares of common stock reserved for issuance under the SICP.

The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2018, 2017 and 2016:

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Awards to non-employee directors	$	539		$	540		$	580
Awards to key employees	2,871			1,950			1,787
Total compensation expense	3,410			2,490			2,367
Less: tax benefit	(934		)	(1,003		)	(952		)
Share-based compensation amounts included in net income	$	2,476		$	1,487		$	1,415

Stock Options

There were no stock options outstanding at December 31, 2018 or 2017, nor were any stock options issued during the years 2016 through 2018.

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 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for board service through the 2018 Annual Meeting of Stockholders; as a group, 7,515 shares, with a weighted average fair value of $71.80, were issued and vested in 2017. 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, were issued and vested in 2018.

The intrinsic values of the shares granted to our non-employee directors are equal to the fair value of these awards on the date of grant. At December 31, 2018, there was $180,000 of unrecognized compensation expense related to these awards. This expense will be fully recognized by April 2019, which approximates the expected remaining service period of those directors.

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, 2016	115,091		$	51.85
Granted	52,355		$	63.42
Vested	(32,926	)	$	38.88
Expired	(1,878	)	$	39.97
Outstanding — December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding — December 31, 2018	131,741		$	67.24

⁽¹⁾ Includes 2,569 shares that were forfeited

The intrinsic value of these awards was $10.7 million, $10.4 million and $7.7 million in 2018, 2017 and 2016, respectively. At December 31, 2018, there was $2.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2019 through 2020.

In 2018, 2017 and 2016, 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,
	2018		2017		2016
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,436		10,269		12,031
Amounts remitted to tax authorities to satisfy obligations	$	1,210	$	692	$	770
Tax benefit associated with settlement of share based payments	$	—	$	349	285

In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). 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, and an additional 2,569 shares were forfeited. We settled the awards that vested in cash and recognized $1.1 million as share-based compensation expense.

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Rates and Other Regulatory Activities

12 Months Ended

Dec. 31, 2018

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Rates and Other Regulatory Activities

RATESAND 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 by the Florida PSC.

Delaware

Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018.

CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition, and subsequent conversion to natural gas of certain CGS located within our service territory. We requested the establishment of regulatory accounting treatment and valuation of the proposed acquisition, approval of a methodology to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs. The application included a request that the Delaware PSC regulate the propane CGS systems after their acquisition but before conversion to natural gas.  In late 2018, the Delaware PSC ruled that it did not have jurisdiction over these propane CGS systems and could not approve the methodology given the lack of jurisdiction.  We are considering proposing legislation to clarify the Delaware PSC jurisdiction or we may redesign the application and re-file.

Effect of the TCJA on customers: The Delaware PSC issued an order requiring all rate-regulated utilities to: (i) file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules), and (ii) propose procedures for changing rates to reflect those impacts on or before March 31, 2018. In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changes in the federal corporate income tax laws. In compliance with the Delaware PSC order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. On May 31, 2018, our Delaware Division filed the information requested by the PSC, including an updated report reflecting the impact of the TCJA. On January 31, 2019, the Delaware PSC approved the as-filed Delaware Division Delivery Service Rates reflecting the impact of the TCJA.  The new rates will go into effect March 1, 2019, and the Company will have to complete refunds back to February 2018, per the Commission’s previous order, by June 30, 2019.  The order also provides for a line item billing credit to go into effect on April 1, 2019, for the return of the excess deferred income taxes.  Additional information on the TCJA impact is included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Maryland

Effect of the TCJA on customers: In April 2018, the Maryland PSC issued orders related to the TCJA impact on both the Maryland Division and Sandpiper operations. Please see the actions taken in conjunction with these orders in the TCJA table at the end of this Note 19, Rates and Other Regulatory Activities. Additionally, if in the future the Maryland Division or Sandpiper identifies any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations filed a petition with the Florida PSC requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of our electrical grid. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. More details about this methodology are included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Electric Limited Proceeding-Storm Recovery: 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 this filing, had a deficit of $779,000. We requested approval of a surcharge of $1.82 per kilowatt hour for two years to recover storm-related costs and replenish the storm reserve. FPU filed written testimony on this matter in August 2018. This matter was heard before the Florida PSC in December 2018, final legal briefs were submitted and, on January 14, 2019, and is scheduled for approval at Agenda on March 5, 2019.

In October 2018, Hurricane Michael passed through Florida Public Utilities Company's (“FPU”) 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 losing electrical service. FPU has restored service to those customers who were able to accept service following Hurricane Michael after a significant hurricane restoration effort. In conjunction with restoring these services, FPU expended over $60.0 million to restore service, which has been recorded as new plant and equipment or charged against FPU’s storm reserve. We are preparing the necessary regulatory filings to seek recovery for the costs incurred, including replenishment of FPU's storm reserve. In conjunction with the hurricane-related expenditures, we executed two13-month unsecured term loans as temporary financing, each in the amount of $30.0 million. The interest cost associated with these loans is LIBOR plus 75 basis points. One of the term loans was executed in December 2018 and the other was executed in January 2019. The storm did not have a material impact on the Company’s financial results in 2018, and is not expected to have a significant impact going forward assuming reasonable regulatory treatment.

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 division filed petitions and supporting testimony regarding the disposition of the related impacts of the TCJA. Hearings on this matter took place in November 2018, The Florida PSC approved staff’s recommendations on February 5, 2019. Final orders were issued on February 25, 2019, and are subject to a 30-day appeal period. Staff’s recommendations are summarized in the table at the end of this Note 19, Rates and Other Regulatory Activities.

Eastern Shore

2017 Expansion Project: In October 2017, the FERC issued a Certificate of Public Convenience and Necessity authorizing Eastern Shore to construct this project, the largest expansion in Eastern Shore's history. The facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system and an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

The first phase of the project was placed into service in December 2017 and, as of December 31, 2018, we have substantially completed construction. The TETLP interconnect upgrade was placed into service in December 2017, and the Fair Hill Loop, the Jennersville Loop, the Daleville Compressor Station, the Seaford-Millsboro Connector, and the Millsboro Pressure Control Station were placed into service at various dates in 2018. The Parkesburg Loop was placed into service in January 2019. The few remaining segments are expected to be placed into service in various phases during the first half of 2019.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC. In August 2017, Eastern Shore implemented the proposed new rates, subject to refund, based on the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates pending FERC approval of a settlement agreement and refunds to customers according to the terms of the settlement. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. In April 2018, Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates. Exclusive of the TCJA impact, which is discussed below, base rates increased, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on customers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the reduction in its federal corporate income tax rate. These adjusted base rates became effective January 1, 2018 and will generate approximately $6.6 million in incremental margin, on an annual basis. Other information about the impact of the TCJA on ESNG has been included in the table at the end of this Note 19, Rates and Other Regulatory Activities.

In October 2018, the FERC issued an order granting a waiver to Eastern Shore. In April 2018, Eastern Shore consummated a filing, which included its comments associated with the United Airlines, Inc. vs. FERC proceeding and requested confirmation from the FERC that Eastern Shore is not required to provide an informational filing because of its implementation of lower rates in accordance with the 2017 rate case settlement agreement.

Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application with the FERC, requesting authorization to construct and operate the Del-Mar Energy Pathway project, which will provide an additional 14,300 Dts/d of capacity 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 Somerset County, Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) further 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. During the fourth quarter of 2018, the FERC held a full project area scoping meeting in Sussex County, Delaware and issued a Notice of Schedule for Environmental Review, indicating issuance of its Environmental Assessment for the Del-Mar Energy Pathway project by April 1, 2019.

Summary TCJA Table

	Regulatory Liabilities related to Excess Accumulated Deferred Income Taxes ("ADIT")		Status of Customer Rate impact related to 35 percent to 21 percent rate change
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing	Implemented one-time bill credit (totaling $900,000) in April 2018 - Customer rates adjusted in April, 2018
Delaware Division (Delaware PSC)	$13,262	In January 2019, PSC approved amortization of ADIT and corresponding customer rate reductions effective March 1, 2019.	Customer rates to be adjusted March 1, 2019. One-time bill credit to be implemented during the second quarter.
Maryland Division (Maryland PSC)	$4,211	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $365,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Sandpiper Energy (Maryland PSC)	$3,815	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $608,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,471	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Natural Gas (includes FPU, Fort Meade, and Indiantown) (Florida PSC)	$19,505	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Electric (Florida PSC)	$5,995	In January 2019, PSC approved 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, 2018 and 2017, 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,
	2018		2017
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	4,631	$	9,869
Under-recovered GRIP revenue (2)	165		164
Deferred postretirement benefits (3)	15,517		15,498
Deferred conversion and development costs (1)	16,727		11,735
Environmental regulatory assets and expenditures (4)	2,731		3,222
Acquisition adjustment (5)	33,255		39,992
Loss on reacquired debt (6)	942		1,031
Other	3,250		4,994
Total Regulatory Assets	$	77,218	$	86,505
Regulatory Liabilities
Self-insurance (7)	$	947	$	1,013
Over-recovered purchased fuel and conservation cost recovery (1)	5,443		2,048
Over-recovered GRIP revenue (2)	1,563		2,245
Storm reserve (7)	677		669
Accrued asset removal cost (8)	42,401		40,948
Deferred income taxes due to rate change (9)	91,162		98,492
Other	729		2,048
Total Regulatory Liabilities	$	142,922	$	147,463

⁽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. 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. Included in these amounts are $543,000 of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including a gross up for income tax, because it is not tax deductible, and $746,000 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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Environmental Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

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Environmental Commitments and Contingencies

ENVIRONMENTAL COMMITMENTSAND 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 six sites located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland.

As of December 31, 2018, we had approximately $9.1 million 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, 2018, we have recovered approximately $11.5 million, leaving approximately $2.5 million 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 Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford (Florida)	In March 2018, the 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. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.
Seaford (Delaware)	Proposed plan for implementation approved by Delaware Department of Natural Resources and Environmental Control in July 2017. Site assessment is ongoing.	$273,000 to $465,000.
Cambridge (Maryland)	Currently in discussions with MDE.	Unable to estimate.

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Other Commitments and Contingencies

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Other Commitments and Contingencies

OTHER COMMITMENTSAND CONTINGENCIES

Natural Gas, Electric and Propane Supply

Our Delmarva Peninsula natural gas distribution operations have 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. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with Eastern Gas & Water Investment Company, LLC ("EGWIC") to purchase propane through May 2019. Sandpiper's remaining commitment is approximately 1.2 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC through May 2019. Sharp's current annual commitment is estimated at approximately 1.2 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC; neither agreement permits the set off of the rights and obligations in one agreement against those in the other agreement.

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, including PESCO. 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.

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL 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, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

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

Year	2019		2020-2021		2022-2023		Beyond 2023		Total
(in thousands)
Purchase Obligations	$	158,544	$	74,970	$	42,279	$	129,019	$	404,812

Corporate Guarantees

The Board of Directors has authorized the Company 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 during 2018 was $95.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at December 31, 2018 was $76.5 million, with the guarantees expiring on various dates through December 2019.

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, 2018, we have issued letters of credit totaling approximately $7.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019. There have been no draws on these letters of credit as of December 31, 2018. 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.

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Quarterly Financial Data

12 Months Ended

Dec. 31, 2018

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)
2018(1)
Operating Revenues	$	239,356	$	136,664	$	140,279	$	201,190
Operating Income	$	40,406	$	13,248	$	12,036	$	28,930
Net Income	$	26,855	$	6,387	$	5,538	$	17,801
Earnings per share:
Basic	$	1.64	$	0.39	$	0.34	$	1.09
Diluted	$	1.64	$	0.39	$	0.34	$	1.08
2017(1)
Operating Revenues	$	185,160	$	125,084	$	126,936	$	180,403
Operating Income	$	35,099	$	14,061	$	14,632	$	23,628
Net Income	$	19,144	$	6,046	$	6,833	$	26,101
Earnings per share:
Basic	$	1.17	$	0.37	$	0.42	$	1.60
Diluted	$	1.17	$	0.37	$	0.42	$	1.59

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

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2018

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

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 by classification as of December 31, 2018 and 2017 is provided in the following table:

	As of December 31,
(in thousands)	2018			2017
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	657,630		$	589,149
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	537,654			384,360
Electric distribution – Florida	102,133			100,227
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	123,632			108,177
Natural gas transmission – Ohio	70,225			66,037
Electricity and Steam generation – Florida	35,239			35,239
Mobile CNG utility and pipeline solutions	7,240			—
Other unregulated energy	1,346			1,229
Other	34,584			27,699
Total property, plant and equipment	1,569,683			1,312,117
Less: Accumulated depreciation and amortization	(294,295		)	(270,599		)
Plus: Construction work in progress	108,584			84,509
Net property, plant and equipment	$	1,383,972		$	1,126,027

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, 2018, 2017 and 2016, the non-refundable contributions totaled $2.8 million, $2.1 million and $1.0 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 year ended December 31, 2018, AFUDC totaled $1.9 million, which was reflected as a reduction of interest charges. During the years ended December 31, 2017 and 2016, AFUDC was not material.

Assets Used in Leases

Property, plant and equipment for the Florida natural gas transmission operation included $1.4 million of assets, at December 31, 2018 and 2017, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a 20-year term. Accumulated depreciation for these assets totaled $720,000 and $652,000 at December 31, 2018 and 2017, respectively.

Capital Lease Assets

Property, plant and equipment include capital lease assets related to: (i) a lease arrangement entered into by our Delmarva Peninsula natural gas distribution operation associated with Sandpiper's capacity, supply and operating agreement and (ii) our Mid-Atlantic propane operation's lease arrangement for property in Anne Arundel County Maryland which it intends to purchase during the first quarter of 2019. Information regarding the impact of the capital leases in our financial statements is shown below. Additional information can be found in Note 21, Other Commitments and Contingencies.

	As of December 31,
(in thousands)	2018		2017
Fair value of asset at lease inception	$	7,816	$	7,126
Less: Accumulated amortization	6,506		5,056
Capital lease asset	$	1,310	$	2,070

	For the years ended December 31,
(in thousands)	2018	2017	2016
Amortization included in fuel cost recovery mechanism	$1,451	$1,401	$1,353

Jointly-owned Pipeline

Property, plant and equipment for our Florida natural gas transmission operation also included $6.7 million of assets, at December 31, 2018 and 2017, 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 the operating expenses of the income statement. Accumulated depreciation for this pipeline totaled $1.4 million and $1.3 million, at December 31, 2018 and 2017, respectively.

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.

In May 2016, we received $650,000 in cash pursuant to a settlement agreement with a vendor related to implementation of a customer billing system which is reflected as "Gain from a settlement" in the accompanying consolidated statements of income. The retention of this amount is contingent upon engaging this vendor to provide agreed-upon services through May 2020.

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, 2018, 2017 and 2016:

	2018	2017	2016
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.8%	2.7%
Natural gas transmission – Florida	2.3%	3.5%	3.9%
Electric distribution – Florida	3.4%	3.4%	3.5%

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, 2018, 2017 and 2016, we reported $8.5 million, $8.1 million and $7.3 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. Eastern Shore’s revenues are based on rates approved by the FERC. 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. 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.

For the unregulated propane operation business, we record revenue in the period the products are delivered and/or services are rendered for bulk delivery customers without meters. For propane customers with meters and natural gas marketing customers 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 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.

Our natural gas marketing operation recognizes revenue based on the volume of natural gas delivered to its customers.

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

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, the level of 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 2018, 2017 or 2016.

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 2018, 2017 and 2016 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 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 reviewed periodically and is based on the actuarial table that best reflects of 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. Our natural gas marketing operation enters into natural gas futures and swap contracts to mitigate any price risk associated with the purchase and/or sale of natural gas to specific customers. 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, call option or natural gas futures contract, 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 and natural gas marketing 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 marketing operations 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

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of adoption of the new revenue standard was immaterial to our net income.

This standard required entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration that the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 5, Revenue Recognition, for additional information.

The following highlights the impact of the adoption of ASC 606 on our income statement for the year ended December 31, 2018 and consolidated balance sheet as of December 31, 2018:

	Year Ended   December 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	345,281	$	346,289	$	(1,008	)
Regulated Energy cost of sales	121,828		122,463		(635		)
Depreciation and amortization	40,802		40,767		35
Income before income taxes	77,574		77,981		(407		)
Income taxes	20,994		21,106		(112		)
Net income	56,580		56,875		(295		)

	As of December 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenue	$	27,499	$	29,461	$	(1,962	)
Long-term receivables and other deferred charges	$	6,985	$	6,816	$	169
Capitalization
Retained earnings	$	261,530	$	263,323	$	(1,793	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in operating income during the year ended December 31, 2018, to future years, and a cumulative adjustment that decreased retained earnings and other assets by $1.8 million at December 31, 2018, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post-Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included in operating expenses. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the other components of net benefit costs, retrospectively. As our plans have been frozen for some time, there is no service cost component. The components of net benefit costs have been reclassified to other expense. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 16, Stockholders' Equity, for additional information.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. We adopted ASU 2017-12, effective July 1, 2018, with no material impact on our financial statements. See Note 8, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021, although early adoption is permitted. We early adopted and updated our disclosures during the annual period ended December 31, 2018. Since the guidance impacted disclosures only, there was no impact on our financial position or results of operations.

Recent Accounting Standards Yet to be Adopted

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 ("ROU") model that requires a lessee to recognize a ROU 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; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019, and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the respective lease components.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $11.0 to $13.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

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. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not 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. Since the changes only impact disclosures, there will be no financial impact.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2018

Summary of Accounting poliicies [Abstract]

Property, Plant and Equipment [Table Text Block]

A summary of property, plant and equipment by classification as of December 31, 2018 and 2017 is provided in the following table:

	As of December 31,
(in thousands)	2018			2017
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida	$	657,630		$	589,149
Natural gas transmission - Delmarva Peninsula, Pennsylvania and Florida	537,654			384,360
Electric distribution – Florida	102,133			100,227
Unregulated Energy
Propane operations – Mid-Atlantic and Florida	123,632			108,177
Natural gas transmission – Ohio	70,225			66,037
Electricity and Steam generation – Florida	35,239			35,239
Mobile CNG utility and pipeline solutions	7,240			—
Other unregulated energy	1,346			1,229
Other	34,584			27,699
Total property, plant and equipment	1,569,683			1,312,117
Less: Accumulated depreciation and amortization	(294,295		)	(270,599		)
Plus: Construction work in progress	108,584			84,509
Net property, plant and equipment	$	1,383,972		$	1,126,027

Schedule of Capital Leased Assets [Table Text Block]

Information regarding the impact of the capital leases in our financial statements is shown below. Additional information can be found in Note 21, Other Commitments and Contingencies.

	As of December 31,
(in thousands)	2018		2017
Fair value of asset at lease inception	$	7,816	$	7,126
Less: Accumulated amortization	6,506		5,056
Capital lease asset	$	1,310	$	2,070

	For the years ended December 31,
(in thousands)	2018	2017	2016
Amortization included in fuel cost recovery mechanism	$1,451	$1,401	$1,353

Annual Depreciation Rates Table [Table Text Block]

The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2018, 2017 and 2016:

	2018	2017	2016
Natural gas distribution – Delmarva Peninsula	2.5%	2.5%	2.5%
Natural gas distribution – Florida	2.9%	2.9%	2.9%
Natural gas transmission – Delmarva Peninsula	2.7%	2.8%	2.7%
Natural gas transmission – Florida	2.3%	3.5%	3.9%
Electric distribution – Florida	3.4%	3.4%	3.5%

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

The following highlights the impact of the adoption of ASC 606 on our income statement for the year ended December 31, 2018 and consolidated balance sheet as of December 31, 2018:

	Year Ended   December 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	345,281	$	346,289	$	(1,008	)
Regulated Energy cost of sales	121,828		122,463		(635		)
Depreciation and amortization	40,802		40,767		35
Income before income taxes	77,574		77,981		(407		)
Income taxes	20,994		21,106		(112		)
Net income	56,580		56,875		(295		)

	As of December 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenue	$	27,499	$	29,461	$	(1,962	)
Long-term receivables and other deferred charges	$	6,985	$	6,816	$	169
Capitalization
Retained earnings	$	261,530	$	263,323	$	(1,793	)

Estimated Useful Life Of Assets Table [Table Text Block]

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

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

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Weighted average shares outstanding	16,369,616		16,336,789		15,570,539
Basic Earnings Per Share	$	3.46	$	3.56	$	2.87
Calculation of Diluted Earnings Per Share:
Net Income	$	56,580	$	58,124	$	44,675
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,369,616		16,336,789		15,570,539
Effect of dilutive securities — Share-based compensation	50,254		46,563		42,552
Adjusted denominator — Diluted	16,419,870		16,383,352		15,613,091
Diluted Earnings Per Share	$	3.45	$	3.55	$	2.86

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Revenue Recognition Revenue Recognition (Tables)

12 Months Ended

Dec. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table displays our revenue by major source based on product and service type for the twelve months endedDecember 31, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	70,338		$	—		$	—		$	70,338
Florida natural gas division	25,341			—			—			25,341
FPU electric distribution	79,803			—			—			79,803
FPU natural gas distribution	81,118			—			—			81,118
Maryland natural gas division	24,172			—			—			24,172
Sandpiper natural gas/propane operations	22,088			—			—			22,088
Total energy distribution	302,860			—			—			302,860
Energy transmission
Aspire Energy	—			35,407			—			35,407
Eastern Shore	64,248			—			—			64,248
Peninsula Pipeline	11,927			—			—			11,927
Total energy transmission	76,175			35,407			—			111,582
Energy generation
Eight Flags	—			17,302			—			17,302
Propane operations
Mid-Atlantic propane operations	—			102,321			—			102,321
Florida propane operations	—			21,282			—			21,282
Total propane operations	—			123,603			—			123,603
Energy services
Marlin Gas Services	—			121			—			121
PESCO - Natural Gas Marketing	—			258,713			—			258,713
	—			258,834			—			258,834
Other and eliminations
Eliminations	(33,754		)	(16,486		)	(49,062		)	(99,302		)
Other	—			1,957			653			2,610
Total other and eliminations	(33,754		)	(14,529		)	(48,409		)	(96,692		)
Total operating revenues (1)	$	345,281		$	420,617		$	(48,409	)	$	717,489

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $236,000 and $334,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Contract with Customer, Asset and Liability [Table Text Block]

The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2018 and 2017 were as follows:

	Trade Receivables		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962	$	1,270	$	407
Balance at 12/31/2018	83,214		2,614		480
Increase (decrease)	$	8,252	$	1,344	$	73

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

Revenue for these businesses for the remaining performance obligations at December 31, 2018 are expected to be recognized as follows:

(in thousands)	2019		2020		2021		2022		2023		2024 and thereafter
Eastern Shore and Peninsula Pipeline	$	38,505	$	36,768	$	33,510	$	26,566	$	21,146	$	212,620
Natural gas distribution operations	4,109		3,586		3,358		3,320		2,924		30,826
PESCO - Natural Gas Marketing	8,886		4,702		1,728		23		—		—
FPU electric distribution	297		297		297		109		—		—
Total revenue contracts with remaining performance obligations	$	51,797	$	45,353	$	38,893	$	30,018	$	24,070	$	243,446

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Segment Information Segment Information (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018			2017			2016
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	332,749		$	316,971		$	302,402
Unregulated Energy	384,740			300,612			196,458
Total operating revenues, unaffiliated customers	$	717,489		$	617,583		$	498,860
Intersegment Revenues(1)
Regulated Energy	$	12,532		$	9,339		$	3,287
Unregulated Energy	35,877			23,983			7,321
Other businesses	653			774			880
Total intersegment revenues	$	49,062		$	34,096		$	11,488
Operating Income
Regulated Energy	$	79,215		$	74,584		$	71,515
Unregulated Energy	16,901			12,631			14,066
Other businesses and eliminations	(1,496		)	205			402
Operating Income	94,620			87,420			85,983
Other expense	(615		)	(2,342		)	(2,328		)
Interest charges	16,431			12,645			10,639
Income Before Income taxes	77,574			72,433			73,016
Income taxes	20,994			14,309			28,341
Net Income	$	56,580		$	58,124		$	44,675
Depreciation and Amortization
Regulated Energy	$	31,876		$	28,554		$	25,677
Unregulated Energy	8,845			7,954			6,386
Other businesses and eliminations	81			91			96
Total depreciation and amortization	$	40,802		$	36,599		$	32,159
Capital Expenditures
Regulated Energy	$	235,912		$	159,011		$	139,994
Unregulated Energy	38,700			26,190			23,984
Other businesses	8,364			5,902			5,398
Total capital expenditures	$	282,976		$	191,103		$	169,376

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

	As of December 31,
	2018		2017
Identifiable Assets
Regulated Energy	$	1,345,805	$	1,121,673
Unregulated Energy	306,045		259,041
Other businesses	41,821		34,220
Total identifiable assets	$	1,693,671	$	1,414,934

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Supplemental Cash Flow Disclosures (Tables)

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Cash Paid for Interest and Income Taxes

Cash paid for interest and income taxes during the years ended December 31, 2018, 2017 and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017			2016
(in thousands)
Cash paid for interest	$	16,741	$	12,420		$	10,315
Cash paid for income taxes, net of refunds	$	477	$	(4,114	)	$	(5,308	)

Non-Cash Investing and Financing Activities

Non-cash investing and financing activities during the years ended December 31, 2018, 2017, and 2016 were as follows:

	For the Year Ended December 31,
	2018		2017		2016
(in thousands)
Capital property and equipment acquired on account, but not paid for as of December 31	$	39,402	$	15,457	$	9,791
Common stock issued for the Retirement Savings Plan	$	—	$	—	$	777
Common stock issued under the SICP	$	2,006	$	1,127	$	1,027
Capital lease obligation	$	1,310	$	2,070	$	3,471

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Derivative Instruments (Tables)

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of December 31, 2018, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO/natural gas marketing	Natural gas (Dts)	14.4	Cash flows hedges	March 2022
PESCO/natural gas marketing	Natural gas (Dts)	3.8	Not designated	December 2020
Sharp/propane operations	Propane (gallons)	9.7	Cash flows hedges	June 2021
Sharp/propane operations	Propane (gallons)	0.3	Fair value hedges	March 2019

Offsetting Assets and Liabilities [Table Text Block]

The following table summarizes the accounts receivable and payables on a gross and net basis at December 31, 2018 and 2017:

	At December 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	12,368	$	3,834	$	8,534
Accounts payable	$	24,741	$	3,834	$	20,907

	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252

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

The balances related to PESCO are as follows:

(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
PESCO	Other Current Assets	$	2,810	$	6,300

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, 2018 and 2017 are as follows:

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	4,024		—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	71		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	9,059		92
Propane swap agreements	Derivative assets, at fair value	11		1,181
Total Derivative Assets		$	13,165	$	1,286

	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	December 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	4,562	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	8,705		—
Natural gas swap contracts	Derivative liabilities, at fair value	—		469
Propane swap agreements	Derivative liabilities, at fair value	1,604		2
Total Derivative Liabilities		$	14,871	$	6,247

Derivative Instruments and Hedging Activities Disclosure [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)		2018			2017			2016
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts and options (1)	Revenue	$	—		$	112		$	(546	)
Natural gas futures contracts	Cost of sales	(3,189		)	(3,633		)	(541		)
Propane swap agreements	Cost of sales	(13		)	8			7
Natural gas swap contracts	Cost of sales	—			1			—
Derivatives designated as fair value hedges
Put/Call option	Cost of sales	—			(9		)	49
Natural gas futures contracts	Natural gas inventory	—			—			(233		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(647		)	1,607			(364		)
Propane swap agreements	Other comprehensive income (loss)	(2,773		)	487			1,016
Natural gas futures contracts	Cost of sales	(2,010		)	(456		)	345
Natural gas swap contracts	Cost of sales	197			(822		)	—
Natural gas futures contracts	Other comprehensive income (loss)	532			(1,476		)	222
Natural gas swap contracts	Other comprehensive income	200			986			—
Total		$	(7,703	)	$	(3,195	)	$	(45	)

⁽¹⁾ All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

As of December 31, 2018, the following amounts were recorded in the consolidated balance sheets related to fair value hedges:

(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At December 31, 2018		At December 31, 2017		At December 31, 2018		At December 31, 2017
Inventory	$	212	$	—	$	—	$	—

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Fair Value of Financial Instruments (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018 and 2017, respectively:

			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	13,165		—		13,165		—
Total assets	$	19,876	$	6,025	$	13,165	$	686
Liabilities:
Derivative liabilities	$	14,871	$	—	$	14,871	$	—

			Fair Value Measurements Using:
As of December 31, 2017	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	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

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, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	68			79
Transfers/disbursements	(41		)	(53		)
Investment income	11			61
Ending Balance	$	686		$	648

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Investments (Tables)

12 Months Ended

Dec. 31, 2018

Investments [Abstract]

Investments schedule [Table Text Block]

	As of December 31,
(in thousands)	2018		2017
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	6,689	$	6,734
Investments in equity securities	22		22
Total	$	6,711	$	6,756

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Goodwill and Other Intangible Assets (Tables)

12 Months Ended

Dec. 31, 2018

Text Block [Abstract]

Schedule of Carrying Value of Goodwill

The carrying value of goodwill as of December 31, 2018 and 2017 was as follows:

	As of December 31,
(in thousands)	2018		2017
Goodwill
Regulated Energy
Florida Natural Gas Distribution(1)	$	3,353	$	3,353
Unregulated Energy
Mid-Atlantic Propane Operations	2,147		674
Florida Propane Operations	1,188		1,188
Aspire Energy	10,119		10,119
Marlin Gas Services	4,760		—
Natural Gas Marketing - PESCO	4,270		4,270
Total Goodwill	$	25,837	$	19,604

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

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, 2018 and 2017 are as follows:

	As of December 31,
	2018				2017
(in thousands)	Gross Carrying Amount		Accumulated Amortization		Gross Carrying Amount		Accumulated Amortization
Customer lists	$	7,757	$	3,664	$	7,393	$	2,880
Non-Compete agreements	2,245		202		270		175
Other	270		199		270		192
Total	$	10,272	$	4,065	$	7,933	$	3,247

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2018

Income Tax Disclosure [Abstract]

Schedule of Income Tax Expense

The following tables provide: (a) the components of income tax expense in 2018, 2017, and 2016; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2018, 2017, and 2016; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2018 and 2017.

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Current Income Tax Expense
Federal	$	(845	)	$	2,803		$	(4,898	)
State	660			492			2,053
Other	(47		)	(71		)	(71		)
Total current income tax expense	(232		)	3,224			(2,916		)
Deferred Income Tax Expense (1)
Property, plant and equipment	19,164			8,314			31,062
Deferred gas costs	(1,435		)	2,002			1,163
Pensions and other employee benefits	463			180			237
FPU merger-related premium cost and deferred gain	(528		)	(1,148		)	(572		)
Net operating loss carryforwards	(331		)	193			(9		)
Other	3,893			1,544			(624		)
Total deferred income tax expense	21,226			11,085			31,257
Total Income Tax Expense	$	20,994		$	14,309		$	28,341

⁽¹⁾ Includes $3.5 million, $873,000 and $2.1 million of deferred state income taxes for the years 2018, 2017 and 2016, respectively.

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

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)	$	16,291		$	25,351		$	22,759
State income taxes, net of federal benefit	4,088			1,894			3,422
ESOP dividend deduction	(158		)	(257		)	(264		)
Revaluation of deferred tax assets and liabilities	—			(14,299		)	—
Other	773			1,620			2,424
Total Income Tax Expense	$	20,994		$	14,309		$	28,341
Effective Income Tax Rate (2)	27.06		%	19.75		%	38.81		%

⁽¹⁾ Federal income taxes were calculated at 21 percent for 2018 and 35 percent for 2017 and 2016.

⁽²⁾Effective tax rate 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,
	2018		2017
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	153,423	$	133,581
Acquisition adjustment	8,896		9,323
Loss on reacquired debt	32		153
Deferred gas costs	1,139		2,574
Natural gas conversion costs	3,987		2,760
Other	2,641		2,662
Total deferred income tax liabilities	170,118		151,053
Deferred income tax assets:
Pension and other employee benefits	3,711		4,698
Environmental costs	1,710		1,744
Net operating loss carryforwards	2,010		1,625
Self-insurance	151		164
Storm reserve liability	—		717
Other	5,716		6,255
Total deferred income tax assets	13,298		15,203
Deferred Income Taxes Per Consolidated Balance Sheets	$	156,820	$	135,850

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2018

Line of Credit Facility [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

The following table summarizes our shelf agreements borrowing information at December 31, 2018:

(in thousands)	Total Borrowing Capacity		Less Amount of Debt Issued			Less Unfunded Commitments			Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement	$	220,000	$	(70,000	)	$	(100,000	)	$	50,000
MetLife Shelf Agreement	150,000		—			—			150,000
NYL Shelf Agreement	150,000		(100,000		)	—			50,000
Total	$	520,000	$	(170,000	)	$	(100,000	)	$	250,000

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	As of December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,986		$	7,982
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	4,000			6,000
5.93% note, due October 31, 2023	15,000			18,000
5.68% note, due June 30, 2026	23,200			26,100
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			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			—
3.58% note, due November 30, 2038	50,000			—
Term Note due January 21, 2020 (1)	30,000			—
Promissory notes	26			97
Capital lease obligations	1,310			2,070
Less: debt issuance costs	(567		)	(433		)
Total long-term debt	327,955			206,816
Less: current maturities	(11,935		)	(9,421		)
Total long-term debt, net of current maturities	$	316,020		$	197,395

⁽¹⁾ In December of 2018 we issued a $30.0 million unsecured Term Note through PNC Bank N.A. The maturity date of the Term Note is January 21, 2020. The Term Note bears interest at a rate equal to the one month LIBOR rate plus 75 basis points. The interest rate at December 31, 2018 was 3.23%

Schedule of Maturities of Long-term Debt [Table Text Block]

Annual maturities and principal repayments of long-term debt, excluding the capital lease obligation, are as follows:

Year	2019		2020		2021		2022		2023		Thereafter		Total
(in thousands)
Payments	$	10,626	$	45,600	$	13,600	$	25,100	$	20,600	$	211,700	$	327,226

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Short-Term Borrowing Short-Term Borrowing (Tables)

12 Months Ended

Dec. 31, 2018

Debt Disclosure [Abstract]

Schedule of Short-term Debt

				Outstanding borrowings at
(in thousands)	Total Facility		LIBOR Based Interest Rate	December 31, 2018		December 31, 2017		Available at December 31, 2018
Bank Credit Facility
Committed revolving credit facility A	$	55,000	plus 1.00 percent	$	25,000	$	55,000	$	30,000
Committed revolving credit facility B	30,000		plus 1.00 percent	15,431		20,500		14,569
Short-term revolving credit note C	50,000		plus 0.80 percent	50,000		50,000		—
Committed revolving credit facility D	45,000		plus 0.85 percent	34,672		40,171		10,328
Committed revolving credit facility E	40,000		plus 0.85 percent	40,000		—		—
Committed revolving credit facility F(2)	150,000		plus up to 1.25 percent	125,000		75,000		25,000
Total short term credit facilities	$	370,000		$	290,103	$	240,671	$	79,897
Book overdrafts(1)				4,355		10,298
Total short-term borrowing				$	294,458	$	250,969

.

⁽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 $200.0 million.

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Lease Obligations Lease Obligations (Tables)

12 Months Ended

Dec. 31, 2018

Leases [Abstract]

Schedule of Future Minimum Lease Payments for Capital Leases [Table Text Block]

As of December 31, 2018, future minimum payments under our current lease agreements are as follows:

Year(s)	2019	2020	2021	2022	2023	Thereafter	Total
(in thousands)
Expected payments	$2,349	$1,998	$1,761	$1,689	$1,642	$5,398	$14,837

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Stockholders' Equity (Tables)

12 Months Ended

Dec. 31, 2018

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

The following table present the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2018 and 2017. All amounts in the following tables are presented net of tax.

	Defined Benefit Pension and Postretirement Plan Items			Commodity Contracts Cash Flow Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income before reclassifications	281			159			440
Amounts reclassified from accumulated other comprehensive income/(loss)	336			(170		)	166
Net current-period other comprehensive income/(loss)	617			(11		)	606
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	)

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, 2018, 2017 and 2016. 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)	2018			2017			2016
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	77		$	77		$	77
Net gain (1)	(579		)	(636		)	(871		)
Total before income taxes	(502		)	(559		)	(794		)
Income tax benefit	63			223			320
Net of tax	$	(439	)	$	(336	)	$	(474	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(647	)	$	1,607		$	(322	)
Natural gas swaps (2)	197			(822		)	—
Natural gas futures (2)	(2,010		)	(456		)	345
Total before income taxes	(2,460		)	329			23
Income tax impact	701			(159		)	(3		)
Net of tax	$	(1,759	)	$	170		$	20
Total reclassifications for the period	$	(2,198	)	$	(166	)	$	(454	)

⁽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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Employee Benefit Plans (Tables)

12 Months Ended

Dec. 31, 2018

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, 2018, 2017 and 2016:

	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2018		2017		2016		2018		2017		2016
Asset Category
Equity securities	49.02	%	52.70	%	52.93	%	50.04	%	55.17	%	53.18	%
Debt securities	40.98	%	37.79	%	37.64	%	41.06	%	36.56	%	37.74	%
Other	10.00	%	9.51	%	9.43	%	8.90	%	8.27	%	9.08	%
Total	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%	100.00	%

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:

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, 2018 and 2017, 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, 2018								At December 31, 2017
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)	$	3,399	$	—	$	—	$	3,399	$	4,245	$	—	$	—	$	4,245
U.S. Mid Cap (1)	1,478		—		—		1,478		1,775		—		—		1,775
U.S. Small Cap (1)	670		—		—		670		918		—		—		918
International (2)	9,226		—		—		9,226		11,916		—		—		11,916
Alternative Strategies (3)	5,726		—		—		5,726		5,528		—		—		5,528
	20,499		—		—		20,499		24,382		—		—		24,382
Mutual Funds - Debt securities
Fixed income (4)	18,630		—		—		18,630		18,454		—		—		18,454
High Yield (4)	2,818		—		—		2,818		2,772		—		—		2,772
	21,448		—		—		21,448		21,226		—		—		21,226
Mutual Funds - Other
Commodities (5)	1,902		—		—		1,902		2,154		—		—		2,154
Real Estate (6)	2,216		—		—		2,216		2,300		—		—		2,300
Guaranteed deposit (7)	—		—		627		627		—		—		436		436
	4,118		—		627		4,745		4,454		—		436		4,890
Total Pension Plan Assets in fair value hierarchy	$	46,065	$	—	$	627	46,692		$	50,062	$	—	$	436	50,498
Investments measured at net asset value (8)							5,558								7,248
Total Pension Plan Assets							$	52,250							$	57,746

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, 2018 and 2017:

	For the Year Ended December 31,
	2018			2017
(in thousands)
Balance, beginning of year	$	436		$	498
Purchases	1,674			2,271
Transfers in	2,375			1,743
Disbursements	(3,872		)	(4,101		)
Investment income	14			25
Balance, end of year	$	627		$	436

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, 2018:

(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(524	)	$	—		$	(524	)
Net loss (gain)	3,865		18,544		559		578			(79		)	23,467
Total	$	3,865	$	18,544	$	559	$	54		$	(79	)	$	22,943
Accumulated other comprehensive loss (gain) pre-tax(1)	$	3,865	$	3,523	$	559	$	54		$	(15	)	$	7,986
Post-merger regulatory asset	—		15,021		—		—			(64		)	14,957
Subtotal	3,865		18,544		559		54			(79		)	22,943
Pre-merger regulatory asset	—		543		—		—			14			557
Total unrecognized cost	$	3,865	$	19,087	$	559	$	54		$	(65	)	$	23,500

⁽¹⁾ The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2018 is net of income tax benefits of $2.1 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)
2019	$	528	$	3,091	$	383	$	96	$	94
2020	$	529	$	3,221	$	150	$	85	$	87
2021	$	736	$	3,299	$	148	$	82	$	91
2022	$	595	$	3,485	$	147	$	81	$	93
2023	$	1,244	$	3,558	$	145	$	64	$	80
Years 2024 through 2028	$	3,866	$	18,570	$	744	$	275	$	402

⁽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

Component of Net Periodic Pension Cost (Benefit)

	Chesapeake Pension Plan									FPU Pension Plan									Chesapeake SERP
For the Years Ended December 31,	2018			2017			2016			2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic pension cost:
Interest cost	$	384		$	402		$	421		$	2,339		$	2,482		$	2,525		$	83		$	89		$	91
Expected return on assets	(542		)	(495		)	(501		)	(3,091		)	(2,779		)	(2,702		)	—			—
Amortization of actuarial loss	343			399			459			404			513			519			101			87			87
Settlement expense	—			—			161			—			—			—
Net periodic pension cost(1)	185			306			540			(348		)	216			342			184			176			178
Amortization of pre-merger regulatory asset	—			—			—			761			761			761			—			—			—
Total periodic cost	$	185		$	306		$	540		$	413		$	977		$	1,103		$	184		$	176		$	178
Assumptions:
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%	3.50		%	3.75		%	3.75		%
Expected return on plan assets	6.00		%	6.00		%	6.00		%	6.50		%	6.50		%	6.50		%	—		%	—		%	—		%

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following schedule sets forth the funded status at December 31, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017 and 2016 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP
At December 31,	2018			2017			2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	11,443		$	11,355		$	64,664		$	63,832		$	2,428		$	2,428
Interest cost	384			402			2,339			2,482			83			89
Actuarial loss (gain)	(610		)	454			(4,739		)	1,199			(74		)	63
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Benefit obligation — end of year	10,712			11,443			59,377			64,664			2,285			2,428
Change in plan assets:
Fair value of plan assets — beginning of year	9,350			8,668			48,396			43,272			—			—
Actual return on plan assets	(647		)	1,144			(3,113		)	6,025			—			—
Employer contributions	451			306			1,205			1,948			152			152
Benefits paid	(505		)	(768		)	(2,887		)	(2,849		)	(152		)	(152		)
Fair value of plan assets — end of year	8,649			9,350			43,601			48,396			—			—
Reconciliation:
Funded status	(2,063		)	(2,093		)	(15,776		)	(16,268		)	(2,285		)	(2,428		)
Accrued pension cost	$	(2,063	)	$	(2,093	)	$	(15,776	)	$	(16,268	)	$	(2,285	)	$	(2,428	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%	4.00		%	3.50		%
Expected return on plan assets	6.00		%	6.00		%	6.50		%	6.50		%	—		%	—		%

Other Postretirement Benefit Plans

Component of Net Periodic Pension Cost (Benefit)

Net periodic postretirement benefit costs for 2018, 2017, and 2016 include the following components:

	Chesapeake Postretirement Plan									FPU Medical Plan
For the Years Ended December 31,	2018			2017			2016			2018			2017			2016
(in thousands)
Components of net periodic postretirement cost:
Interest cost	$	38		$	41		$	43		$	47		$	50		$	55
Amortization of actuarial loss	58			53			64			—			—			—
Amortization of prior service cost (credit)	(77		)	(77		)	(77		)	—			—			—
Net periodic cost	19			17			30			47			50			55
Amortization of pre-merger regulatory asset	—			—			—			8			8			8
Total periodic cost(1)	$	19		$	17		$	30		$	55		$	58		$	63
Assumptions
Discount rate	3.50		%	3.75		%	3.75		%	3.75		%	4.00		%	4.00		%

Schedule of Funded Status of Benefit Obligation and Plan Assets

The following table sets forth the funded status at December 31, 2018 and 2017 and the net periodic cost for the years ended December 31, 2018, 2017, and 2016:

	Chesapeake Postretirement Plan						FPU Medical Plan
At December 31,	2018			2017			2018			2017
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,128		$	1,132		$	1,287		$	1,349
Interest cost	38			41			47			50
Plan participants contributions	136			118			41			48
Actuarial loss (gain)	(131		)	72			(89		)	(48		)
Benefits paid	(169		)	(235		)	(99		)	(112		)
Benefit obligation — end of year	1,002			1,128			1,187			1,287
Change in plan assets:
Fair value of plan assets — beginning of year	—			—			—			—
Employer contributions(1)	33			117			58			64
Plan participants contributions	136			118			41			48
Benefits paid	(169		)	(235		)	(99		)	(112		)
Fair value of plan assets — end of year	—			—			—			—
Reconciliation:
Funded status	(1,002		)	(1,128		)	(1,187		)	(1,287		)
Accrued postretirement cost	$	(1,002	)	$	(1,128	)	$	(1,187	)	$	(1,287	)
Assumptions:
Discount rate	4.00		%	3.50		%	4.25		%	3.75		%

⁽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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Share-Based Compensation Plans (Tables)

12 Months Ended

Dec. 31, 2018

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,
	2018		2017		2016
(amounts except shares, in thousands)
Shares withheld to satisfy tax obligations	10,436		10,269		12,031
Amounts remitted to tax authorities to satisfy obligations	$	1,210	$	692	$	770
Tax benefit associated with settlement of share based payments	$	—	$	349	285

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, 2018, 2017 and 2016:

	For the Year Ended December 31,
	2018			2017			2016
(in thousands)
Awards to non-employee directors	$	539		$	540		$	580
Awards to key employees	2,871			1,950			1,787
Total compensation expense	3,410			2,490			2,367
Less: tax benefit	(934		)	(1,003		)	(952		)
Share-based compensation amounts included in net income	$	2,476		$	1,487		$	1,415

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, 2016	115,091		$	51.85
Granted	52,355		$	63.42
Vested	(32,926	)	$	38.88
Expired	(1,878	)	$	39.97
Outstanding — December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding — December 31, 2018	131,741		$	67.24

⁽¹⁾ Includes 2,569 shares that were forfeited

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

12 Months Ended

Dec. 31, 2018

Regulated Operations [Abstract]

Schedule of Regulatory Assets [Table Text Block]

At December 31, 2018 and 2017, 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,
	2018		2017
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	4,631	$	9,869
Under-recovered GRIP revenue (2)	165		164
Deferred postretirement benefits (3)	15,517		15,498
Deferred conversion and development costs (1)	16,727		11,735
Environmental regulatory assets and expenditures (4)	2,731		3,222
Acquisition adjustment (5)	33,255		39,992
Loss on reacquired debt (6)	942		1,031
Other	3,250		4,994
Total Regulatory Assets	$	77,218	$	86,505
Regulatory Liabilities
Self-insurance (7)	$	947	$	1,013
Over-recovered purchased fuel and conservation cost recovery (1)	5,443		2,048
Over-recovered GRIP revenue (2)	1,563		2,245
Storm reserve (7)	677		669
Accrued asset removal cost (8)	42,401		40,948
Deferred income taxes due to rate change (9)	91,162		98,492
Other	729		2,048
Total Regulatory Liabilities	$	142,922	$	147,463

⁽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. 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. Included in these amounts are $543,000 of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including a gross up for income tax, because it is not tax deductible, and $746,000 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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Rates and Other Regulatory Activities Summary of Effects of Tax Reform Impact on Regulated Businesses (Tables)

12 Months Ended

Dec. 31, 2018

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 Excess Accumulated Deferred Income Taxes ("ADIT")		Status of Customer Rate impact related to 35 percent to 21 percent rate change
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing	Implemented one-time bill credit (totaling $900,000) in April 2018 - Customer rates adjusted in April, 2018
Delaware Division (Delaware PSC)	$13,262	In January 2019, PSC approved amortization of ADIT and corresponding customer rate reductions effective March 1, 2019.	Customer rates to be adjusted March 1, 2019. One-time bill credit to be implemented during the second quarter.
Maryland Division (Maryland PSC)	$4,211	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $365,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Sandpiper Energy (Maryland PSC)	$3,815	In May 2018, PSC approved amortization of ADIT and corresponding customer rate reductions commenced	Implemented one-time bill credit (totaling $608,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,471	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Natural Gas (includes FPU, Fort Meade, and Indiantown) (Florida PSC)	$19,505	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019	PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019
		The order states that the net ADIT liability would be amortized and retained by the Company pursuant to the prescribed schedule	No one-time bill credit or adjustment in rates would be applied; the tax savings arising from the TCJA rate reduction would be retained
FPU Electric (Florida PSC)	$5,995	In January 2019, PSC approved 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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Environmental Commitments and Contingencies Environmental Remediation Status (Tables)

12 Months Ended

Dec. 31, 2018

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 Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford (Florida)	In March 2018, the 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. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.
Seaford (Delaware)	Proposed plan for implementation approved by Delaware Department of Natural Resources and Environmental Control in July 2017. Site assessment is ongoing.	$273,000 to $465,000.
Cambridge (Maryland)	Currently in discussions with MDE.	Unable to estimate.

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Other Commitments and Contingencies Other Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2018

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	2019		2020-2021		2022-2023		Beyond 2023		Total
(in thousands)
Purchase Obligations	$	158,544	$	74,970	$	42,279	$	129,019	$	404,812

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Quarterly Financial Data (Tables)

12 Months Ended

Dec. 31, 2018

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)
2018(1)
Operating Revenues	$	239,356	$	136,664	$	140,279	$	201,190
Operating Income	$	40,406	$	13,248	$	12,036	$	28,930
Net Income	$	26,855	$	6,387	$	5,538	$	17,801
Earnings per share:
Basic	$	1.64	$	0.39	$	0.34	$	1.09
Diluted	$	1.64	$	0.39	$	0.34	$	1.08
2017(1)
Operating Revenues	$	185,160	$	125,084	$	126,936	$	180,403
Operating Income	$	35,099	$	14,061	$	14,632	$	23,628
Net Income	$	19,144	$	6,046	$	6,833	$	26,101
Earnings per share:
Basic	$	1.17	$	0.37	$	0.42	$	1.60
Diluted	$	1.17	$	0.37	$	0.42	$	1.59

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

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Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Public Utilities, Allowance for Funds Used During Construction, Description	1869586
Property, plant and equipment
Total property, plant and equipment	$ 1,569,683	$ 1,312,117
Less: Accumulated depreciation and amortization	(294,295)	(270,599)
Plus: Construction work in progress	108,584	84,509
Net property, plant and equipment	1,383,972	1,126,027
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	657,630	589,149
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	537,654	384,360
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	70,225	66,037
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	102,133	100,227
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	123,632	108,177
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	35,239	35,239
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	7,240	0
Other unregulated energy | Other [Member]
Property, plant and equipment
Total property, plant and equipment	1,346	1,229
Other
Property, plant and equipment
Total property, plant and equipment	$ 34,584	$ 27,699

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands	12 Months Ended
	Dec. 31, 2018 USD ($) mi	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	May 31, 2016 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Number of Utilities that do not have cost recovery mechanism	2
Delay of Revenue Recognition Due To Implementation of New Standard	$ (407)
New Accounting Pronouncement or Change in Accounting Principle, Cumulative Effect of Change on Equity or Net Assets	$ (1,800)
Maturity Period To Be Considered Cash Equivalents	3
Contributions or Advances in Aid of Construction	$ 2,800	$ 2,100	$ 1,000
Property, plant and equipment in service assets under operating lease contract	1,400
Annual revenue from operating lease	$ 264
Operating lease term	20 years
Accumulated depreciation, plant in service assets under operating lease	$ 720	652
Capital Leased Assets, Net	1,300	2,100
Capital Leased Assets, Noncurrent, Fair Value Disclosure	7,816	7,126
Ground Leases, Accumulated Amortization	6,506	5,056
Amortization of Leased Asset	1,451	1,401	1,353
Net property, plant and equipment	1,383,972	1,126,027
Accumulated depreciation	294,295	270,599
Depreciation and accretion reported in operations expenses	8,500	8,100	7,300
Gain from a settlement	(130)	(130)	$ (130)
Gain Contingency, Unrecorded Amount				$ 650
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	$ 6,670
Length of pipeline | mi	16
Ownership interest	45.00%
Accumulated depreciation	$ 1,363	$ 1,251
Minimum [Member]
Summary Of Accounting Policies [Line Items]
Operating Lease, Liability	11,000
Operating Lease, Right-of-Use Asset	11,000
Maximum
Summary Of Accounting Policies [Line Items]
Operating Lease, Liability	13,000
Operating Lease, Right-of-Use Asset	$ 13,000

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Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	2.90%	2.90%	2.90%
Natural gas transmission | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.70%	2.80%	2.70%
Natural gas transmission | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.30%	3.50%	3.90%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	3.40%	3.40%	3.50%

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Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2018
Minimum | Propane Distribution Mains [Member]
Useful Life of Assets	10 years
Minimum | Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	10 years
Minimum | Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	5 years
Minimum | Meters And Meter Installations [Member]
Useful Life of Assets	5 years
Minimum | Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	5 years
Minimum | Natural gas processing equipment [Member]
Useful Life of Assets	20 years
Minimum | Office Furniture And Equipment [Member]
Useful Life of Assets	3 years
Minimum | Transportation Equipment [Member]
Useful Life of Assets	4 years
Minimum | Structures And Improvements [Member]
Useful Life of Assets	5 years
Maximum | Propane Distribution Mains [Member]
Useful Life of Assets	37 years
Maximum | Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	40 years
Maximum | Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	33 years
Maximum | Meters And Meter Installations [Member]
Useful Life of Assets	33 years
Maximum | Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	37 years
Maximum | Natural gas pipelines [Member]
Useful Life of Assets	45 years
Maximum | Natural gas processing equipment [Member]
Useful Life of Assets	25 years
Maximum | Office Furniture And Equipment [Member]
Useful Life of Assets	10 years
Maximum | Transportation Equipment [Member]
Useful Life of Assets	20 years
Maximum | Structures And Improvements [Member]
Useful Life of Assets	45 years

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Summary of Significant Accounting Policies Capital Leased Asset (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Capital Leased Assets [Line Items]
Amortization of Leased Asset	$ 1,451	$ 1,401	$ 1,353
Capital Leased Assets, Noncurrent, Fair Value Disclosure	7,816	7,126
Ground Leases, Accumulated Amortization	6,506	5,056
Capital Leases, Balance Sheet, Assets by Major Class, Net	$ 1,300	$ 2,100

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Summary of Significant Accounting Policies Effects of New Accounting Pronouncements (Details) - USD ($) $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Regulated Energy									$ 345,281	$ 326,310	$ 305,689
Accrued revenue	$ 27,499				$ 22,279				27,499	22,279
Receivables and other deferred charges	6,985				3,699				6,985	3,699
Retained earnings	261,530				229,141				261,530	229,141
Regulated Energy cost of sales									121,828	118,769	109,609
Income Tax Expense (Benefit)									20,994	14,309	28,341
Depreciation and amortization									40,802	36,599	32,159
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									77,574	72,433	73,016
Net Income	17,801	$ 5,538	$ 6,387	$ 26,855	$ 26,101	$ 6,833	$ 6,046	$ 19,144	56,580	$ 58,124	$ 44,675
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Regulated Energy									346,289
Accrued revenue	29,461								29,461
Receivables and other deferred charges	6,816								6,816
Retained earnings	263,323								263,323
Regulated Energy cost of sales									122,463
Income Tax Expense (Benefit)									21,106
Depreciation and amortization									40,767
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									77,981
Net Income									56,875
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Accrued revenue	(1,962)								(1,962)
Receivables and other deferred charges	169								169
Retained earnings	$ (1,793)								(1,793)
Deferred Revenue, Period Increase (Decrease)									(1,008)
Regulated Energy cost of sales									(635)
Income Tax Expense (Benefit)									(112)
Depreciation and amortization									35
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest									(407)
Net Income									$ (295)

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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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Calculation of Basic Earnings Per Share:
Net Income	$ 17,801	$ 5,538	$ 6,387	$ 26,855	$ 26,101	$ 6,833	$ 6,046	$ 19,144	$ 56,580	$ 58,124	$ 44,675
Weighted shares outstanding - Basic (in shares)									16,369,616	16,336,789	15,570,539
Basic Earnings Per Share (in usd per share)	$ 1.09	$ 0.34	$ 0.39	$ 1.64	$ 1.60	$ 0.42	$ 0.37	$ 1.17	$ 3.46	$ 3.56	$ 2.87
Calculation of Diluted Earnings Per Share:
Net Income	$ 17,801	$ 5,538	$ 6,387	$ 26,855	$ 26,101	$ 6,833	$ 6,046	$ 19,144	$ 56,580	$ 58,124	$ 44,675
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									16,369,616	16,336,789	15,570,539
Share-based Compensation									50,254	46,563	42,552
Adjusted denominator — Diluted									16,419,870	16,383,352	15,613,091
Diluted Earnings Per Share (in usd per share)	$ 1.08	$ 0.34	$ 0.39	$ 1.64	$ 1.59	$ 0.42	$ 0.37	$ 1.17	$ 3.45	$ 3.55	$ 2.86

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Acquisitions - Additional Information (Detail)		3 Months Ended								12 Months Ended
	Aug. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Cash paid for acquisition										$ 16,654,000	$ 11,945,000	$ 0
Revenues		$ 201,190,000	$ 140,279,000	$ 136,664,000	$ 239,356,000	$ 180,403,000	$ 126,936,000	$ 125,084,000	$ 185,160,000	717,489,000	617,583,000	498,860,000
Net Income		17,801,000	$ 5,538,000	$ 6,387,000	$ 26,855,000	$ 26,101,000	$ 6,833,000	$ 6,046,000	$ 19,144,000	56,580,000	$ 58,124,000	$ 44,675,000
Marlin and Ohl [Member]
Business Combination, Consideration Transferred										18,400,000
ARM Energy [Member]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized										2,500,000
Business Combination, Liabilities Arising from Contingencies, Amount Recognized		$ 2,500,000.0								$ 2,500,000.0
Chipola & Central Gas [Member]
Number of customers acquired through acquisition										1,125
Unregulated Energy | Marlin [Member]
Goodwill, Acquired During Period										$ 4,800,000
Unregulated Energy | Ohl [Member]
Number of customers acquired through acquisition										2,500
Goodwill, Acquired During Period										$ 1,500,000
Unregulated Energy | ARM [Member]
Goodwill, Acquired During Period	$ 4,300,000

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Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 83,214	$ 74,962
Contract with Customer, Asset, Net, Noncurrent	2,614	1,270
Contract with Customer, Liability, Current	480	$ 407
Increase (Decrease) in Receivables	8,252
Increase (Decrease) in Other Noncurrent Assets	1,344
Increase (Decrease) in Other Current Liabilities	73
Contract with Customer, Liability, Revenue Recognized	$ 697

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Revenue Recognition Disaggregation of Revenue (Details) - USD ($)	3 Months Ended								12 Months Ended
	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disaggregation of Revenue [Line Items]
Revenues	$ 201,190,000	$ 140,279,000	$ 136,664,000	$ 239,356,000	$ 180,403,000	$ 126,936,000	$ 125,084,000	$ 185,160,000	$ 717,489,000	$ 617,583,000	$ 498,860,000
Revenue from Contract with Customer, Excluding Assessed Tax									717,489,000
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									2,610,000
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									111,582,000
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									123,603,000
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(99,302,000)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									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									302,860,000
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									76,175,000
Regulated Energy | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(33,754,000)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									420,617,000
Unregulated Energy | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									1,957,000
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									35,407,000
Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									123,603,000
Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									258,834,000
Unregulated Energy | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(16,486,000)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(48,409,000)
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(48,409,000)
Other Segments And Intersegments Eliminations [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									653,000
Other Segments And Intersegments Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(49,062,000)
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(96,692,000)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues									236,000
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues									334,000
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									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									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									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									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									24,172,000
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									22,088,000
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									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									64,248,000
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									11,927,000
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									17,302,000
Delmarva Peninsula Propane Delivery [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									102,321,000
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									21,282,000
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									121,000
PESCO [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									258,713,000
Eliminations [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									(33,754,000)
Eliminations [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax									$ (14,529,000)

XML

Revenue Recognition Remaining performance obligations (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 38,505
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	4,109
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	8,886
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | FPU Electric Distribution [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	297
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	51,797
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	36,768
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	3,586
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	4,702
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	297
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	45,353
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	33,510
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	3,358
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	1,728
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	297
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	38,893
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	26,566
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	3,320
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	23
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	109
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	30,018
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	21,146
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	2,924
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 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	0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	24,070
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	212,620
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	30,826
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | PESCO - Natural Gas Marketing [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	0
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, 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	0
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	$ 243,446

XML

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands		3 Months Ended								12 Months Ended
		Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		$ 201,190	$ 140,279	$ 136,664	$ 239,356	$ 180,403	$ 126,936	$ 125,084	$ 185,160	$ 717,489	$ 617,583	$ 498,860
Intersegment Revenues (1)
Total intersegment revenues		201,190	140,279	136,664	239,356	180,403	126,936	125,084	185,160	717,489	617,583	498,860
Operating Income
Operating Income		28,930	12,036	13,248	40,406	23,628	14,632	14,061	35,099	94,620	87,420	85,983
Other income										(615)	(2,342)	(2,328)
Interest charges										16,431	12,645	10,639
Income Before Income taxes										77,574	72,433	73,016
Income taxes										20,994	14,309	28,341
Net Income		17,801	$ 5,538	$ 6,387	$ 26,855	26,101	$ 6,833	$ 6,046	$ 19,144	56,580	58,124	44,675
Depreciation and Amortization
Total depreciation and amortization										40,802	36,599	32,159
Identifiable Assets
Total identifiable assets		1,693,671				1,414,934				1,693,671	1,414,934
Regulated Energy
Operating Income
Operating Income										79,215	74,584	71,515
Depreciation and Amortization
Total depreciation and amortization										31,876	28,554	25,677
Payments to Acquire Productive Assets										235,912	159,011	139,994
Identifiable Assets
Total identifiable assets		1,345,805				1,121,673				1,345,805	1,121,673
Unregulated Energy
Operating Income
Operating Income										16,901	12,631	14,066
Depreciation and Amortization
Total depreciation and amortization										8,845	7,954	6,386
Payments to Acquire Productive Assets										38,700	26,190	23,984
Identifiable Assets
Total identifiable assets		306,045				259,041				306,045	259,041
Other
Operating Income
Operating Income										(1,496)	205	402
Depreciation and Amortization
Payments to Acquire Productive Assets										8,364	5,902	5,398
Identifiable Assets
Total identifiable assets		$ 41,821				$ 34,220				41,821	34,220
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization										81	91	96
Total for Segments [Member]
Depreciation and Amortization
Payments to Acquire Productive Assets										282,976	191,103	169,376
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										717,489	617,583	498,860
Intersegment Revenues (1)
Total intersegment revenues										717,489	617,583	498,860
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										332,749	316,971	302,402
Intersegment Revenues (1)
Total intersegment revenues										332,749	316,971	302,402
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues										384,740	300,612	196,458
Intersegment Revenues (1)
Total intersegment revenues										384,740	300,612	196,458
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									49,062	34,096	11,488
Intersegment Revenues (1)
Total intersegment revenues	[1]									49,062	34,096	11,488
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									9,339	12,532	3,287
Intersegment Revenues (1)
Total intersegment revenues	[1]									9,339	12,532	3,287
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									23,983	35,877	7,321
Intersegment Revenues (1)
Total intersegment revenues	[1]									23,983	35,877	7,321
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]									774	653	880
Intersegment Revenues (1)
Total intersegment revenues	[1]									$ 774	$ 653	$ 880

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

XML

Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 16,740	$ 12,420	$ 10,320
Cash paid for income taxes	$ 477	$ (4,114)	$ (5,308)

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Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	$ 39,402	$ 15,457	$ 9,791
Retirement Savings Plan	0	0	777
Performance Incentive Plan	2,006	1,127	1,027
Capital Lease Obligation	$ 1,310	$ 2,070	$ 3,471

XML

Derivative Instruments - Additional Information (Detail) $ in Thousands, gal in Millions, Mcf in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) gal Mcf	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 212	$ 0
Other Receivables from Broker-Dealers and Clearing Organizations	2,810	6,300
Energy Marketing Contract Liabilities, Current	14,871	6,247
Accounts Payable Subject To Master Netting Arrangement	3,834	2,391
Derivative assets, at fair value	13,165	1,286
Unrealized Gain (Loss) on Derivatives	(7,703)	(3,195)	$ (45)
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 8,705
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	3.8
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative assets, at fair value	$ 4,024
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value		13
Not Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	4,562	5,776
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative assets, at fair value	9,059	92
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Put Option
Derivative [Line Items]
Derivative assets, at fair value	71
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	11	1,181
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	0	469
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 1,235
Sharp Energy Inc [Member] | Put Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	0.3
PESCO [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months	$ 1,534
PESCO [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	14.4
2017 [Member] | Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 1,604	2
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	532	(1,476)	222
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	200	986	0
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(2,773)	487	1,016
Cost of Sales [Member] | Not Designated as Hedging Instrument [Member] | Future [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives	(3,189)	(3,633)	(541)
Cost of Sales [Member] | Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(13)	8	7
Cost of Sales [Member] | Derivatives designated as fair value hedges | Natural Gas Swaps [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			0
Cost of Sales [Member] | Derivatives designated as fair value hedges | Future [Member]
Derivative [Line Items]
Unrealized Gain (Loss) on Derivatives			345
Cost of Sales [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(647)	1,607	(364)
Inventories [Member] | Not Designated as Hedging Instrument [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 0	$ 1	$ 0

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 13,165	$ 1,286
Energy Marketing Contract Liabilities, Current	14,871	6,247
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	8,705
Not Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	4,562	5,776
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		13
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	4,024
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	0	469
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	11	1,181
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Put Option
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	71
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	9,059	92
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	$ 1,604	$ 2

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current		$ 14,871	$ 6,247
Gain (Loss) on derivatives		(7,703)	(3,195)	$ (45)
Revenue | Derivatives not designated as hedging instruments | Forward Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]	0	112	(546)
Cost of Sales | Derivatives not designated as hedging instruments | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(13)	8	7
Cost of Sales | Derivatives not designated as hedging instruments | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(3,189)	(3,633)	(541)
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	(9)	49
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(647)	1,607	(364)
Cost of Sales | Derivatives designated as fair value hedges | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives				345
Propane Inventory | Derivatives designated as fair value hedges | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		0	0	(233)
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		532	(1,476)	222
Other Comprehensive Income (Loss) | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(2,773)	487	$ 1,016
Mark To Market Energy Liabilities [Member] | Derivatives not designated as hedging instruments | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current		4,562	5,776
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		0	469
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		$ 1,604	$ 2

[1] All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

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Derivative Instruments Accounts Receivable and Payable on a Gross and Net Basis (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 3,834	$ 2,391
Accounts Payable Subject To Master Netting Arrangement	3,834	2,391
Net [Member]
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	8,534	5,892
Accounts Payable Subject To Master Netting Arrangement	20,907	14,252
Gross [Member]
Offsetting Liabilities [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	12,368	8,283
Accounts Payable Subject To Master Netting Arrangement	$ 24,741	$ 16,643

XML

Derivative Instruments Volume of Derivative Activity (Details) gal in Millions, Mcf in Millions	12 Months Ended
	Dec. 31, 2018 gal Mcf
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	3.8
Sharp Energy Inc [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	9.7
Sharp Energy Inc [Member] | Put Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	0.3

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Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2018	Dec. 31, 2017
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 327.2	$ 205.2
Fair value of long-term debt	$ 323.8	$ 215.4

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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, 2018	Dec. 31, 2017
Assets:
Investments	$ 6,711	$ 6,756
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	6,025	6,108
Fair Value, Inputs, Level 1 [Member] | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Significant Other Observable Inputs (Level 2)
Assets:
Assets, Fair Value Disclosure	13,165	1,286
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	14,871	6,247
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	686	648
Significant Unobservable Inputs (Level 3) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	22	22
Equity Securities [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Equity Securities [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Guaranteed Income Fund [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	686	648
Investments - other | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	6,003	6,086
Investments - other | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments - other | Significant Unobservable Inputs (Level 3)
Assets:
Investments	0	0
Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	6,025	6,108
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	686	648
Mark-to-market energy assets, including put option | Fair Value, Inputs, Level 1 [Member]
Assets:
Mark-to-market energy assets, including put option	0	0
Mark-to-market energy assets, including put option | Significant Other Observable Inputs (Level 2)
Assets:
Mark-to-market energy assets, including put option	13,165	1,286
Mark-to-market energy assets, including put option | Significant Unobservable Inputs (Level 3)
Assets:
Mark-to-market energy assets, including put option	0	0
Fair Value
Assets:
Assets, Fair Value Disclosure	19,876	8,042
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	14,871	6,247
Fair Value | Equity Securities [Member]
Assets:
Investments	22	22
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	686	648
Fair Value | Investments - other
Assets:
Investments	6,003	6,086
Fair Value | Investments [Member]
Assets:
Investments	6,711	6,756
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 13,165	$ 1,286

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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, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Purchases	$ 68	$ 79
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	648	561
Purchases and adjustments	(41)	(53)
Investment income	11	61
Ending Balance	$ 686	$ 648

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Investments - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Investments [Abstract]
Unrealized gain, net of other expenses	$ (428)	$ 1,000	$ 379

XML

Investments - Schedule of Investment (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Investment [Line Items]
Investments, at fair value	$ 6,711	$ 6,756
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investment [Line Items]
Investments, at fair value	6,689	6,734
Fair Value, Inputs, Level 1 [Member] | Investments in equity securities
Investment [Line Items]
Investments, at fair value	$ 22	$ 22

XML

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($)		12 Months Ended
	Aug. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill		$ 25,837,000	$ 19,604,000
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months		1,139,000
Amortization of intangible assets		818,000	$ 537,000	$ 380,000
Finite-Lived Intangible Assets, Amortization Expense, Year Four		820,000
Amortization of intangible assets, 2019		1,139,102
Amortization of intangible assets, 2020		1,074,245
Amortization of intangible assets, 2022		$ 813,000
ARM [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill, Acquired During Period	$ 4,300,000
Customer list | Minimum
Goodwill [Line Items]
Amortized period of acquired intangible assets		5 years
Customer list | Maximum
Goodwill [Line Items]
Amortized period of acquired intangible assets		41 years

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Goodwill [Line Items]
Goodwill		$ 25,837	$ 19,604
Florida Natural Gas Distribution [Member] | Regulated Energy
Goodwill [Line Items]
Goodwill	[1]	3,353	3,353
Mid-Atlantic Propane Operations [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		2,147	674
Florida Propane Operations [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		1,188	1,188
Aspire Energy | Unregulated Energy
Goodwill [Line Items]
Goodwill		10,119	10,119
Marlin Gas Services [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		4,760	0
PESCO - Natural Gas Marketing [Member] | Unregulated Energy
Goodwill [Line Items]
Goodwill		$ 4,270	$ 4,270

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

XML

Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 10,272	$ 7,933
Accumulated Amortization	4,065	3,247
Customer list
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	7,757	7,393
Accumulated Amortization	3,664	2,880
Non-Compete Agreements
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	2,245	270
Accumulated Amortization	202	175
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	270
Accumulated Amortization	$ 199	$ 192

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Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Operating Loss Carryforwards [Line Items]
Deferred tax asset related to state net operating loss carry-forwards	$ 1,586
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%	35.00%
State
Operating Loss Carryforwards [Line Items]
Federal net operating losses for income tax	$ 34,200

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Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Current Income Tax Expense
Federal		$ (845)	$ 2,803	$ (4,898)
State		660	492	2,053
Other		(47)	(71)	(71)
Total current income tax expense		(232)	3,224	(2,916)
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	21,226	11,085	31,257
Total Income Tax Expense		20,994	14,309	28,341
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		19,164	8,314	31,062
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		(1,435)	2,002	1,163
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		463	180	237
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense		(528)	(1,148)	(572)
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		(331)	193	(9)
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ 3,893	$ 1,544	$ (624)

[1] (1) Includes $3.5 million, $873,000 and $2.1 million of deferred state income taxes for the years 2018, 2017 and 2016, respectively.

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Reconciliation of Effective Income Tax Rates Continuing Operations
Federal income tax expense (1)	[1]	$ 16,291	$ 25,351	$ 22,759
State income taxes, net of federal benefit		4,088	1,894	3,422
ESOP dividend deduction		(158)	(257)	(264)
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount		0	(14,299)	0
Other		773	1,620	2,424
Total Income Tax Expense		$ 20,994	$ 14,309	$ 28,341
Effective Income Tax Rate (2)	[2]	27.06%	19.75%	38.81%

[1] Federal income taxes were calculated at 21 percent for 2018 and 35 percent for 2017 and 2016.

[2] Effective tax rate 2017 includes the impact of the revaluation of deferred tax assets and liabilities for our unregulated businesses due to implementation of the TCJA

XML

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 3,500	$ 900	$ 2,100
Deferred income tax liabilities:
Property, plant and equipment	153,423	133,581
Acquisition adjustment	8,896	9,323
Deferred gas costs	32	153
Deferred Income Tax Liability - Deferred Gas Costs	1,139	2,574
Deferred Income Tax Liability, Natural Gas Conversion Costs	3,987	2,760
Other	2,641	2,662
Total deferred income tax liabilities	170,118	151,053
Deferred income tax assets:
Pension and other employee benefits	3,711	4,698
Environmental costs	1,710	1,744
Net operating loss carryforwards	2,010	1,625
Self-insurance	151	164
Storm reserve liability	0	717
Other	5,716	6,255
Total deferred income tax assets	13,298	15,203
Deferred Income Tax Liabilities, Net	$ 156,820	$ 135,850

XML

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 3.5	$ 0.9	$ 2.1

XML

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%	35.00%

XML

Income Taxes Federal Tax Reform (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Federal Tax Reform
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%	35.00%
Effective Income Tax Rate Reconciliation, Change in Enacted Tax Rate, Amount	$ 0	$ (14,299)	$ 0

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Long-Term Debt - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 USD ($)
Debt Instrument [Line Items]
Long-term debt maturities repayment of principal in next twelve months	$ 10,600,000
Long-term debt maturities repayment of principal in year two	45,600,000
Long-term debt maturities repayment of principal in year three	13,600,000
Long-term debt maturities repayment of principal in year four	25,100,000
Long-term debt maturities repayment of principal in year five	20,600,000
Long-term debt maturities repayment of principal in year five thereafter	211,700,000
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	10.0
Cumulative consolidated net income base	$ 444,300,000
Cumulative net income with restrictions	201,500,000
Cumulative net income free of restrictions	242,800,000
Restricted net assets of consolidated subsidiaries	$ 42,200,000
Percentage of restricted net assets	8.00%
Term Note Due January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.23%
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
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	$ 155,834,240
Cumulative net income with restrictions	(37,600,000)
Cumulative net income free of restrictions	$ 118,200,000
Uncollateralized Senior Note Due On May 2 Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
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%
Uncollateralized Senior Note Due On Two Thousand Twenty Three [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Florida Public Utilities Company [Member]
Debt Instrument [Line Items]
Cumulative net income with restrictions	$ 2,500,000

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Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Long-term Debt	$ 327,200	$ 205,200
Capital lease obligation	1,310	2,070
Less: debt issuance costs	(567)	(433)
Long-term Debt and Capital Lease Obligations	327,955	206,816
Less: current maturities	(11,935)	(9,421)
Total long-term debt, net of current maturities	316,020	197,395
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term Debt	$ 7,986	7,982
Debt Instrument, Interest Rate, Stated Percentage	9.08%
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	$ 4,000	6,000
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	$ 15,000	18,000
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 23,200	26,100
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 7,000	7,000
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 20,000	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
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
Debt Instrument, Interest Rate, Stated Percentage	3.58%
Term Note Due January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term Debt	$ 30,000
Long-term Debt, Percentage Bearing Fixed Interest, Percentage Rate	0.75%
Debt Instrument, Interest Rate, Stated Percentage	3.23%
Promissory note
Debt Instrument [Line Items]
Long-term Debt	$ 26	$ 97

XML

Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2018
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
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

XML

Long-Term Debt Annual Maturities (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Twelve Months	$ 10,600
Long-term Debt, Maturities, Repayments of Principal in Year Two	45,600
Long-term Debt, Maturities, Repayments of Principal in Year Three	13,600
Long-term Debt, Maturities, Repayments of Principal in Year Four	25,100
Long-term Debt, Maturities, Repayments of Principal in Year Five	20,600
Long-term Debt, Maturities, Repayments of Principal after Year Five	211,700
Total Future Repayments	$ 327,226

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Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Line of Credit Facility [Line Items]
Long-term Debt	$ (327,200)	$ (205,200)
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	(70,000)
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
Debt Instrument, Unused Borrowing Capacity, Amount	50,000
Aggregate Shelf Agreements [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(170,000)
Aggregated Unfunded Commitments [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(100,000)
Uncollateralized Senior Note to be Issued in 2019 [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (100,000)
Debt Instrument, Interest Rate, Stated Percentage	3.98%
New York Life [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (100,000)
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Long-term Debt	(70,000)	$ (70,000)
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

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Short-Term Borrowing - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Oct. 08, 2015 USD ($)
Short-term Debt [Line Items]
Short-term borrowings	$ 294,458,000	$ 250,969,000
Line of Credit Facility, Aggregate Borrowing Capacity	$ 370,000,000
Number Of Unsecured Bank Credit Facilities	5
Number Of Financial Institutions With Bank Credit Facilities	4
Line Of Available Credit Facility Borrowing Capacity	$ 220,000,000
ParticipatingLendersInTheRevolver	5
Short-term Debt, Weighted Average Interest Rate, at Point in Time	3.4379%	2.4246%
Line of Credit Facility, Commitment Fee Amount	$ 93,300	$ 131,000	$ 145,000
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
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity	$ 350,000,000
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 1.00 percent
Line of Credit Facility, Aggregate Borrowing Capacity	$ 30,000,000
Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate plus 80 basis points
Line of Credit Facility, Aggregate Borrowing Capacity	$ 50,000,000
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate, plus 0.85 percent
Line of Credit Facility, Aggregate Borrowing Capacity	$ 45,000,000
Unsecured Debt [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Expiration Date	Oct. 31, 2019
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Expiration Date	Oct. 08, 2020

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Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 370,000
Long-term Line of Credit		290,103	$ 240,671
Line of Credit Facility, Remaining Borrowing Capacity		79,897
Bank Overdrafts	[1]	4,355	10,298
Short-term borrowing		294,458	250,969
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
Line of Credit Facility, Remaining Borrowing Capacity		$ 30,000
Debt Instrument, Description of Variable Rate Basis		LIBOR rate, plus 1.00 percent
Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 50,000
Long-term Line of Credit			50,000
Debt Instrument, Description of Variable Rate Basis		Lender's base rate plus 80 basis points
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		40,000	40,171
Line of Credit Facility, Remaining Borrowing Capacity		$ 10,328
Debt Instrument, Description of Variable Rate Basis		Lender's base rate, plus 0.85 percent
Committed Line of Credit Facility Five [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 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	[2]		75,000
Line of Credit Facility, Remaining Borrowing Capacity	[2]	$ 25,000
Debt Instrument, Description of Variable Rate Basis		LIBOR rate, plus 1.00 percent
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 30,000
Long-term Line of Credit			$ 20,500
Line of Credit Facility, Remaining Borrowing Capacity		$ 14,569
Debt Instrument, Description of Variable Rate Basis		LIBOR rate, plus 1.00 percent

[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 $200.0 million.

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Lease Obligations - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Subsequent Event [Line Items]
Rent expense related to operating leases	$ 3,800,000	$ 3,600,000	$ 2,500,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	2,300,000
Operating Leases, Future Minimum Payments, Due in Two Years	1,998,000
Operating Leases, Future Minimum Payments, Due in Three Years	1,800,000
Operating Leases, Future Minimum Payments, Due in Four Years	1,689,000
Operating Leases, Future Minimum Payments, Due in Five Years	1,642,000
Future minimum payments under current lease agreements, thereafter	5,400,000
Future minimum payments under current lease agreements, total	14,800,000
Capital Leases, Future Minimum Payments Due, Next Twelve Months	2,400,000		$ 1,500,000
Capital Leases, Future Minimum Payments Due in Five Years	$ 1,315,000

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Lease Obligations Future lease payments (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Leases [Abstract]
Operating Leases, Future Minimum Payments Due, Next Twelve Months	$ 2,300
Operating Leases, Future Minimum Payments, Due in Two Years	1,998
Operating Leases, Future Minimum Payments, Due in Three Years	1,800
Operating Leases, Future Minimum Payments, Due in Four Years	1,689
Operating Leases, Future Minimum Payments, Due in Five Years	1,642
Operating Leases, Future Minimum Payments, Due Thereafter	5,400
Operating Leases, Future Minimum Payments Due	$ 14,800

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Stockholders' Equity Additional Details (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017		Dec. 31, 2016
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
Stock Issued During Period, Shares, New Issues				960,488
Stock Issued During Period, Value, Other				$ 62.26
Proceeds from issuance of common stock, net of expenses	$ 0	$ (10,000)	[1]	$ 57,360,000	[1]

[1] On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.

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Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (4,272)	$ (4,878)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(3,732)	440
Amounts reclassified from accumulated other comprehensive income/(loss)	2,198	166
Net current-period other comprehensive income/(loss)	(1,534)	606
Accumulated other comprehensive loss at end of period	(6,713)	(4,272)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(907)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	(4,743)	(5,360)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(602)	281
Amounts reclassified from accumulated other comprehensive income/(loss)	439	336
Net current-period other comprehensive income/(loss)	(163)	617
Accumulated other comprehensive loss at end of period	(5,928)	(4,743)
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	482
Other Comprehensive Income (Loss), before Reclassifications, before Tax	(3,130)	159
Amounts reclassified from accumulated other comprehensive income/(loss)	1,759	(170)
Net current-period other comprehensive income/(loss)	(1,371)	(11)
Accumulated other comprehensive loss at end of period	(785)	$ 471
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 115

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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, 2018	Dec. 31, 2017	Dec. 31, 2016
Amortization of defined benefit pension and postretirement plan items:
Income tax benefit		$ (20,994)	$ (14,309)	$ (28,341)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of defined benefit pension and postretirement plan items:
Net of tax		(2,198)	(166)	(454)
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]	(579)	(636)	(871)
Total before income taxes		(502)	(559)	(794)
Income tax benefit		63	223	320
Net of tax		(439)	(336)	(474)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes		(2,460)	329	23
Income tax benefit		701	(159)	(3)
Net of tax		(1,759)	170	20
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	[2]	(647)	1,607	(322)
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	[2]	(2,010)	(456)	345
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	[2]	$ 197	$ (822)	$ 0

[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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Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2018 USD ($) plan shares	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans | plan		3
Income tax benefits		$ 2,100
Pre-merger regulatory asset		557
Total unrecognized cost		23,500
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
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		$ 5,500	$ 5,000	$ 4,500
Shares reserved to fund future contributions | shares		831,183
Investments, Fair Value Disclosure		$ 6,711	6,756
Deferred compensation obligation		$ 3,854	3,395
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		3,865
Unfunded accumulated benefit obligation		(2,063)	(2,093)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		163
Expected contribution	[1]	528
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Merger Related Costs Allowed To Be Recovered In Future Rates		500
Defined Benefit Plan, Amortization of Transition Asset (Obligation)			1,300
Pre-merger regulatory asset		543
Total unrecognized cost		19,087
Unfunded accumulated benefit obligation		(15,776)	(16,268)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		1,200
Expected contribution	[1]	3,091
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		559
Unfunded accumulated benefit obligation		(2,285)	(2,428)
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		383
Expected contribution	[2]	$ 383
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		54
Unfunded accumulated benefit obligation		$ (1,002)	(1,128)
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		$ 96
Expected contribution	[2]	96
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		14	22
Total unrecognized cost		(65)
Unfunded accumulated benefit obligation		$ (1,187)	(1,287)
Health care inflation rate		5.00%
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 94
Expected contribution	[2]	94
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Investments, Fair Value Disclosure		$ 6,689	$ 6,734
FPU Medical Plan and Chesapeake OPRB [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans		2

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

[2] Benefit payments are expected to be paid out of our general funds.

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Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Change in benefit obligation:
Interest cost		$ 83	$ 89	$ 91
Change in plan assets:
Balance, beginning of year		57,746
Balance, end of year		52,250	57,746
Chesapeake Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year		11,443	11,355
Interest cost		384	402	421
Actuarial loss		(610)	454
Benefits paid		(505)	(768)
Benefit obligation - end of year		10,712	11,443	11,355
Change in plan assets:
Balance, beginning of year		9,350	8,668
Actual return on plan assets		(647)	1,144
Employer contributions		451	306
Benefits paid		(505)	(768)
Balance, end of year		8,649	9,350	$ 8,668
Reconciliation:
Funded status		(2,063)	(2,093)
Accrued pension cost		$ (2,063)	$ (2,093)
Assumptions:
Discount rate		4.00%	3.50%
Expected return on plan assets		6.00%	6.00%	6.00%
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 64,664	$ 63,832
Interest cost		2,339	2,482	$ 2,525
Actuarial loss		(4,739)	1,199
Benefits paid		(2,887)	(2,849)
Benefit obligation - end of year		59,377	64,664	63,832
Change in plan assets:
Balance, beginning of year		48,396	43,272
Actual return on plan assets		(3,113)	6,025
Employer contributions		1,205	1,948
Benefits paid		(2,887)	(2,849)
Balance, end of year		43,601	48,396	$ 43,272
Reconciliation:
Funded status		(15,776)	(16,268)
Accrued pension cost		$ (15,776)	$ (16,268)
Assumptions:
Discount rate		4.25%	3.75%
Expected return on plan assets		6.50%	6.50%	6.50%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year		$ 2,428	$ 2,428
Interest cost		83	89
Actuarial loss		(74)	63
Benefits paid		(152)	(152)
Benefit obligation - end of year		2,285	2,428	$ 2,428
Change in plan assets:
Employer contributions		152	152
Benefits paid		(152)	(152)
Reconciliation:
Funded status		(2,285)	(2,428)
Accrued pension cost		$ (2,285)	$ (2,428)
Assumptions:
Discount rate		4.00%	3.50%
Chesapeake Postretirement Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 1,128	$ 1,132
Interest cost		38	41	43
Plan participants contributions		136	118
Actuarial loss		(131)	72
Benefits paid		(169)	(235)
Benefit obligation - end of year		1,002	1,128	1,132
Change in plan assets:
Balance, beginning of year		0	0
Employer contributions	[1]	33	117
Plan participants contributions		136	118
Benefits paid		(169)	(235)
Balance, end of year		0	0	0
Reconciliation:
Funded status		(1,002)	(1,128)
Accrued pension cost		$ (1,002)	$ (1,128)
Assumptions:
Discount rate		4.00%	3.50%
FPU Medical Plan
Change in benefit obligation:
Benefit obligation - beginning of year		$ 1,287	$ 1,349
Interest cost		47	50	55
Plan participants contributions		41	48
Actuarial loss		(89)	(48)
Benefits paid		(99)	(112)
Benefit obligation - end of year		1,187	1,287	1,349
Change in plan assets:
Balance, beginning of year		0	0
Employer contributions	[1]	58	64
Plan participants contributions		41	48
Benefits paid		(99)	(112)
Balance, end of year		0	0	$ 0
Reconciliation:
Funded status		(1,187)	(1,287)
Accrued pension cost		$ (1,187)	$ (1,287)
Assumptions:
Discount rate		4.25%	3.75%

[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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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, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		$ (524)
Net loss		23,467
Total		22,943
Accumulated other comprehensive loss pre-tax		7,986
Post-merger regulatory asset		14,957
Subtotal		22,943
Pre-merger regulatory asset		557
Total unrecognized cost		23,500
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		0
Net loss		3,865
Total		3,865
Accumulated other comprehensive loss pre-tax	[1]	3,865
Post-merger regulatory asset		0
Subtotal		3,865
Pre-merger regulatory asset		0
Total unrecognized cost		3,865
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		0
Net loss		18,544
Total		18,544
Accumulated other comprehensive loss pre-tax	[1]	3,523
Post-merger regulatory asset		15,021
Subtotal		18,544
Pre-merger regulatory asset		543
Total unrecognized cost		19,087
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		0
Net loss		559
Total		559
Accumulated other comprehensive loss pre-tax	[1]	559
Post-merger regulatory asset		0
Subtotal		559
Pre-merger regulatory asset		0
Total unrecognized cost		559
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		(524)
Net loss		578
Total		54
Accumulated other comprehensive loss pre-tax	[1]	54
Post-merger regulatory asset		0
Subtotal		54
Pre-merger regulatory asset		0
Total unrecognized cost		54
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)		0
Net loss		(79)
Total		(79)
Accumulated other comprehensive loss pre-tax	[1]	(15)
Post-merger regulatory asset		(64)
Subtotal		(79)
Pre-merger regulatory asset		14	$ 22
Total unrecognized cost		$ (65)

[1] The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2018 is net of income tax benefits of $2.1 million.

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Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Phantoms) (Detail) $ in Millions	Dec. 31, 2018 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	$ 2.1

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Employee Benefit Plans - Schedule of Assets by Investment Type (Detail)	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	49.02%	52.70%	52.93%
Chesapeake Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	40.98%	37.79%	37.64%
Chesapeake Pension Plan | Other
Asset Category
Percentage of assets by investment type	10.00%	9.51%	9.43%
FPU Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
FPU Pension Plan | Investments in equity securities
Asset Category
Percentage of assets by investment type	50.04%	55.17%	53.18%
FPU Pension Plan | Debt securities
Asset Category
Percentage of assets by investment type	41.06%	36.56%	37.74%
FPU Pension Plan | Other
Asset Category
Percentage of assets by investment type	8.90%	8.27%	9.08%

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Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2018
Minimum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	14.00%
Minimum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	13.00%
Minimum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	26.00%
Minimum | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	6.00%
Minimum | Diversifying Assets
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7.00%
Minimum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	0.00%
Maximum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	32.00%
Maximum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	25.00%
Maximum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	40.00%
Maximum | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	14.00%
Maximum | Diversifying Assets
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	19.00%
Maximum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	5.00%

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Employee Benefit Plans - Summary of Pension Plan Assets (Detail) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 52,250	$ 57,746
Total Pension Plan Assets, excluding investments measured at net asset value		46,692	50,498
Investments measured at net asset value	[1]	5,558	7,248
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		20,499	24,382
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	3,399	4,245
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1,478	1,775
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	670	918
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	9,226	11,916
Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	5,726	5,528
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		21,448	21,226
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	18,630	18,454
Debt securities | High Yield Asset Backed Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	2,818	2,772
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		4,745	4,890
Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	1,902	2,154
Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,216	2,300
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[8]	627	436
Quoted Prices in Active Markets (Level 1)
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		46,065	50,062
Quoted Prices in Active Markets (Level 1) | Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		20,499	24,382
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]	3,399	4,245
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]	1,478	1,775
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]	670	918
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]	9,226	11,916
Quoted Prices in Active Markets (Level 1) | Investments in equity securities | Alternative Strategies
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	5,726	5,528
Quoted Prices in Active Markets (Level 1) | Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		21,448	21,226
Quoted Prices in Active Markets (Level 1) | Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	18,630	18,454
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]	2,818	2,772
Quoted Prices in Active Markets (Level 1) | Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		4,118	4,454
Quoted Prices in Active Markets (Level 1) | Other | Commodities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[6]	1,902	2,154
Quoted Prices in Active Markets (Level 1) | Other | Real Estate
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[7]	2,216	2,300
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		627	436	$ 498
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		627	436
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]	$ 627	$ 436

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

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

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

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

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

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

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

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

XML

Employee Benefit Plans - Summary of Changes in Fair Value of Level 3 Investments (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		$ 57,746
Balance, end of year		52,250	$ 57,746
Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		50,062
Balance, end of year		46,065	50,062
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		436	498
Purchases		1,674	2,271
Transfers in		2,375	1,743
Disbursements		(3,872)	(4,101)
Investment Income		14	25
Balance, end of year		627	436
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year		24,382
Balance, end of year		20,499	24,382
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		24,382
Balance, end of year		20,499	24,382
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		21,226
Balance, end of year		21,448	21,226
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		21,226
Balance, end of year		21,448	21,226
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
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	[1]	4,245
Balance, end of year	[1]	3,399	4,245
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	[1]	4,245
Balance, end of year	[1]	3,399	4,245
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	[1]	0
Balance, end of year	[1]	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	[1]	0
Balance, end of year	[1]	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	[1]	1,775
Balance, end of year	[1]	1,478	1,775
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	[1]	1,775
Balance, end of year	[1]	1,478	1,775
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	[1]	0
Balance, end of year	[1]	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	[1]	0
Balance, end of year	[1]	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	[1]	918
Balance, end of year	[1]	670	918
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	[1]	918
Balance, end of year	[1]	670	918
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	[1]	0
Balance, end of year	[1]	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	[1]	0
Balance, end of year	[1]	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	[2]	11,916
Balance, end of year	[2]	9,226	11,916
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	[2]	11,916
Balance, end of year	[2]	9,226	11,916
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	[2]	0
Balance, end of year	[2]	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	[2]	0
Balance, end of year	[2]	0	0
Alternative Strategies | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	[3]	5,528
Balance, end of year	[3]	5,726	5,528
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	[3]	5,528
Balance, end of year	[3]	5,726	5,528
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	[3]	0
Balance, end of year	[3]	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	[3]	0
Balance, end of year	[3]	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	[4]	2,772
Balance, end of year	[4]	2,818	2,772
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	[4]	2,772
Balance, end of year	[4]	2,818	2,772
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	[4]	0
Balance, end of year	[4]	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	[4]	0
Balance, end of year	[4]	$ 0	$ 0

[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.

XML

Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) - USD ($) $ in Thousands		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Components of net periodic cost:
Interest cost		$ 83	$ 89	$ 91
Expected Amortization Of Pre Merger Regulatory Asset		0
Assumptions
Defined Benefit Plan, Plan Assets, Amount		52,250	57,746
Chesapeake Postretirement Plan
Components of net periodic cost:
Interest cost		38	41	43
Amortization of prior service cost		(77)	(77)	(77)
Actuarial (gain) loss		58	53	64
Net periodic pension cost		19	17	30
Expected Amortization Of Pre Merger Regulatory Asset			0	0
Net periodic postretirement cost	[1]	$ 19	$ 17	$ 30
Assumptions
Discount rate		3.50%	3.75%	3.75%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 136	$ 118
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(131)	72
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(169)	(235)
Defined Benefit Plan, Plan Assets, Amount		0	0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	[2]	33	117
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		136	118
Defined Benefit Plan, Plan Assets, Benefits Paid		(169)	(235)
Funded status		(1,002)	(1,128)
Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits		$ 1,002	$ 1,128
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.00%	3.50%
FPU Medical Plan
Components of net periodic cost:
Interest cost		$ 47	$ 50	55
Amortization of prior service cost		0	0	0
Actuarial (gain) loss		0	0	0
Net periodic pension cost		47	50	55
Amortization of pre-merger regulatory asset		8	8	8
Net periodic postretirement cost	[1]	$ 55	$ 58	$ 63
Assumptions
Discount rate		3.75%	4.00%	4.00%
Defined Benefit Plan, Benefit Obligation, Contributions by Plan Participant		$ 41	$ 48
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(89)	(48)
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(99)	(112)
Defined Benefit Plan, Plan Assets, Amount		0	0	$ 0
Defined Benefit Plan, Plan Assets, Contributions by Employer	[2]	58	64
Defined Benefit Plan, Plan Assets, Contributions by Plan Participant		41	48
Defined Benefit Plan, Plan Assets, Benefits Paid		(99)	(112)
Funded status		(1,187)	(1,287)
Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits		$ 1,187	$ 1,287
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.25%	3.75%
Chesapeake SERP
Components of net periodic cost:
Interest cost		$ 83	$ 89
Actuarial (gain) loss		101	87	87
Net periodic postretirement cost		$ 184	$ 176	$ 178
Assumptions
Discount rate		3.50%	3.75%	3.75%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ (74)	$ 63
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(152)	(152)
Defined Benefit Plan, Plan Assets, Contributions by Employer		152	152
Defined Benefit Plan, Plan Assets, Benefits Paid		(152)	(152)
Funded status		(2,285)	(2,428)
Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits		$ 2,285	$ 2,428
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.00%	3.50%
Chesapeake Pension Plan
Components of net periodic cost:
Interest cost		$ 384	$ 402	$ 421
Expected return on assets		(542)	(495)	(501)
Actuarial (gain) loss		343	399	459
Defined Benefit Plan, Net Periodic Benefit Cost (Credit), Gain (Loss) Due to Settlement		0	0	161
Net periodic pension cost		185	306	540
Amortization of pre-merger regulatory asset		0	0	0
Net periodic postretirement cost		$ 185	$ 306	$ 540
Assumptions
Discount rate		3.50%	3.75%	3.75%
Expected return on plan assets		6.00%	6.00%	6.00%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ (610)	$ 454
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(505)	(768)
Defined Benefit Plan, Plan Assets, Amount		8,649	9,350	$ 8,668
Defined Benefit Plan, Plan Assets, Contributions by Employer		451	306
Defined Benefit Plan, Plan Assets, Benefits Paid		(505)	(768)
Funded status		(2,063)	(2,093)
Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits		$ 2,063	$ 2,093
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.00%	3.50%
FPU Pension Plan
Components of net periodic cost:
Interest cost		$ 2,339	$ 2,482	2,525
Expected return on assets		(3,091)	(2,779)	(2,702)
Actuarial (gain) loss		404	513	519
Net periodic pension cost		(348)	216	342
Amortization of pre-merger regulatory asset		761	761	761
Net periodic postretirement cost		$ 413	$ 977	$ 1,103
Assumptions
Discount rate		3.75%	4.00%	4.00%
Expected return on plan assets		6.50%	6.50%	6.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		$ (4,739)	$ 1,199
Defined Benefit Plan, Benefit Obligation, Benefits Paid		(2,887)	(2,849)
Defined Benefit Plan, Plan Assets, Amount		43,601	48,396	$ 43,272
Defined Benefit Plan, Plan Assets, Contributions by Employer		1,205	1,948
Defined Benefit Plan, Plan Assets, Benefits Paid		(2,887)	(2,849)
Funded status		(15,776)	(16,268)
Defined Benefit Plan Accrued Pension Costs Accrued Expenses Employment Benefits		$ 15,776	$ 16,268
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate		4.25%	3.75%

[1] As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

[2] 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.

XML

Employee Benefit Plans - Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
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	761	761	761
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Amortization of pre-merger regulatory asset	$ 8	$ 8	$ 8

XML

Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2018 USD ($)
Chesapeake Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	$ 528	[1]
2018	529	[1]
2019	736	[1]
2020	595	[1]
2021	1,244	[1]
Years 2022 through 2026	3,866	[1]
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	3,091	[1]
2018	3,221	[1]
2019	3,299	[1]
2020	3,485	[1]
2021	3,558	[1]
Years 2022 through 2026	18,570	[1]
Chesapeake SERP
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	383	[2]
2018	150	[2]
2019	148	[2]
2020	147	[2]
2021	145	[2]
Years 2022 through 2026	744	[2]
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	96	[2]
2018	85	[2]
2019	82	[2]
2020	81	[2]
2021	64	[2]
Years 2022 through 2026	275	[2]
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	94	[2]
2018	87	[2]
2019	91	[2]
2020	93	[2]
2021	80	[2]
Years 2022 through 2026	$ 402	[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.

XML

Employee Benefit Plans Employee benefit plans phantoms (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans Table Text Block [Line Items]
Funded status	$ (2,063)	$ (2,093)

XML

Share-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Thousands		12 Months Ended
		Dec. 31, 2018 USD ($) $ / shares shares	Dec. 31, 2017 USD ($) $ / shares shares	Dec. 31, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation expense related to the awards to Non employee directors | $		$ 2,101
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	[1]	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		7,128	7,515
Number of shares withheld		10,436	10,269	12,031
Payments of employees' tax obligations to taxing authorities		3
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized | $		$ 1,100
SICP Awards to Non-employee directors
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			$ 71.80
Amortization of expense equally over a service period		1 year
Unrecognized compensation expense related to the awards to Non employee directors | $		$ 180
Number of Shares, Granted		792	835
Weighted average grant-date fair value of awards granted | $ / shares		$ 75.70
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		$ 47.39	$ 38.88
Number of Shares, Granted		49,494	52,355
Weighted average grant-date fair value of awards granted | $ / shares		$ 67.76	$ 63.42
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested | $		$ 10,700	$ 10,400	$ 7,700
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance		475,099

[1] Includes 2,569 shares that were forfeited

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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, 2018	Dec. 31, 2017	Dec. 31, 2016
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 3,410	$ 2,490	$ 2,367
Less: tax benefit	(934)	(1,003)	(952)
Share-Based Compensation amounts included in net income	2,476	1,487	1,415
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	2,101
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	539	540	580
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	180
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	10,700	10,400	7,700
Total compensation expense	$ 2,871	$ 1,950	$ 1,787

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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, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	7,128	7,515
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract]
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	$ 2,101
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Period For Amortization Of Share Based Expenses	1 year
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	792	835
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	$ 75.70
Weighted Average Grant Date Fair Value, Vested		$ 71.80
Employee Service Share-based Compensation, Nonvested Awards, Compensation Not yet Recognized, Share-based Awards Other than Options	$ 180

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Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - $ / shares		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted		7,128	7,515
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	[1]	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		132,642	115,091
Number of Shares, Granted		49,494	52,355
Number of Shares, Vested		(29,786)	(32,926)
Number of Shares, Expired		(3,933)	1,878
Number of Shares, Outstanding Ending Balance		131,741	132,642
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		$ 59.31	$ 51.85
Weighted Average Grant Date Fair Value, Granted		67.76	63.42
Weighted Average Grant Date Fair Value, Vested		47.39	38.88
Weighted Average Grant Date Fair Value, Expired		49.66	39.97
Weighted Average Grant Date Fair Value, Outstanding Ending Balance		67.24	$ 59.31
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	[1]	$ 75.78
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	[1]	16,676

[1] Includes 2,569 shares that were forfeited

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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, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Shares Paid for Tax Withholding for Share Based Compensation	10,436	10,269	12,031
Payments Related to Tax Withholding for Share-based Compensation	$ 1,210	$ 692	$ 770
Proceeds and Excess Tax Benefit from Share-based Compensation	$ 0	$ 349	$ 285

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Rates and Other Regulatory Activities - Additional Information (Detail)	3 Months Ended								12 Months Ended
	Dec. 31, 2018 USD ($) mi	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Sep. 30, 2017 USD ($)	Jun. 30, 2017 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2018 USD ($) dekatherm / d unit mi	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Rates and Other Regulatory Activities [Line Items]
Restricted Payment	$ 201,500,000								$ 201,500,000
Regulatory Assets	77,218,000				$ 86,505,000				$ 77,218,000	$ 86,505,000
Florida Appeal Period for Federal Tax Reform Impact									30 days
Revenues	$ 201,190,000	$ 140,279,000	$ 136,664,000	$ 239,356,000	$ 180,403,000	$ 126,936,000	$ 125,084,000	$ 185,160,000	$ 717,489,000	$ 617,583,000	$ 498,860,000
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount									$ 1.82
Number of Years to Recover Storm Related Costs									2 years
Extent of Customers Losing Service									100.00%
Amounts Spent to Restore Service									$ 60,000,000
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									$ 30,000,000
Asset Recovery Damaged Property Costs, Noncurrent	$ 1,500,000								1,500,000
Deferred Storm and Property Reserve Deficiency, Noncurrent	779,000								779,000
Electric distribution
Rates and Other Regulatory Activities [Line Items]
Amount of Regulatory Costs Not yet Approved	15,200,000								15,200,000
Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
Increase in Revenue Recognized Due to Motion Rate in Effect	$ 3,700,000								$ 3,700,000
Eastern Shore Gas Company | 2017 Expansion Project [Member]
Rates and Other Regulatory Activities [Line Items]
firm natural gas transportation deliverability | dekatherm / d									61,162
Additional Firm Natural Gas Transportation Deliverability | dekatherm / d									52,500
Number of Pipeline Miles | mi	23								23
Miles Of Natural Gas Pipeline | mi	17								17
Pressure Control Stations									2
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	$ 2,500,000								$ 2,500,000
Business Acquisition Premium Paid	$ 34,200,000								$ 34,200,000
Subscribers [Member] | Eastern Shore Gas Company | 2017 Expansion Project [Member]
Rates and Other Regulatory Activities [Line Items]
number of customers									7
Number of affiliates | unit									3
Pre TCJA approved revenue requirements [Member] | Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount									$ 9,800,000
Post TCJA approved revenue requirements [Member] | Eastern Shore Gas Company
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount									$ 6,600,000

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Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands		Dec. 31, 2018	Dec. 31, 2017
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 77,218	$ 86,505
Regulatory Liabilities		142,922	147,463
Self Insured Liabilities [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	947	1,013
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	5,443	2,048
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	677	669
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	42,401	40,948
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[4]	91,162	98,492
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		729	2,048
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	4,631	9,869
Under-recovered GRIP Revenue [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[5]	165	164
Regulatory Liabilities	[5]	1,563	2,245
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	15,517	15,498
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2]	16,727	11,735
Environmental Regulatory Assets And Expenditures [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	2,731	3,222
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[8]	33,255	39,992
Loss on Reacquired Debt [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	942	1,031
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		3,250	$ 4,994
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34,200
Regulatory Liabilities		19,505
Indiantown Gas Company
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		746
FPU Pension Plan
Rates and Other Regulatory Activities [Line Items]
Merger Related Costs Allowed To Be Recovered In Future Rates		$ 500

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

[3] See Note 1, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.

[4] We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 12, Income Taxes, for additional information.

[5] The Florida PSC 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. 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. Included in these amounts are $543,000 of the premium paid by FPU, $34.2 million of the premium paid by us in 2009, including a gross up for income tax, because it is not tax deductible, and $746,000 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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Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2018	Dec. 31, 2017
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 142,922	$ 147,463
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	13,262
Maryland Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	4,211
Sandpiper [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	3,815
Central Florida Gas Division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	8,471
Florida Public Utilities Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	19,505
FPU electric division [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 5,995

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Environmental Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	$ 7,638,000	$ 8,263,000
Amount paid for funding requirements	625,000	$ 329,000	$ 350,000
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	9,100,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	11,500,000
FPU | Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	$ 2,500,000
FPU | Sanford Florida
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense percent	5.00%
Environmental Remediation Expense	$ 24,000
Number of Years to ensure remedy	5
FPU | Sanford Florida | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	$ 13,000,000
FPU | Sanford Florida | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	$ 650,000

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Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands, gal in Millions	12 Months Ended
	Dec. 31, 2018 USD ($) gal
Subsequent Event [Line Items]
Intercompany Agreements, Description	3
Annual Estimate Of Volume Of Propane To Be Purchased | gal	1.2
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	$ 158,500
Total purchase obligations for 2019 - 2020	74,970
Total purchase obligations for 2021 - 2022	42,279
Total purchase obligations thereafter	129,019
Maximum authorized liability under such guarantees and letters of credit	95,000
Aggregate guaranteed amount	76,500
Amount of letter of credit to our current primary insurance company	$ 7,000

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Other Commitments and Contingencies Purchase Obligations (Details) $ in Thousands	Dec. 31, 2018 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 158,500
Purchase Obligation, Due in Second and Third Year	74,970
Purchase Obligation, Due in Fourth and Fifth Year	42,279
Purchase Obligation, Due after Fifth Year	129,019
Purchase Obligation	$ 404,812

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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, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Disclosure Quarterly Financial Data Schedule Of Quarterly Financial Information [Abstract]
Revenues	$ 201,190	$ 140,279	$ 136,664	$ 239,356	$ 180,403	$ 126,936	$ 125,084	$ 185,160	$ 717,489	$ 617,583	$ 498,860
Operating Income	28,930	12,036	13,248	40,406	23,628	14,632	14,061	35,099	94,620	87,420	85,983
Net Income	$ 17,801	$ 5,538	$ 6,387	$ 26,855	$ 26,101	$ 6,833	$ 6,046	$ 19,144	$ 56,580	$ 58,124	$ 44,675
Earnings per share:
Basic (in usd per share)	$ 1.09	$ 0.34	$ 0.39	$ 1.64	$ 1.60	$ 0.42	$ 0.37	$ 1.17	$ 3.46	$ 3.56	$ 2.87
Diluted (in usd per share)	$ 1.08	$ 0.34	$ 0.39	$ 1.64	$ 1.59	$ 0.42	$ 0.37	$ 1.17	$ 3.45	$ 3.55	$ 2.86

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Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 936	$ 909	$ 909
Additions, Charged to Income	1,157	602	985
Additions, Other Accounts	136	337	340
Deductions	(1,121)	(912)	(1,325)
Balance at End of Year	$ 1,108	$ 936	$ 909