CHESAPEAKE UTILITIES CORP - Annual Report: 2019 (Form 10-K)

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company

Emerging growth company

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

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

For the Fiscal Year Ended: December 31, 2019

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

Commission File Number: 001-11590




CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)



State of Delaware		51-0064146
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including zip code)

302-734-6799

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:



Title of each class	Trading Symbol	Name of each exchange on which registered
Common Stock—par value per share $0.4867	CPK	New York Stock Exchange, Inc.

Securities registered pursuant to Section 12(g) of the Act:

None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

The aggregate market value of the common shares held by non-affiliates of Chesapeake Utilities Corporation as of June 30, 2019, the last business day of its most recently completed second fiscal quarter, based on the last sale price on that date, as reported by the New York Stock Exchange, was approximately $1.5 billion.

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

DOCUMENTS INCORPORATED BY REFERENCE

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

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CHESAPEAKE UTILITIES CORPORATION

FORM 10-K

YEAR ENDED DECEMBER 31, 2019

TABLE OF CONTENTS



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

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GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

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

CDD: Cooling Degree-Day

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

CHP: Combined Heat and Power Plant

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

Degree-day: A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit

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

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

Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value

Dts/d: Dekatherms per day

Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake Utilities

Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake's OnSight Services, LLC

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission

FGT: Florida Gas Transmission Company

Flo-gas: Flo-gas Corporation, a wholly-owned subsidiary of Chesapeake Utilities

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

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

GAAP: Generally Accepted Accounting Principles

Gas South: Gas South LLC

GRIP: Gas Reliability Infrastructure Program

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

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

HDD: Heating Degree Day

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

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

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

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

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

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

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

Peoples Gas: Peoples Gas System division of Tampa Electric Company

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

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

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

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

Revolver: Our unsecured revolving credit facility with certain lenders

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

SEC: Securities and Exchange Commission

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

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

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

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

SICP: 2013 Stock and Incentive Compensation Plan

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

TETLP: Texas Eastern Transmission, LP

UET: United Energy Trading, LLC

U.S.: The United States of America

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

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PART I

References in this document to “Chesapeake,” “Chesapeake Utilities,” the “Company,” “we,” “us” and “our” mean Chesapeake Utilities Corporation, its divisions and/or its wholly-owned subsidiaries, as appropriate in the context of the disclosure.

Safe Harbor for Forward-Looking Statements

We make statements in this Annual Report on Form 10-K that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future events or otherwise. These statements are subject to many risks and uncertainties. In addition to the risk factors described under Item 1A, Risk Factors, the following important factors, among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:


•	state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed and the degree to which competition enters the electric and natural gas industries;


•	the outcomes of regulatory, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the related costs are adequately covered by insurance or recoverable in rates;


•	the impact of climate change, including the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change;


•	the impact of significant changes to current tax regulations and rates;


•	the timing of certification authorizations associated with new capital projects and the ability to construct facilities at or below estimated costs;


•	changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now, or may in the future, own or operate;


•	possible increased federal, state and local regulation of the safety of our operations;


•	the inherent hazards and risks involved in transporting and distributing natural gas and electricity;


•	the economy in our service territories or markets, the nation, and worldwide, including the impact of economic conditions (which we do not control ) on demand for electricity, natural gas, propane or other fuels;


•	risks related to cyber-attacks or cyber-terrorism that could disrupt our business operations or result in failure of information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information;


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


•	customers' preferred energy sources;


•	industrial, commercial and residential growth or contraction in our markets or service territories;


•	the effect of competition on our businesses from other energy suppliers and alternative forms of energy;


•	the timing and extent of changes in commodity prices and interest rates;


•	the effect of spot, forward and future market prices on our various energy businesses;


•	the extent of our success in connecting natural gas and electric supplies to transmission systems, establishing and maintaining key supply sources; and expanding natural gas and electric markets;


•	the creditworthiness of counterparties with which we are engaged in transactions;


•	the capital-intensive nature of our regulated energy businesses;


•	our ability to access the credit and capital markets to execute our business strategy, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;


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


•	the impact on our costs and funding obligations, under our pension and other post-retirement benefit plans, of potential downturns in the financial markets, lower discount rates, and costs associated with health care legislation and regulation;


•	the ability to continue to hire, train and retain appropriately qualified personnel; and


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

Chesapeake Utilities Corporation 2019 Form 10-K Page 1

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ITEM 1. Business.

Corporate Overview and Strategy

Chesapeake Utilities Corporation is a Delaware corporation formed in 1947 with operations primarily in the Mid-Atlantic region, Florida and Ohio. We are an energy delivery company engaged in the distribution of natural gas, propane and electricity; the transmission of natural gas; the generation of electricity and steam, and in providing related services to our customers.

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

•

capital investment in growth opportunities that generate our target returns;

•

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

•

providing new services in our current service areas;

•

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

•

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

•

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

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

Operating Segments

We operate within two reportable segments: Regulated Energy and Unregulated Energy. The remainder of our operations is presented as “Other businesses and eliminations." These segments are described below in detail.

Regulated Energy

Our regulated energy businesses are comprised of natural gas and electric distribution as well as natural gas transmission services. The following table presents net income for the year ended December 31, 2019 and total assets as of December 31, 2019, for our Regulated Energy segment by operation and area served:




Operations	Areas Served	Net Income		Total Assets
(in thousands)
Natural Gas Distribution
Delmarva Natural Gas (Delaware division, Maryland division and Sandpiper Energy)	Delaware/Maryland	$	9,873	$	280,002
Central Florida Gas and FPU	Florida	13,721		420,483
Natural Gas Transmission
Eastern Shore	Delaware/Maryland/ Pennsylvania	17,965		447,041
Peninsula Pipeline	Florida	5,571		115,685

Electric Distribution
FPU	Florida	640		170,855
Total Regulated Energy		$	47,770	$	1,434,066

Revenues in this operating segment are based on rates regulated by the PSC in the states in which we operate or, in the case of Eastern Shore, which is an interstate business, by the FERC. The rates are designed to generate revenues to recover all prudent operating and financing costs and provide a reasonable return for our stockholders. Each of our distribution and transmission operations has a rate base, which generally consists of the original cost of the operation's plant, less accumulated depreciation, working capital and other assets. For Delmarva Natural Gas and Eastern Shore, rate base also includes deferred income tax liabilities and other additions or deductions. Our Regulated Energy operations in Florida do not include deferred income tax liabilities in their rate base.

Chesapeake Utilities Corporation 2019 Form 10-K Page 2

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Our natural gas and electric distribution operations bill customers at standard rates approved by their respective state PSC. Each state PSC allows us to negotiate rates, based on approved methodologies, for large customers that can switch to other fuels. Some of our customers in Maryland receive propane through our underground distribution system in Worcester County, which we are in the process of converting to natural gas. We bill these customers under PSC-approved rates and include them in the natural gas distribution results and customer statistics.

Our natural gas and electric distribution operations earn profits on the delivery of natural gas or electricity to customers. The cost of natural gas or electricity that we deliver is passed through to customers under PSC-approved fuel cost recovery mechanisms. The mechanisms allow us to adjust our rates on an ongoing basis without filing a rate case to recover changes in the cost of the natural gas and electricity that we purchase for customers. Therefore, while our distribution operating revenues fluctuate with the cost of natural gas or electricity we purchase, our distribution margin (which we define as operating revenues less purchased gas or electric cost) is generally not impacted by fluctuations in the cost of natural gas or electricity.

Our natural gas transmission operations bill customers under rate schedules approved by the FERC or at rates negotiated with customers.

Operational Highlights

The following table presents operating revenues, volumes and the average number of customers by customer class for our natural gas and electric distribution operations for the year ended December 31, 2019:




	Delmarva Natural Gas Distribution				Florida Natural Gas Distribution ⁽²⁾				FPU Electric Distribution
Operating Revenues (in thousands)
Residential	$	62,708	60	%	$	38,248	34	%	$	45,738		59	%
Commercial	33,070		32	%	33,126		30	%	38,254			49	%
Industrial	8,314		8	%	37,202		34	%	2,128			3	%
Other ⁽¹⁾	152		<1%		2,327		2	%	(8,704		)	(11	)%
Total Operating Revenues	$	104,244	100	%	110,903		100	%	$	77,416		100	%

Volumes (in Dts for natural gas/KW Hours for electric)
Residential	3,871,032		29	%	1,744,486		4	%	306,445			47	%
Commercial	3,776,388		29	%	6,190,350		14	%	310,856			49	%
Industrial	5,358,474		40	%	32,736,870		76	%	27,929			4	%
Other	220,541		2	%	2,574,925		6	%	—			—	%
Total Volumes	13,226,435		100	%	43,246,631		100	%	645,230			100	%

Average Number of Customers⁽³⁾
Residential	73,995		91	%	74,915		90	%	24,573			77	%
Commercial	7,097		9	%	5,478		7	%	7,243			23	%
Industrial	169		<1%		2,453		3	%	2			<1%
Other	15		<1%		12		<1%		—			—	%
Total Average Number of Customers	81,276		100	%	82,858		100	%	31,818			100	%

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

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 3

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



	Eastern Shore				Peninsula Pipeline
Operating Revenues (in thousands)
Local distribution companies - affiliated ⁽¹⁾	$	24,709	33	%	$	14,003	85	%
Local distribution companies - non-affiliated	25,171		35	%	840		5	%
Commercial and industrial - affiliated	—		—	%	1,120		7	%
Commercial and industrial - non-affiliated	22,527		31	%	490		3	%
Other ⁽²⁾	516		1	%	—		—	%
Total Operating Revenues	$	72,923	100	%	$	16,453	100	%

Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated	125,152		42	%	243,500		95	%
Local distribution companies - non-affiliated	76,619		26	%	4,825		2	%
Commercial and industrial - affiliated	—		—	%	1,500		1	%
Commercial and industrial - non-affiliated	96,348		32	%	5,100		2	%
Total Contracted firm transportation capacity	298,119		100	%	254,925		100	%

Design day capacity (in Dts/d)	298,119		100	%	254,925		100	%

⁽¹⁾Eastern Shore's and Peninsula Pipeline's service to our local distribution affiliates is based on the respective regulator's approved rates and is an integral component of the cost associated with providing natural gas supplies for those affiliates. We eliminate operating revenues of these entities against the cost of sales of those affiliates in our consolidated financial information; however, our local distribution affiliates include this amount in their purchased fuel cost and recover it through fuel cost recovery mechanisms.

⁽²⁾ Operating revenues from "Other" sources are from the rental of gas properties

Regulatory Overview

The following table highlights key regulatory information for each of our principal Regulated Energy operations. Peninsula Pipeline is not regulated with regard to cost of service by either the Florida PSC or FERC and is therefore excluded from the table. The table reflects rate increases and rates of return approved prior to the enactment of the TCJA on December 22, 2017. See Item 8, Financial Statements and Supplementary Data (Note 19, Rates and Other Regulatory Activities and Note 12, Income Taxes in the consolidated financial statements) for further discussion on the impact of this legislation on our regulated businesses.



	Natural Gas Distribution
	Delmarva			Florida		Electric Distribution	Natural Gas Transmission
Operation/Division	Delaware	Maryland	Sandpiper	Chesapeake's Florida natural gas division	FPU	FPU	Eastern Shore
Regulatory Agency	Delaware PSC	Maryland PSC	Maryland PSC	Florida PSC	Florida PSC	Florida PSC	FERC
Effective date - Last Rate Order	01/01/2017	12/1/2007	12/01/2019	01/14/2010	01/14/2010⁽¹⁾	01/03/2018	08/01/2017
Rate Base (in Rates)	Not stated	Not stated	Not stated	$46,680,000	$68,940,000	$11,850,000	Not stated
Annual Rate Increase Approved	$2,250,000	$648,000	N/A⁽²⁾	$2,540,000	$7,970,000	$1,560,000	$9,800,000
Capital Structure (in rates)^(3)*	Not stated	LTD: 42.00% STD: 5.00% Equity: 53.00%	Not stated	LTD: 30.63% STD: 6.26% Equity: 43.49% Other: 19.62%	LTD: 30.75% Equity: 46.67% Other: 22.58%	LTD: 21.91% STD: 23.50% Equity: 54.59%	Not stated
Allowed Return on Equity	9.75% ⁽⁴⁾	10.75%⁽⁴⁾	Not Stated ⁽⁵⁾	10.80%⁽⁴⁾	10.85%⁽⁴⁾	10.25%^{(4), (6)}	Not Stated
TJCA Refund Status associated with customer rates	Refunded	Refunded	Refunded	Retained	Retained	Refunded	Refunded

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

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

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

⁽⁴⁾Allowed after-tax return on equity.

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

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

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

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

In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as a regulatory asset for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. In the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC on November 5, 2019 and interim rate increases became effective January 2, 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 2020. See Item 8, Financial Statements and Supplementary Data (Note 19, Rates and Other Regulatory Activities in the consolidated financial statements) for further information.

The following table presents surcharge and other mechanisms that have been approved by the respective PSC for our regulated energy distribution businesses. These include Delaware’s surcharge to expand natural gas service in eastern Sussex County; Maryland's surcharge to fund natural gas conversions and system improvement in Worcester County; Florida’s GRIP surcharge which provides accelerated recovery of the costs of replacing older portions of the natural gas distribution system to improve safety and reliability and the Florida electric distribution operation's limited proceeding.



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

Weather

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

Competition

Natural Gas Distribution

While our natural gas distribution operations do not compete directly with other distributors of natural gas for residential and commercial customers in our service areas, we do compete with other natural gas suppliers and alternative fuel providers for sales to industrial customers. Large customers could bypass our natural gas distribution systems and connect directly to interstate transmission pipelines, and we compete in all aspects of our natural gas business with alternative energy sources, including electricity, oil, propane and renewables. The most effective means to compete against alternative fuels are lower prices, superior reliability and flexibility of service. Natural gas historically has maintained a price advantage in the residential, commercial

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and industrial markets, and reliability of natural gas supply and service has been excellent. In addition, we provide flexible pricing to our large customers to minimize fuel switching and protect these volumes and their contributions to the profitability of our natural gas distribution operations.

Natural Gas Transmission

Our natural gas transmission business competes with other pipeline companies to provide service to large industrial, generation and distribution customers, primarily in the northern portion of Delmarva Peninsula and in Florida.

Electric Distribution

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

Supplies, Transmission and Storage

Natural Gas Distribution

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

The Delmarva natural gas distribution systems are directly connected to Eastern Shore’s pipeline, which has connections to the other pipelines that provide us with transportation and storage. These operations can also use propane-air and liquefied natural gas peak-shaving equipment to serve customers. Our Delmarva Peninsula natural gas distribution operations had asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of the sale of PESCO's assets and contracts, effective October 1, 2019, these agreements are now managed by NJRES. Our Delmarva operations receive a fee, which we share with our customers, from the asset manager, who optimizes the transportation, storage and natural gas supply for these operations.

Our Florida natural gas distribution operation uses Peninsula Pipeline and the Peoples Gas System division of Tampa Electric Company ("Peoples Gas") to transport natural gas where there is no direct connection with FGT. In May 2019, FPU natural gas distribution and Eight Flags entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. Short-term agreements were entered for a one year term beginning July 2019 through July 2020 with the expectation that long-term agreements will then be executed for a 10-year term commencing on or about July 2020.

A summary of our pipeline capacity contracts follows:



		Maximum Daily Firm Transportation Capacity (Dts)	Contract Expiration Date
Division	Pipeline	Maximum Daily Firm Transportation Capacity (Dts)	Contract Expiration Date
Delmarva Natural Gas Distribution	Eastern Shore	125,152	2020-2028
	Columbia Gas⁽¹⁾	15,160	2020-2024
	Transco⁽¹⁾	27,732	2019-2028
	TETLP⁽¹⁾	50,000	2027

Florida Natural Gas Distribution	Gulfstream⁽²⁾	10,000	2022
	FGT	53,409 - 84,817	2020-2041
	Peninsula Pipeline	237,500	2033-2048
	Peoples Gas	2,660	2024-2035
	Florida Southeast Connection	5,000	2045
	Southern Natural Gas Company	5,000	2020

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

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⁽²⁾Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under this agreement has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge.

Eastern Shore has three agreements with Transco for a total of 7,292 Dts/d of firm daily storage injection and withdrawal entitlements and total storage capacity of 288,003 Dts. These agreements expire in March 2023. Eastern Shore retains these firm storage services in order to provide swing transportation service and firm storage service to customers requesting such services.

Electric Distribution

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



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

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

Unregulated Energy

In the third and fourth quarter of 2019, we reached agreements with four entities to sell PESCO's assets and contracts. These transactions closed during the fourth quarter of 2019. As a result of the sale, we have fully exited the natural gas marketing business, which provided natural gas management and supply services to commercial and industrial customers in Florida, Delaware, Maryland, Pennsylvania, Ohio and other states. Accordingly, PESCO’s historical financial results are reflected in our consolidated financial statements as discontinued operations, which required retrospective application to financial information for all periods presented. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions and Divestitures in the consolidated financial statements) for further information. The following table presents net income for the year ended December 31, 2019 and total assets as of December 31, 2019, for our Unregulated Energy segment by operation and area served:



Operations	Area Served	Net Income		Total Assets
(in thousands)
Propane Operations (Sharp, FPU and Flo-gas)	Delaware, Maryland, Virginia, Pennsylvania, Florida	$	6,297	$	134,791
Energy Transmission (Aspire Energy)	Ohio	3,822		94,124
Energy Generation (Eight Flags)	Florida	1,908		38,569
Marlin Gas Services	The Eastern U.S.	986		27,269
Other	Other	382		171
Total		$	13,395	$	294,924

Propane Operations

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

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Propane Operations - Operational Highlights

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



	Operating Revenues (in thousands)								Volumes (in thousands of gallons)						Average Number of Customers ⁽¹⁾
	Mid-Atlantic				Florida				Mid-Atlantic			Florida			Mid-Atlantic ⁽²⁾			Florida

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

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

⁽²⁾ Average numbers of customers for the Mid-Atlantic propane operations includes approximately 5,200 customers added in December 2019 in the acquisition of certain propane operating assets of Boulden. See Item 8, Financial Statements and Supplementary Data (Note 4, Acquisitions and Divestitures in the consolidated financial statements) for further information.

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

Competition

Our propane operations compete with national and local independent companies primarily on the basis of price and service. Propane is generally a cheaper fuel for home heating than oil and electricity but more expensive than natural gas. Our propane operations are largely concentrated in areas that are not currently served by natural gas distribution systems.

Supplies, Transportation and Storage

We purchase propane from major oil companies and independent natural gas liquids producers. Propane is transported by truck and rail to our bulk storage facilities in Delaware, Maryland, Florida, Pennsylvania and Virginia, which have a total storage capacity of 7.4 million gallons. Deliveries are made from these facilities by truck to tanks located on customers’ premises or to central storage tanks that feed our underground propane distribution systems. While propane supply has traditionally been adequate, significant fluctuations in weather, closing of refineries and disruption in supply chains, could cause temporary reductions in available supplies.

Weather

Propane revenues are affected by seasonal variations in temperature and weather conditions, which directly influence the volume of propane used by our customers. Our propane revenues are typically highest during the winter months when propane is used for heating. Sustained warmer-than-normal temperatures will tend to reduce propane use, while sustained colder-than-normal temperatures will tend to increase consumption.

Unregulated Energy Transmission and Supply (Aspire Energy)

Aspire Energy owns approximately 2,700 miles of natural gas pipeline systems in 40 counties in Ohio. The majority of Aspire Energy’s revenues are derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative ("CGC"), which together serve more than 21,000 end-use customers. Aspire Energy purchases natural gas to serve these customers from conventional producers in the Marcellus and Utica natural gas production areas. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.

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For the twelve-month period ended December 31, 2019, Aspire Energy's operating revenues and deliveries by customer type were as follows:



	Operating revenues				Deliveries
	(in thousands)		% of Total		(in thousands Dts)	% of Total
Supply to Columbia Gas of Ohio	$	13,391	41	%	2,607	41	%
Supply to CGC	12,544		39	%	1,615	25	%
Supply to Marketers - affiliated	1,952		6	%	929	15	%
Supply to Marketers - unaffiliated	2,307		7	%	1,096	17	%
Other (including natural gas gathering and processing)	2,299		7	%	120	2	%
Total	$	32,493	100	%	6,367	100	%

Energy Generation (Eight Flags)

Eight Flags generates electricity and steam at its CHP plant located on Amelia Island, Florida. The plant is powered by natural gas transported by Peninsula Pipeline and our Florida natural gas distribution operation and produces approximately 21 MW of electricity and 75,000 pounds per hour of steam. Eight Flags sells the electricity generated from the plant to our Florida electric distribution operation and sells the steam to the customer who owns the site on which the plant is located both under separate 20-year contracts.

Marlin Gas Services

Marlin Gas Services is a supplier of mobile compressed natural gas (“CNG”) and pipeline solutions, primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. These services are provided by a highly trained staff of drivers and maintenance technicians who safely perform these functions throughout the eastern United States. Marlin Gas Services maintains a fleet of steel tube CNG trailers, composite CNG trailers, mobile compression equipment and an internally developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas. Marlin Gas Services continues to actively expand the territories it serves, as well as leverages its patented technology to potentially serve liquefied natural gas and renewable natural gas transportation needs.

Other Businesses and Eliminations

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

Environmental Matters

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

Employees

As of December 31, 2019, we had a total of 955 employees, 120 of whom are union employees represented by two labor unions: the International Brotherhood of Electrical Workers and the United Food and Commercial Workers Union. The collective bargaining agreements with these labor unions expire in 2022.

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Executive Officers

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



Name	Age	Officer Since	Offices Held During the Past Five Years
Jeffry M. Householder	62	2010	President (January 2019 - present) Chief Executive Officer (January 2019 - present) Director (January 2019 - present) President of FPU (June 2010 - February 2019)
Beth W. Cooper	53	2005	Executive Vice President (February 2019 - present) Chief Financial Officer (September 2008 - present) Senior Vice President (September 2008 - February 2019) Assistant Corporate Secretary (March 2015 - present) Corporate Secretary (June 2005 - March 2015)
James F. Moriarty	62	2015	Executive Vice President (February 2019 - present) General Counsel & Corporate Secretary (March 2015 - present) Chief Policy and Risk Officer (February 2019 - present) Senior Vice President (February 2017 - February 2019) Vice President (March 2015 - February 2017)
Kevin J. Webber	61	2010	Senior Vice President (February 2019 - present) President FPU (February 2019 - present) Vice President Gas Operations and Business Development Florida Business Units (July 2010 - February 2019)

Available Information on Corporate Governance Documents

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

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

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

•Code of Ethics for Financial Officers;

•Corporate Governance Guidelines;


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

•Corporate Governance Guidelines on Director Independence.

Any of these reports or documents may also be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, DE 19904.

ITEM 1A. RISK FACTORS.

The following is a discussion of the primary factors that may affect the operations and/or financial performance of our regulated and unregulated energy businesses. Refer to the section entitled Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for an additional discussion of these and other related factors that affect our operations and/or financial performance.

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FINANCIAL RISKS

Instability and volatility in the financial markets could negatively impact access to capital at competitive rates, which could affect our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth.

Our business strategy includes the continued pursuit of growth and requires capital investment in excess of cash flow from operations. As a result, the successful execution of our strategy is dependent upon access to equity and debt at reasonable costs. Our ability to issue new debt and equity capital and the cost of equity and debt are greatly affected by our financial performance and the conditions of the financial markets. In addition, our ability to obtain adequate and cost-effective debt depends on our credit ratings. A downgrade in our current credit ratings could negatively impact our access to and cost of debt. If we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.

Fluctuations in propane gas prices could negatively affect results of operations.

We adjust the price of the propane we sell based on changes in our cost of purchasing propane. However, if the market does not allow us to increase propane sales prices to compensate fully for fluctuations in purchased propane costs, our results of operations and earnings could be negatively affected.

If we fail to comply with our debt covenant obligations, we could experience adverse financial consequences that could affect our liquidity and ability to borrow funds.

Our long-term debt obligations, term loans, the Revolver and our committed short-term lines of credit contain financial covenants related to debt-to-capital ratios and interest-coverage ratios. Failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations or the inability to borrow under certain credit agreements. Any such acceleration could cause a material adverse change in our financial condition.

Increases in interest rates may adversely affect our results of operations and cash flows.

Increases in interest rates could increase the cost of future debt issuances. Absent recovery of the higher debt cost in the rates we charge our utility customers, our earnings could be adversely affected. Increases in short-term interest rates could negatively affect our results of operations, which depend on short-term lines of credit to finance accounts receivable and storage gas inventories and to temporarily finance capital expenditures. Reference should be made to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.

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

Our pension plans are closed to new employees, and the future benefits are frozen. The costs of providing benefits and related funding requirements of these plans are subject to changes in the market value of the assets that fund the plans and the discount rates used to estimate the pension benefit obligations. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of uncertainty, particularly in the current economic environment. Future losses of asset values and further declines in discount rates may necessitate accelerated funding of the plans to meet minimum federal government requirements and may result in higher pension expense in future years. Adverse changes in the benefit obligations of our pension plans may require us to record higher pension expense and fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.

OPERATIONAL RISKS

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

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

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We operate in a competitive environment, and we may lose customers to competitors.

Natural Gas. Our natural gas transmission and distribution operations compete with interstate pipelines when our customers are located close enough to a competing pipeline to make direct connections economically feasible. Customers also have the option to switch to alternative fuels, including renewable energy sources. Failure to retain and grow our natural gas customer base would have an adverse effect on our financial condition, cash flows and results of operations.

Electric. Our Florida electric distribution business has remained substantially free from direct competition from other electric service providers but does face competition from other energy sources. Changes in the competitive environment caused by legislation, regulation, market conditions, or initiatives of other electric power providers, particularly with respect to retail electric competition, could adversely affect our results of operations, cash flows and financial condition.

Propane. Our propane operations compete with other propane distributors, primarily on the basis of service and price. Our ability to grow the propane operations business is contingent upon capturing additional market share, expanding into new markets, and successfully utilizing pricing programs that retain and grow our customer base. Failure to retain and grow our customer base in our propane operations would have an adverse effect on our results of operations, cash flows and financial condition.

Fluctuations in weather may cause a significant variance in our earnings.

Our natural gas distribution, propane operations and natural gas transmission operations, are sensitive to fluctuations in weather conditions, which directly influence the volume of natural gas and propane we transport, sell and deliver to our customers. A significant portion of our natural gas distribution, propane operations and natural gas transmission revenue is derived from the sales and deliveries to residential, commercial and industrial heating customers during the five-month peak heating season (November through March). Other than our Maryland division and Sandpiper Energy which have revenue normalization mechanisms, if the weather is warmer than normal, we sell and deliver less natural gas and propane to customers, and earn less revenue, which could adversely affect our results of operations, cash flows and financial condition. Likewise, if the weather is colder than normal, we sell and deliver more natural gas and propane to customers, and earn more revenue, which could positively affect our results of operations, cash flows and financial condition. Variations in weather from year to year can cause our results of operations, cash flows and financial condition to vary accordingly.

Our electric distribution operation is also affected by variations in weather conditions and unusually severe weather conditions. However, electricity consumption is generally less seasonal than natural gas and propane because it is used for both heating and cooling in our service areas.

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

Inherent in energy transmission and distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, explosions, sabotage and mechanical problems. Natural disasters and severe weather may damage our assets, cause operational interruptions and result in the loss of human life, all of which could negatively affect our earnings, financial condition and results of operations. Acts of terrorism and the impact of retaliatory military and other action by the United States and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas, electricity and propane that could negatively affect our operations. Companies in the energy industry may face a heightened risk of exposure to acts of terrorism, which could affect our earnings, financial condition and results of operations. The insurance industry may also be affected by natural disasters, severe weather and acts of terrorism; as a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms, which could adversely affect our results of operations, financial condition and cash flows.

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

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

A security breach disrupting our operating systems and facilities or exposing confidential information may adversely affect our reputation, disrupt our operations and increase our costs.

We continue to heavily rely on technological tools that support our business operations and corporate functions. There are various risks associated with our information technology infrastructure, including hardware and software failure, communications failure,

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data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, cyber-attacks, cyber-terrorism, data breaches, programming mistakes, and other inadvertent errors or deliberate human acts. The failure of, or security breaches related to, our information technology infrastructure, could lead to system disruptions or cause facility shutdowns. If such a failure, attack, or security breach were to occur, our business, our earnings, results of operation and financial condition could be adversely affected. In addition, the protection of customer, employee and Company data is crucial to our operational security. A breach or breakdown of our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could have an adverse effect on our reputation, results of operations and financial condition and could also materially increase our costs of maintaining our system and protecting it against future breakdowns or breaches. We take reasonable precautions to safeguard our information systems from cyber-attacks and security breaches; however, there is no guarantee that the procedures implemented to protect against unauthorized access to our information systems are adequate to safeguard against all attacks and breaches. We also cannot assure that any redundancies built into our networks and technology, or the procedures we have implemented to protect against cyber-attacks and other unauthorized access to secured data, are adequate to safeguard against all failures of technology or security breaches.

Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.

Our ability to implement our business strategy and serve our customers depends upon our continuing ability to attract, develop and retain talented professionals and a technically skilled workforce, and transfer the knowledge and expertise of our workforce to new employees as our existing employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or the future availability and cost of contract labor could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.

A strike, work stoppage or a labor dispute could adversely affect our operations.

We are party to collective bargaining agreements with labor unions at some of our Florida operations. A strike, work stoppage or a labor dispute with a union or employees represented by a union could cause interruption to our operations and our results could be adversely affected.

Our businesses are capital-intensive, and the increased costs and/or delays of capital projects may adversely affect our future earnings.

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

Our regulated energy business may be at risk if franchise agreements are not renewed, or new franchise agreements are not obtained, which could adversely affect our future results or operating cash flows and financial condition.

Our regulated natural gas and electric distribution operations hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity. Ongoing financial results would be adversely impacted in the event that franchise agreements were not renewed. If we are unable to obtain franchise agreements for new service areas, growth in our future earnings could be negatively impacted.

Slowdowns in customer growth may adversely affect earnings and cash flows.

Our ability to increase gross margins in our natural gas, propane and electric distribution businesses is dependent upon growth in the residential construction market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other energy sources. Slowdowns in growth may adversely affect our results of operations, cash flows and financial condition.

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

Federal and state legislative and regulatory initiatives to promote energy efficiency, conservation and the use of alternative energy sources could lower energy consumption by our customers. In addition, higher costs of natural gas, propane and electricity may cause customers to conserve fuel. To the extent a PSC or the FERC does not allow the recovery through customer rates of higher costs or lower consumption from energy efficiency or conservation, and our propane margins cannot be increased due to market conditions, our results of operations, cash flows and financial condition may be adversely affected.

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

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

Propane. Propane costs are subject to changes as a result of product supply or other market conditions, including weather, economic and political factors affecting crude oil and natural gas supply or pricing. For example, weather conditions could damage production or transportation facilities, which could result in decreased supplies of propane, increased supply costs and higher prices for customers. Such increases in costs can occur rapidly and can negatively affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year-to-year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes due to reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.

Refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.

A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity or electric transmission capacity may impair our ability to meet customers’ existing and future requirements.

In order to meet existing and future customer demands for natural gas and electricity, we must acquire sufficient supplies of natural gas and electricity, interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate upstream transmission capacity for our distribution systems while considering the dynamics of the interstate pipeline and storage and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Our financial condition and results of operations would be materially and adversely affected if the future availability of these capacities were insufficient to meet future customer demands for natural gas and electricity. Currently, our Florida natural gas operation relies primarily on one pipeline system, FGT, for most of its natural gas supply and transmission. Our Florida electric operation secures electricity from external parties. Any continued interruption of service from these suppliers could adversely affect our ability to meet the demands of our customers, which could negatively impact our earnings, financial condition and results of operations.

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

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

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

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

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

In accordance with GAAP, goodwill is tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the goodwill and the implied fair value of the goodwill in the period the determination is made. The testing of goodwill for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These estimates can be affected by numerous factors, including: future business operating performance, changes in economic conditions and interest rates, regulatory, industry or market conditions, changes in business operations, changes in competition or changes in technologies. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more business segments, which may result in an impairment charge.

REGULATORY, LEGAL AND ENVIRONMENTAL RISKS

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

The Delaware, Maryland and Florida PSCs regulate our utility operations in those states. Eastern Shore is regulated by the FERC. The PSCs and the FERC set the rates that we can charge customers for services subject to their regulatory jurisdiction. Our ability to obtain timely future rate increases and rate supplements to maintain current rates of return depends on regulatory approvals, and there can be no assurance that our regulated operations will be able to obtain such approvals or maintain currently authorized rates of return. When earnings from our regulated utilities exceed the authorized rate of return, the respective regulatory authority may require us to reduce our rates charged to customers in the future.

We may face certain regulatory and financial risks related to pipeline safety legislation.

We are subject to a number of legislative proposals at the federal and state level to implement increased oversight over natural gas pipeline operations and facilities to inspect pipeline facilities, upgrade pipeline facilities, or control the impact of a breach of such facilities. Additional operating expenses and capital expenditures may be necessary to remain in compliance. If new legislation is adopted and we incur additional expenses and expenditures, our financial condition, results of operations and cash flows could be adversely affected, particularly if we are not authorized through the regulatory process to recover from customers some or all of these costs and our authorized rate of return.

We are subject to operating and litigation risks that may not be fully covered by insurance.

Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting, transmitting and delivering natural gas, electricity and propane to end users. From time to time, we are a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance coverage for our general liabilities in the amount of $51 million, which we believe is reasonable and prudent. However, there can be no assurance that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.

Costs of compliance with environmental laws may be significant.

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at our current and former operating sites, especially former MGP sites. To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former MGP sites. However, there is no guarantee that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs at former MGP sites could adversely affect our results of operations, cash flows and financial condition.

Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted and be applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable. Any such increase in compliance costs could adversely affect our financial condition and results of operations. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed civil or criminal penalties and fines, which could impact our financial condition and results of operations. See Item 8, Financial Statements and Supplementary Data (see Note 20, Environmental Commitments and Contingencies, in the consolidated financial statements).

Chesapeake Utilities Corporation 2019 Form 10-K Page 15

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Unanticipated changes in our tax provisions or exposure to additional tax liabilities could affect our profitability and cash flow.

We are subject to income and other taxes in the U.S. Changes in applicable U.S. tax laws and regulations, or their interpretation and application, including the possibility of retroactive effect, could affect our tax expense and profitability. In addition, the final determination of any tax audits or related litigation could be materially different from our historical income tax provisions and accruals. Changes in our tax provision or an increase in our tax liabilities, due to changes in applicable law and regulations, the interpretation or application thereof, future changes in the tax rate or a final determination of tax audits or litigation, could have a material adverse effect on our financial position, results of operations or cash flows.

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

There have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions, such as carbon dioxide. The direction of future U.S. climate change regulation is difficult to predict given the potential for policy changes under different Presidential administrations and Congressional leadership. The EPA may or may not continue developing regulations to reduce greenhouse gas emissions. Even if federal efforts in this area slow, states may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and reduce demand for our products. Federal or state legislative initiatives to implement renewable portfolio standards or to further subsidize the cost of solar, wind and other renewable power sources may change the demand for natural gas. We cannot predict the potential impact that such laws or regulations, if adopted, may have on our future business, financial condition or financial results.

Climate changes may impact the demand for our services in the future and could result in more frequent and more severe weather events, which ultimately could adversely affect our financial results.

Significant climatic change creates physical and financial risks for us. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of any changes. To the extent that climate change adversely impacts the economic health or weather conditions of our service territories directly, it could adversely impact customer demand or our customers’ ability to pay. Changes in energy use due to weather variations may affect our financial condition through volatility and/or decreased revenues and cash flows. Extreme weather conditions require more system backups and can increase costs and system stresses, including service interruptions. Severe weather impacts our operating territories primarily through thunderstorms, tornadoes, hurricanes, and snow or ice storms. Weather conditions outside of our operating territories could also have an impact on our revenues and cash flows by affecting natural gas prices. To the extent the frequency of extreme weather events increases, this could increase our costs of providing services. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for lawsuits related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate change, which could impact adversely our business, results of operations and cash flows.

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

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

ITEM 1B. UNRESOLVED STAFF COMMENTS.

None.

Chesapeake Utilities Corporation 2019 Form 10-K Page 16

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ITEM 2. Properties.

Offices and other operational facilities

We own or lease offices and other operational facilities in our service territories located in Delaware, Maryland, Virginia, Florida, Pennsylvania and Ohio.

Regulated Energy Segment

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

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

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

Unregulated Energy Segment

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

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

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

Florida liens

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

ITEM 3. Legal Proceedings.

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

ITEM 4. Mine Safety Disclosures.

Chesapeake Utilities Corporation 2019 Form 10-K Page 17

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Not applicable.

PART II

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

Common Stock Dividends and Stockholder Information:

Chesapeake Utilities common stock is traded on the New York Stock Exchange ("NYSE") under the ticker symbol CPK. As of February 20, 2020, we had 2,177 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $1.585 per share in 2019 and $1.435 per share in 2018, and have paid a cash dividend to our common stock stockholders for 59 consecutive years. Future dividend payments and amounts are at the discretion of our Board of Directors and will depend on our financial condition, results of operations, capital requirements, and other factors.

Indentures to our long-term debt contain various restrictions which limit our ability to pay dividends. FPU’s first mortgage bonds, which are due in 2022, contain a similar restriction that limits the payment of dividends by FPU. Refer to Item 8, Financial Statements and Supplementary Data (see Note 13, Long-Term Debt, in the consolidated financial statements) for additional information.

Purchases of Equity Securities by the Issuer

The following table sets forth information on purchases by us or on our behalf of shares of our common stock during the quarter ended December 31, 2019.



	Total Number of Shares Purchased	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs ⁽²⁾	Maximum Number of Shares That May Yet Be Purchased Under the Plans or Programs ⁽²⁾
Period
October 1, 2019 through October 31, 2019 ⁽¹⁾	406	$	94.79	—	—
November 1, 2019 through November 30, 2019	—	—		—	—
December 1, 2019 through December 31, 2019	—	—		—	—
Total	406	$	94.79	—	—

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

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 18

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Common Stock Performance Graph

The stock performance graph and table below compares cumulative total stockholder return on our common stock during the five fiscal years ended December 31, 2019, with the cumulative total stockholder return of the Standard & Poor’s 500 Index and the cumulative total stockholder return of select peers, which include the following companies: Atmos Energy Corporation; Black Hills Corporation; New Jersey Resources Corporation; NiSource Inc.; Northwest Natural Holding Company; NorthWestern Corporation; ONE Gas Inc.; RGC Resources, Inc.; South Jersey Industries, Inc.; Spire Inc. and Unitil Corporation.

The comparison assumes $100 was invested on December 31, 2014 in our common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of our common stock.



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

Chesapeake Utilities Corporation 2019 Form 10-K Page 19

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ITEM 6. SELECTED FINANCIAL DATA



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

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

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 20

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

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

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

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

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 21

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ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

This section provides management’s discussion of Chesapeake Utilities and its consolidated subsidiaries, with specific information on results of operations, liquidity and capital resources, as well as discussion of how certain accounting principles affect our financial statements. It includes management’s interpretation of our financial results and our operating segments, the factors affecting these results, the major factors expected to affect future operating results as well as investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto in Item 8, Financial Statements and Supplementary Data.

Several factors exist that could influence our future financial performance, some of which are described in Item 1A, Risk Factors. They should be considered in connection with forward-looking statements contained in this report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.

In the fourth quarter of 2019, we completed the previously announced sale of assets and contracts of PESCO and recorded a pre-tax gain of $7.3 million ($5.4 million after tax). As a result, PESCO’s results for all periods presented have been separately reported as discontinued operations and its assets and liabilities have been reclassified as held for sale where applicable.

The following discussions and those later in the document on operating income and segment results include the use of the term “gross margin," which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structures for unregulated energy operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 22

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OVERVIEW AND HIGHLIGHTS



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

Chesapeake Utilities Corporation 2019 Form 10-K Page 23

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2019 compared to 2018

Key variances in continuing operations between 2019 and 2018 included:



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

	(15,943		)	(11,853		)	(0.71		)
Other income tax effects	—			816			0.05
Interest charges	(6,078		)	(4,519		)	(0.27		)
Net Other changes	(1,125		)	(730		)	(0.07		)
Year ended December 31, 2019 Reported Results from Continuing Operations	$	82,233		$	61,142		$	3.72

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

* See the Major Projects and Initiatives table.

Chesapeake Utilities Corporation 2019 Form 10-K Page 24

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SUMMARY OF KEY FACTORS

Recently Completed and Ongoing Major Projects and Initiatives

We constantly pursue and develop additional projects and initiatives to serve existing and new customers, further grow our businesses and earnings, with the intention of increasing shareholder value. The following represent the major projects/initiatives recently completed and currently underway. In the future, we will add new projects and initiatives to this table once substantially finalized and the associated earnings can be estimated.



	Gross Margin for the Period
	Year Ended December 31,						Estimate for Fiscal
(in thousands)	2017		2018		2019		2020		2021
Expansions:
2017 Eastern Shore System Expansion - including interim services	$	483	$	9,103	$	16,434	$	15,799	$	15,799
Northwest Florida Expansion (including related natural gas distribution services)	—		4,350		6,516		6,500		6,500
Western Palm Beach County, Florida Expansion	—		54		2,139		5,047		5,227
Del-Mar Energy Pathway - including interim services	—		—		731		2,512		4,100
Auburndale	—		—		283		679		679
Callahan Intrastate Pipeline	—		—		—		3,219		6,400
Guernsey Power Station	—		—		—		—		1,400
Total Expansions	483		13,507		26,103		33,756		40,105
Acquisitions:
Marlin Gas Services	—		110		5,410		6,400		7,000
Ohl Propane	—		—		1,200		1,236		1,250
Boulden Propane	—		—		329		4,000		4,200
Elkton Gas Company	—		—		—		TBD ⁽⁴⁾		TBD
Total Acquisitions	—		110		6,939		11,636		12,450
Regulatory Initiatives:
Florida GRIP^{(1) (2)}	13,454		13,020		13,528		14,858		15,831
Tax benefit retained by certain Florida entities⁽³⁾	—		—		2,740		1,400		1,500
Hurricane Michael regulatory proceeding	—		—		—		TBD		TBD
Total Regulatory Initiatives	13,454		13,020		16,268		16,258		17,331

Total	$	13,937	$	26,637	$	49,310	$	61,650	$	69,886

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

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

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

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

Detailed Discussion of Major Projects and Initiatives

Expansions

2017 Eastern Shore System Expansion

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 25

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Northwest Florida Expansion

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

Western Palm Beach County, Florida Expansion

Peninsula Pipeline is constructing four transmission lines to bring additional natural gas to our distribution system in West Palm Beach, Florida. The first phase of this project was placed into service in December 2018 and generated incremental gross margin of $2.1 million during 2019 compared to 2018. We expect to complete the remainder of the project in phases through early 2020, and estimate that the project will generate gross margin of $5.0 million in 2020 and $5.2 million annually thereafter.

Del-Mar Energy Pathway

In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021. The new facilities will provide an additional 14,300 Dts/d of firm service to four customers, will provide additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and it will represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Interim services in advance of this project generated gross margin of $0.7 million for the year ended December 31, 2019. The estimated annual gross margin from this project is approximately $2.5 million in 2020, $4.1 million in 2021 and $5.1 million annually thereafter.

Auburndale

In August 2019, the Florida PSC approved Peninsula Pipeline's Transportation Service Agreement with the Florida Division of Chesapeake Utilities. Peninsula Pipeline purchased an existing pipeline owned by the Florida Division of Chesapeake Utilities and Calpine and constructed pipeline facilities in Polk County, Florida. Peninsula Pipeline will provide transportation service to the Florida Division of Chesapeake Utilities increasing both delivery capacity and downstream pressure as well as introducing a secondary source of natural gas for the Florida Division of Chesapeake Utilities' distribution system. Peninsula Pipeline generated gross margin from this project of $0.3 million for the year ended December 31, 2019 and expects to generate annual gross margin of $0.7 million in 2020 and beyond.

Callahan Intrastate Pipeline

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

Guernsey Power Station

Guernsey Power Station, LLC ("Guernsey Power Station") and our affiliate, Aspire Energy Express, LLC ("Aspire Energy Express"), entered into a precedent firm transportation capacity agreement whereby Guernsey Power Station will construct a power generation facility and Aspire Energy Express will provide natural gas transportation service to this facility. Guernsey Power Station commenced construction of the project in October 2019. Aspire Energy Express is expected to commence construction of the gas transmission facilities to provide the firm transportation service to the power generation facility in the third quarter of 2020. This project is expected to produce gross margin of approximately $1.4 million annually once placed into service in the first quarter of 2021.

Acquisitions

Marlin Gas Services

In December 2018, Marlin Gas Services, our wholly-owned subsidiary, acquired certain operating assets of Marlin Gas Transport, a supplier of mobile CNG and pipeline solutions, primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. Marlin Gas Services generated incremental gross margin of $5.3 million in 2019 compared to 2018. We estimate that Marlin Gas Services will generate annual gross margin of approximately $6.4 million in 2020 and $7.0 million in 2021 and beyond. Marlin Gas Services continues to actively expand the territories it serves, as well as leverage its patented technology to serve liquefied natural gas transportation needs and to aid in the transportation of renewable natural gas from the supply sources to various pipeline interconnection points.

Chesapeake Utilities Corporation 2019 Form 10-K Page 26

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Ohl Propane

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

Boulden Propane

In December 2019, Sharp acquired certain propane customers and operating assets of Boulden which provides propane distribution service to approximately 5,200 customers in Delaware, Maryland and Pennsylvania. The customers and assets acquired from Boulden have been assimilated into Sharp. The operations acquired from Boulden generated $0.3 million of incremental gross margin for 2019. We estimate that this acquisition will generate additional gross margin of approximately $4.0 million in 2020, and $4.2 million in 2021, with the potential for additional growth in future years.

Elkton Gas Company

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

Regulatory Initiatives

Florida GRIP

Florida GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic recovery, through rates, of costs associated with the replacement of mains and services. Since the program's inception in August 2012, we have invested $143.9 million of capital expenditures to replace 303 miles of qualifying distribution mains, including $16.7 million and $13.3 million of new pipes during 2019 and 2018, respectively. GRIP generated additional gross margin of $0.5 million in 2019 compared to 2018.

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

Florida Tax Savings Related to the TCJA

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

Hurricane Michael

In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane caused widespread and severe damage to FPU's infrastructure resulting in 100 percent of its customers in the Northwest Florida service territory losing electrical service. FPU expended more than $65.0 million to restore service as quickly as possible, which has been recorded as new plant and equipment, charged against FPU’s accumulated depreciation or charged against FPU’s storm reserve. Additionally, amounts currently being reviewed by the Florida PSC for regulatory asset treatment have been recorded as receivables and other deferred charges.

In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (plant investment and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as a regulatory asset for items currently not allowed to be recovered through the storm reserve as well as the recovery of plant investment replaced as a result of the storm. FPU has proposed an overall return component on both the plant additions and regulatory assets. In the fourth quarter of 2019, FPU along with the Office of Public Counsel in Florida, filed a joint motion with the Florida PSC to approve an interim rate increase, subject to refund, pending the final ruling on the recovery of the restoration costs incurred. The petition was approved by the Florida PSC in November 2019 and interim rate increases were implemented effective January 2020. FPU continues to work with the Florida PSC and expects to reach a final ruling in the second half of 2020.

Chesapeake Utilities Corporation 2019 Form 10-K Page 27

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Other Major Factors Influencing Gross Margin

Weather and Consumption

Weather conditions accounted for decreased gross margin of $4.9 million in 2019 compared to 2018 and $3.4 million compared to Normal temperatures as defined below. The following table summarizes heating degree day ("HDD") and cooling degree day (“CDD”) variances from the 10-year average HDD/CDD ("Normal") for the year ended December 31, 2019 compared to 2018.

HDD and CDD Information



	For the Years Ended December 31,
	2019		2018		Variance		2018		2017		Variance
Delmarva
Actual HDD	4,089		4,251		(162	)	4,251		3,800		451
10-Year Average HDD ("Normal")	4,323		4,379		(56	)	4,379		4,374		5
Variance from Normal	(234	)	(128	)			(128	)	(574	)

Florida
Actual HDD	619		780		(161	)	780		533		247
10-Year Average HDD ("Normal")	792		800		(8	)	800		818		(18	)
Variance from Normal	(173	)	(20	)			(20	)	(285	)

Ohio
Actual HDD	5,498		5,845		(347	)	5,845		5,126		719
10-Year Average HDD ("Normal")	5,983		5,823		160		5,823		5,914		(91	)
Variance from Normal	(485	)	22				22		(788	)

Florida
Actual CDD	3,200		3,105		95		3,105		3,013		92
10-Year Average CDD ("Normal")	2,939		2,889		50		2,889		2,865		24
Variance from Normal	261		216				216		148

Natural Gas Distribution Margin Growth

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



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

Chesapeake Utilities Corporation 2019 Form 10-K Page 28

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REGULATED ENERGY



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

2019 compared to 2018

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

Gross Margin

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



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

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

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

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

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


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


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


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

Chesapeake Utilities Corporation 2019 Form 10-K Page 29

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Natural Gas Customer Growth

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

2018 Retained Tax Savings for Florida Natural Gas Operations

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

Tax Reform Impact

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

Sandpiper's Margin Primarily from Natural Gas Conversions

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

Florida GRIP

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

Impact of Weather on Customer Consumption

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

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



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

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

2018 compared to 2017

The results for the Regulated Energy segment for the year ended December 31, 2018 compared 2017 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2018.

Chesapeake Utilities Corporation 2019 Form 10-K Page 30

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UNREGULATED ENERGY



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

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

2019 Compared to 2018

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

Gross Margin

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



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

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

Acquisitions

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

Propane Operations


•	Increased Retail Propane Margins - Gross margin increased by $3.2 million, due to lower propane inventory costs and favorable market conditions. These market conditions, which include competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices.


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


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

Chesapeake Utilities Corporation 2019 Form 10-K Page 31

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•

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


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

Aspire Energy


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

Eight Flags


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

Other Operating Expenses

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



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

2018 compared to 2017

The results for the Unregulated Energy segment for the year ended December 31, 2018 compared 2017 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2018.

Divestiture of PESCO

As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts and accordingly have exited the natural gas marketing business. This was done in an effort to enable us to focus on the strategies that support our core energy delivery business. We executed four separate transactions associated with the sale of PESCO’s assets and contracts:


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


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


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


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

As a result of the sales agreements, we began to report PESCO as discontinued operations during the third quarter of 2019 and excluded PESCO's performance from continuing operations for all periods presented and classified its assets and liabilities as held for sale, where applicable. PESCO's results for the year ended December 31, 2018 compared to 2017 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations of our Annual Report on Form 10-K for the year ended December 31, 2018.

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

Chesapeake Utilities Corporation 2019 Form 10-K Page 32

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OTHER EXPENSE, NET

Other expense, net was $1.8 million and $0.6 million for 2019 and 2018, respectively. Other expense, net includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets for our unregulated businesses and pension and other benefits expense. The increase in other expense, net in 2019 was due to higher pension expense as well as pension settlement expense associated with the de-risking of the Chesapeake Pension Plan see Note 17, Employee Benefit Plans, for additional information.

INTEREST CHARGES

2019 Compared to 2018

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



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

INCOME TAXES

2019 Compared to 2018

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

LIQUIDITY AND CAPITAL RESOURCES

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

Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered by our distribution operations, and our natural gas transmission operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $199.0 million (including the purchase of certain propane assets of Boulden) in 2019 and $282.9 million in 2018 (including the purchase of certain assets from Marlin Gas Services and Ohl). The 2018 capital expenditures also includes over $60.0 million of restoration costs associated with repairing damages caused by Hurricane Michael to our electric distribution operations’ service territory in Northwest Florida.

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



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

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

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



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

The 2020 budget, excluding acquisitions, includes: Eastern Shore's Del-Mar Energy Pathway Project, Florida's Callahan and Palm Beach County Western Expansion and other potential pipeline projects, continued expenditures under Florida GRIP, further expansions of our natural gas distribution and transmission systems, continued natural gas infrastructure improvement activities, information technology systems, and other strategic initiatives and investments.

The capital expenditure projection is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities, availability of capital and other factors discussed in Item 1A. Risk Factors.

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

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Capital Structure

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

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



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



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

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

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

Term Notes

In December 2018, we issued a $30.0 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. This note was paid off in December 2019 utilizing the proceeds from the issuance of uncollateralized senior notes discussed below. In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. The interest rate, at December 31, 2019, was 2.46%, which equals the one-month LIBOR rate plus 75 basis points. As of December 31, 2019, this term note is included in the current maturities of long-term debt.

Uncollateralized Senior Notes

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

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

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Shelf Agreements

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

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

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



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

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

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

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

Short-Term Borrowings

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

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

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

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

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



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

As of December 31, 2019, we had issued $5.0 million in letters of credit to various counterparties under the Revolver. Although the letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties, the letters of credit reduce the available borrowings under the Revolver.

Cash Flows

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



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

Cash Flows Provided by Operating Activities

Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items, such as depreciation and changes in deferred income taxes, and changes in working capital. Working capital requirements are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.

We normally generate a large portion of our annual net income and related increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered to customers during the peak heating season by our natural gas and propane operations and our natural gas supply, gathering and processing operation to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

During 2019 and 2018, net cash provided by operating activities was $103.0 million and $117.4 million, respectively, resulting in a decrease in cash flows of $14.4 million. Significant operating activities generating the cash flows change were as follows:

•

Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $45.1 million, in part due to the absence of PESCO which ceased invoicing the majority of its former customers during the middle of the fourth quarter of 2019 and had also settled most of its outstanding vendor obligations at December 31, 2019. The remainder of the decrease was primarily driven by the timing of the receipt of payments from continuing operations.


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


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

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


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


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

Cash Flows Used in Investing Activities

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


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


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


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

Cash Flows Provided by Financing Activities

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


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

•

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


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


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


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

CONTRACTUAL OBLIGATIONS

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



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

⁽¹⁾ This represents principal payments on long-term debt. See Item 8, Financial Statements and Supplementary Data, Note 13, Long-Term Debt, for additional information. The expected interest payments on long-term debt are $17.5 million, $31.9 million, $27.7 million and $94.4 million, respectively, for the periods indicated above. Expected interest payments for all periods total $171.5 million.

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

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

⁽⁴⁾ These amounts associated with our unfunded post-employment and post-retirement benefit plans are based on expected payments to current retirees and assume a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early

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retirement, future health care costs that differ from past experience and discount rates implicit in calculations. See Item 8, Financial Statements and Supplementary Data, Note 17, Employee Benefit Plans, for additional information on the plans.

⁽⁵⁾ We have recorded long-term liabilities of $17.2 million at December 31, 2019 for two qualified, defined benefit pension plans. The assets funding these plans are in a separate trust and are not considered assets of ours or included in our balance sheets. The Contractual Obligations table above includes $3.5 million, reflecting the payments we expect to make to the trust funds in 2020. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8, Financial Statements and Supplementary Data, Note 17, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $9.2 million, funded with Rabbi Trust assets in the same amount. The Rabbi Trust assets are recorded under Investments on the consolidated balance sheets. We assume a retirement age of 65 for purposes of distribution from this trust.

OFF-BALANCE SHEET ARRANGEMENTS

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

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

We have issued letters of credit totaling $5.4 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carrier with expiration dates extending through October 22, 2020. There were no draws on these letters of credit as of December 31, 2019. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 21, Other Commitments and Contingencies in the consolidated financial statements.

CRITICAL ACCOUNTING POLICIES

We prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. We base our estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since a significant portion of our businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.

Regulatory Assets and Liabilities

As a result of the ratemaking process, we record certain assets and liabilities in accordance with ASC Topic 980, Regulated Operations, and consequently, the accounting principles applied by our regulated energy businesses differ in certain respects from those applied by the unregulated businesses. Amounts are deferred as regulatory assets and liabilities when there is a probable expectation that they will be recovered in future revenues or refunded to customers as a result of the regulatory process. This is more fully described in Item 8, Financial Statements and Supplementary Data, Note 2, Summary of Significant Accounting Policies, in the consolidated financial statements. If we were required to terminate the application of ASC Topic 980, we would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material effect on our results of operations.

Valuation of Environmental Liabilities and Related Regulatory Assets

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

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Derivative Instruments

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

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

We determined that certain propane put options, call options, swap agreements and natural gas futures contracts met the specific hedge accounting criteria. We also determined that most of our contracts for the purchase or sale of natural gas, electricity and propane either: (i) did not meet the definition of derivatives because they did not have a minimum purchase/sell requirement, or (ii) were considered “normal purchases and normal sales” because the contracts provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities that we expect to use or sell over a reasonable period of time in the normal course of business. Accordingly, these contracts were accounted for on an accrual basis of accounting.

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

Operating Revenues

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC of each state in which we operate. Customers’ base rates may not be changed without formal approval by these PSCs. However, the PSCs authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.

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

For regulated deliveries of natural gas, propane and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters, such as community gas system customers and natural gas marketing customers, whose billing cycles do not coincide with the accounting periods.

Our natural gas supply operation in Ohio recognizes revenues based on actual volumes of natural gas shipped, using contractual rates, which are based upon index prices that are published monthly.

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

Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.

Each of our natural gas distribution operations in Delaware and Maryland, our bundled natural gas distribution service in Florida and our electric distribution operation in Florida has a fuel cost recovery mechanism. This mechanism provides a method of adjusting billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

We charge flexible rates to industrial interruptible customers on our natural gas distribution systems to compete with the price of alternative fuel that they can use. Neither we, nor any of our interruptible customers, are contractually obligated to deliver or receive natural gas on a firm service basis.

Allowance for Doubtful Accounts

An allowance for doubtful accounts is recorded against amounts due to reduce the net receivable balance to the amount we reasonably expect to collect based upon our collections experience, the condition of the overall economy and our assessment of

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our customers’ inability or reluctance to pay. If circumstances change, however, our estimate of the recoverability of accounts receivable may also change. Circumstances which could affect our estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off once they are deemed to be uncollectible.

Goodwill and Other Intangible Assets

We test goodwill for impairment at least annually in December. The annual impairment testing for 2019 indicated no impairment of goodwill. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 11, Goodwill and Other Intangible Assets, in the consolidated financial statements.

Other Assets Impairment Evaluations

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

Pension and Other Postretirement Benefits

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

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

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

Tax-Related Contingency

We account for uncertainty in income taxes in the consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on its technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.

We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and quantifiable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities.

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

INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. Additional information

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

COMMODITY PRICE RISK

Regulated Energy Segment

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

Unregulated Energy Segment

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

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

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

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



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

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

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



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

WHOLESALE CREDIT RISK

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

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

INFLATION

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

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Stockholders of

Chesapeake Utilities Corporation

Opinions on the Consolidated Financial Statements and Internal Control over Financial Reporting

We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation and Subsidiaries (the "Company") as of December 31, 2019 and 2018, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the years in the three-year period ended December 31, 2019, and the related notes and financial statement schedule listed in Item 15(a)2 (collectively referred to as the "consolidated financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework: (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”).

In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of their operations and their cash flows for each of the years in the three-year period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework: (2013) issued by COSO.

Basis for Opinion

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

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

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

Definition and Limitations of Internal Control Over Financial Reporting

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

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

Critical Audit Matter

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

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

Critical Audit Matter Description

As described in Notes 1 and 11 to the consolidated financial statements, the Company has recorded approximately $29.3 million of goodwill within the Unregulated Energy reportable segment as of December 31, 2019, all of which relates to the four reporting units listed above. To test goodwill for impairment, the Company uses a present value technique based on discounted cash flows to estimate the fair value of its reporting units. Management’s testing of goodwill for 2019 indicated no impairment.

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

How the Critical Audit Matter was Addressed in the Audit

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


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


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


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


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


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


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

/s/ Baker Tilly Virchow Krause, LLP

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

Philadelphia, Pennsylvania

February 26, 2020

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Income

	For the Year Ended December 31,
	2019			2018			2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	343,006		$	345,281		$	326,310
Unregulated Energy	154,150			161,904			140,076
Other businesses and eliminations	(17,552		)	(16,869		)	(16,740		)
Total operating revenues	479,604			490,316			449,646
Operating Expenses
Regulated Energy cost of sales	102,803			121,828			118,769
Unregulated Energy and other cost of sales	51,697			68,342			53,420
Operations	137,844			132,523			121,949
Maintenance	15,679			14,387			12,701
Gain from a settlement	(130		)	(130		)	(130		)
Depreciation and amortization	45,423			40,220			36,386
Other taxes	20,001			18,303			16,821
Total operating expenses	373,317			395,473			359,916
Operating Income	106,287			94,843			89,730
Other expense, net	(1,830		)	(603		)	(2,204		)
Interest charges	22,224			16,146			12,530
Income from Continuing Operations Before Income Taxes	82,233			78,094			74,996
Income Taxes on Continuing Operations	21,091			21,232			14,670
Income from Continuing Operations	61,142			56,862			60,326
Loss from Discontinued Operations, Net of tax	(1,391		)	(282		)	(2,202		)
Gain on sale of Discontinued Operations, Net of tax	5,402			—			—
Net Income	$	65,153		$	56,580		$	58,124

Weighted Average Common Shares Outstanding:
Basic	16,398,443			16,369,616			16,336,789
Diluted	16,448,486			16,419,870			16,383,352
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	3.73		$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)
Basic Earnings Per Share of Common Stock	$	3.97		$	3.46		$	3.56

Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	3.72		$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24			(0.02		)	(0.13		)
Diluted Earnings Per Share of Common Stock	$	3.96		$	3.45		$	3.55

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

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Comprehensive Income

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

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

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets

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

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

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Balance Sheets

	As of December 31,
Capitalization and Liabilities	2019			2018
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—		$	—
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	7,984			7,971
Additional paid-in capital	259,253			255,651
Retained earnings	300,607			261,530
Accumulated other comprehensive loss	(6,267		)	(6,713		)
Deferred compensation obligation	4,543			3,854
Treasury stock	(4,543		)	(3,854		)
Total stockholders’ equity	561,577			518,439
Long-term debt, net of current maturities	440,168			316,020
Total capitalization	1,001,745			834,459
Current Liabilities
Current portion of long-term debt	45,600			11,935
Short-term borrowing	247,371			294,458
Accounts payable	54,068			98,681
Customer deposits and refunds	30,939			32,620
Accrued interest	2,554			2,317
Dividends payable	6,644			6,060
Accrued compensation	16,236			13,923
Regulatory liabilities	5,991			7,883
Derivative liabilities, at fair value	1,844			1,604
Other accrued liabilities	12,077			10,081
Current liabilities held for sale	—			48,672
Total current liabilities	423,324			528,234
Deferred Credits and Other Liabilities
Deferred income taxes	180,656			156,820
Regulatory liabilities	127,744			135,039
Environmental liabilities	6,468			7,638
Other pension and benefit costs	30,569			28,513
Operating lease - liabilities	9,896			—
Deferred investment tax credits and other liabilities	2,796			2,968
Total deferred credits and other liabilities	358,129			330,978
Environmental and other commitments and contingencies (Note 20 and 21)
Total Capitalization and Liabilities	$	1,783,198		$	1,693,671

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

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Cash Flows

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

Supplemental Cash Flow Disclosures (see Note 7)

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

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Chesapeake Utilities Corporation and Subsidiaries Consolidated Statements of Stockholders' Equity

	Common Stock ⁽¹⁾
(in thousands, except shares and per share data)	Number of Shares⁽²⁾	Par Value		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total
Balance at December 31, 2016	16,303,499	$	7,935	$	250,967		$	192,062		$	(4,878	)	$	2,416	$	(2,416	)	$	446,086
Net Income	—	—		—			58,124			—			—		—			58,124
Other comprehensive income	—	—		—			—			606			—		—			606
Dividends declared ($1.2800 per share)	—	—		—			(21,045		)	—			—		—			(21,045		)
Retirement savings plan and dividend reinvestment plan	10,771	5		730			—			—			—		—			735
Stock issuance ⁽³⁾	—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit ^{(4) (5)}	30,172	15		1,783			—			—			—		—			1,798
Treasury stock activities⁽²⁾	—	—		—			—			—			979		(979		)	—
Balance at December 31, 2017	16,344,442	7,955		253,470			229,141			(4,272		)	3,395		(3,395		)	486,294
Net Income	—	—		—			56,580			—			—		—			56,580
Cumulative effect of the adoption of ASU 2014-09	—	—		—			(1,498		)	—			—		—			(1,498		)
Reclassification upon the adoption of ASU 2018-02	—	—		—			907			(907		)	—		—			—
Other comprehensive income	—	—		—			—			(1,534		)	—		—			(1,534		)
Dividends declared ($1.4350 per share)	—	—		—			(23,600		)	—			—		—			(23,600		)
Dividend reinvestment plan	—	—		(3		)	—			—			—		—			(3		)
Share-based compensation and tax benefit ^{(4) (5)}	34,103	16		2,184			—			—			—		—			2,200
Treasury stock activities⁽²⁾	—	—		—			—			—			459		(459		)	—
Balance at December 31, 2018	16,378,545	7,971		255,651			261,530			(6,713		)	3,854		(3,854		)	518,439
Net Income	—	—		—			65,153			—			—		—			65,153
Prior period reclassification	—	—					115			(115		)	—		—			—
Other comprehensive income	—	—		—						561			—		—			561
Dividends declared ($1.585 per share)	—	—		—			(26,191		)	—			—		—			(26,191		)
Dividend reinvestment plan	—	—		(3		)	—			—			—		—			(3		)
Share-based compensation and tax benefit ^{(4) (5)}	25,231	13		3,605			—			—			—		—			3,618
Treasury stock activities ⁽²⁾	—	—		—			—			—			689		(689		)	—
Balances at December 31, 2019	16,403,776	$	7,984	$	259,253		$	300,607		$	(6,267	)	$	4,543	$	(4,543	)	$	561,577

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

⁽²⁾ Includes 95,329, 97,053 and 90,961 shares at December 31, 2019, 2018 and 2017, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

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

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

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

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

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Notes to the Consolidated Financial Statements

1. ORGANIZATION AND BASIS OF PRESENTATION

Chesapeake Utilities, incorporated in 1947 in Delaware, is a diversified energy company engaged in regulated and unregulated energy businesses.

Our regulated energy businesses consist of: (a) regulated natural gas distribution operations in central and southern Delaware, Maryland’s eastern shore and Florida; (b) regulated natural gas transmission operations on the Delmarva Peninsula, in Pennsylvania and in Florida; and (c) regulated electric distribution operations serving customers in northeast and northwest Florida.

Our unregulated energy businesses primarily include: (a) propane operations in the Mid-Atlantic region and Florida; (b) our unregulated natural gas transmission/supply operation in central and eastern Ohio; (c) our CHP plant in Florida that generates electricity and steam; and (d) our subsidiary, based in Florida, that provides CNG and pipeline solutions, primarily to utilities and pipelines throughout the eastern United States.

Our consolidated financial statements include the accounts of Chesapeake Utilities and its wholly-owned subsidiaries. We do not have any ownership interest in investments accounted for using the equity method or any interest in a variable interest entity. All intercompany accounts and transactions have been eliminated in consolidation. We have assessed and, if applicable, reported on subsequent events through the date of issuance of these consolidated financial statements. Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Beginning in the third quarter of 2019, our management began executing a strategy to sell the operating assets of PESCO. In connection with this strategy, during the third and fourth quarter of 2019, we reached agreements with four entities to sell PESCO's assets and contracts. These transactions closed during the fourth quarter of 2019. As a result of the sale, we have fully exited the natural gas marketing business, which provided natural gas management and supply services to commercial and industrial customers in Florida, Delaware, Maryland, Pennsylvania, Ohio and other states. Accordingly, PESCO’s historical financial results are reflected in our consolidated financial statements as discontinued operations, which required retrospective application to financial information for all periods presented. Refer to Note 4, Acquisitions and Divestitures for further information.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Use of Estimates

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

Property, Plant and Equipment

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

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

Contributions or Advances in Aid of Construction

Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2019 and 2018, the non-refundable contributions totaled $2.1 million and $2.8 million, respectively.

AFUDC

Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for ratemaking purposes when the completed projects are placed in service. During the years ended December 31, 2019 and 2018, AFUDC totaled $0.7 million and $1.9 million, respectively, which was reflected as a reduction of interest charges. During the year ended December 31, 2017, AFUDC was not material.

Leases

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

Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 15, Leases for additional information.

Jointly-owned Pipelines

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Notes to the Consolidated Financial Statements

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

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

Asset Impairment Evaluations

We periodically evaluate whether events or circumstances have occurred, which indicate that other long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.

Depreciation and Accretion Included in Operations Expenses

We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2019, 2018 and 2017:



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

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



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

We report certain depreciation and accretion in operations expense, rather than as a depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2019, 2018 and 2017, we reported $8.8 million, $8.5 million and $8.1 million, respectively, of depreciation and accretion in operations expenses.

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Notes to the Consolidated Financial Statements

Regulated Operations

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

We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980, Regulated Operations, continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.

Revenue Recognition

Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates.

For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class.

All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms, except for two utilities that provide only unbundled delivery service (Chesapeake Utilities' Central Florida Gas division and FPU's Indiantown division). These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.

We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis.

Our unregulated propane delivery businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses.

Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly.

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

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.

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Operations and Maintenance Expenses

Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses.

Cash and Cash Equivalents

Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.

Accounts Receivable and Allowance for Doubtful Accounts

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

Inventories

We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There was no lower-of-cost-or-net realizable value adjustment during 2019, 2018 or 2017.

Goodwill and Other Intangible Assets

Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its implied fair value. The testing of goodwill for 2019, 2018 and 2017 indicated no goodwill impairment. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.

Other Deferred Charges

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

Asset Removal Cost

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

Pension and Other Postretirement Plans

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

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

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as the Prudential curve index and the FTSE Pension Discount curve, formerly the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.

The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.

We estimate the health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.

The mortality assumption used for our pension and postretirement plans is reviewed periodically and is based on the actuarial table that best reflects the expected mortality of the plan participants.

Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency

Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.

We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.

We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities.

Financial Instruments

Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging, it is recorded at fair value with all gains or losses being recorded directly in earnings.

Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and sales” treatment under ASC Topic 815 Derivatives and Hedging, and are accounted for on an accrual basis.

Recently Adopted Accounting Standards

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

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

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

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

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

Recent Accounting Standards Yet to be Adopted

Financial Instruments - Credit Losses (ASC 326) - In June 2016, the FASB issued ASU 2016-13, Measurement of Credit Losses on Financial Instruments, which changes how entities account for credit losses for most financial assets and certain other instruments, and subsequent guidance which served to clarify or amend the original standard. ASU 2016-13 and the related amendments require entities to estimate lifetime expected credit losses for trade receivables and to provide additional disclosure related to credit losses. ASU 2016-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and is not expected to have a material impact on our financial position or results of operations.

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

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

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3. EARNINGS PER SHARE

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



	For the Year Ended December 31,
	2019		2018			2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	61,142	$	56,862		$	60,326
Income/(Loss) from Discontinued Operations	4,011		(282		)	(2,202		)
Net Income	$	65,153	$	56,580		$	58,124

Weighted average shares outstanding	16,398,443		16,369,616			16,336,789
Earnings Per Share from Continuing Operations	$	3.73	$	3.48		$	3.69
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Basic Earnings Per Share	$	3.97	$	3.46		$	3.56

Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding — Basic	16,398,443		16,369,616			16,336,789
Effect of dilutive securities — Share-based compensation	50,043		50,254			46,563
Adjusted denominator — Diluted	16,448,486		16,419,870			16,383,352
Earnings Per Share from Continuing Operations	$	3.72	$	3.47		$	3.68
Earnings/(Loss) Per Share from Discontinued Operations	0.24		(0.02		)	(0.13		)
Diluted Earnings Per Share	$	3.96	$	3.45		$	3.55

4. ACQUISITIONS AND DIVESTITURES

Acquisition of Elkton Gas Company

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

Acquisitions in 2019

In December 2019, Sharp acquired certain propane operating assets of Boulden which provides propane distribution service to approximately 5,200 customers in Delaware, Maryland and Pennsylvania, for approximately $24.6 million, net of cash acquired. Additionally, the purchase price included $0.2 million of working capital. We recorded contingent consideration of $0.6 million related to the seller's adherence to various provisions contained in the contract through the first anniversary of the transaction closing. We accounted for the purchase of the operating assets of Boulden as a business combination within our Unregulated Energy segment. In connection with this acquisition, we recorded $8.3 million in property, plant and equipment, $5.1 million in intangible assets associated with customer relationships and non-compete agreements and $11.2 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary and subject to adjustment based on contractual provisions that will be finalized at the end of the measurement period. Contributions to our operating revenues and operating income as a result of this acquisition for the year ended December 31, 2019 can be found in the table below.

Acquisitions in 2018

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

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emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. These services are provided by a highly trained staff of drivers and maintenance technicians who safely perform these functions throughout the eastern United States. Marlin Gas Services maintains a fleet of steel tube CNG trailers, composite CNG trailers, mobile compression equipment and an internally-developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas.

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

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



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

Divestiture of PESCO

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


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


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


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


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

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

As a result of the sales agreements, we began to report PESCO as discontinued operations during the third quarter of 2019 and excluded PESCO's performance from continuing operations for all periods presented and classified its assets and liabilities as held for sale. The assets and liabilities of PESCO are presented as current and noncurrent assets and liabilities of a business held for sale in the consolidated balance sheets.

Additionally, amounts for operating revenues and costs of sales which had previously been eliminated in consolidation related to intercompany sales and purchases have been grossed up and are now reflected as a component of operating revenues and costs of sales for all periods presented. We have recast these amounts because, upon completion of the sales transactions, we will continue to provide and receive services from the buyers.

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



	For the Year Ended December 31,
(in thousands)	2019			2018			2017
Operating revenues⁽¹⁾	$	161,289		$	258,713		$	184,519
Cost of sales⁽¹⁾	157,646			252,111			182,307
Other operating expenses	5,222			6,825			4,522
Operating loss	(1,579		)	(223		)	(2,310		)
Interest and other expense	315			297			253
Loss from Discontinued Operations before income taxes	(1,894		)	(520		)	(2,563		)
Gain on sale of Discontinued Operations	7,344			—			—
Income tax (benefit) / expense	1,439			(238		)	(361		)
Gain / (Loss) from Discontinued Operations, Net of Tax	$	4,011		$	(282	)	$	(2,202	)

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

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



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

Current liabilities ⁽³⁾	$	48,672
Liabilities of Discontinued Operations held for sale	$	48,672
Net assets	$	11,671

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

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

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

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



	For the Year Ended December 31,
(in thousands)	2019			2018		2017
Depreciation and amortization	$	477		$	582	$	213
Property, plant and equipment expenditures	—			115		11,766
Deferred income taxes	(125		)	1,088		(1,515		)
Realized / (loss) gain on commodity contracts	(2,161		)	5,002		4,911

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

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and capacity arrangements with PESCO which were included in the assets sold to UET. Eastern Shore will continue to fulfill these arrangements throughout the remainder of their contractual term. These agreements currently have expiration dates of March 31, 2020 and November 30, 2021.

5. REVENUE RECOGNITION

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

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	For the Year Ended December 31, 2019												For the Year Ended December 31, 2018
(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total			Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Delaware natural gas division	$	62,659		$	—		$	—		$	62,659		$	70,338		$	—		$	—		$	70,338
Florida natural gas division	28,485			—			—			28,485			25,341			—			—			25,341
FPU electric distribution	77,416			—			—			77,416			79,803			—			—			79,803
FPU natural gas distribution	82,418			—			—			82,418			81,118			—			—			81,118
Maryland natural gas division	22,517			—			—			22,517			24,172			—			—			24,172
Sandpiper natural gas/propane operations	19,068			—			—			19,068			22,088			—			—			22,088
Total energy distribution	292,563			—			—			292,563			302,860			—			—			302,860

Energy transmission
Aspire Energy	—			32,493			—			32,493			—			35,407			—			35,407
Eastern Shore	72,924			—			—			72,924			64,248			—			—			64,248
Peninsula Pipeline	16,453			—			—			16,453			11,927			—			—			11,927
Total energy transmission	89,377			32,493			—			121,870			76,175			35,407			—			111,582

Energy generation
Eight Flags	—			16,749			—			16,749			—			17,302			—			17,302

Propane operations
Propane delivery operations	—			107,964			—			107,964			—			123,603			—			123,603

Energy delivery services
Marlin Gas Services	—			5,702			—			5,702			—			121			—			121

Other and eliminations
Eliminations	(38,934		)	(10,407		)	(18,080		)	(67,421		)	(33,754		)	(16,486		)	(17,522		)	(67,762		)
Other	—			1,649			528			2,177			—			1,957			653			2,610
Total other and eliminations	(38,934		)	(8,758		)	(17,552		)	(65,244		)	(33,754		)	(14,529		)	(16,869		)	(65,152		)

Total operating revenues ⁽¹⁾	$	343,006		$	154,150		$	(17,552	)	$	479,604		$	345,281		$	161,904		$	(16,869	)	$	490,316

⁽¹⁾ Total operating revenues for the year ended December 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, and $0.2 million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, for the year ended December 31, 2018. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Regulated Energy Segment

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

Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required

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

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

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

Unregulated Energy Segment

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

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

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

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

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Contract balances

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




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

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

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our Mid-Atlantic propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2019 and 2018, we recognized revenue of $1.0 million and $0.7 million, respectively.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2019 are expected to be recognized as follows:



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

Practical expedients

For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.

6. SEGMENT INFORMATION

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

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


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

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•

Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and our mobile compressed natural gas and pipeline solutions subsidiary. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services. Effective in the third quarter of 2019, PESCO's results, previously reported in the Unregulated Energy segment, are reflected in discontinued operations. See Note 4, Acquisitions and Divestitures for additional details regarding the divestiture of PESCO.

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

The following table presents information about our reportable segments.



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

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

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

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

7. SUPPLEMENTAL CASH FLOW DISCLOSURES

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



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

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



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

8. DERIVATIVE INSTRUMENTS

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of December 31, 2019 and 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

PESCO's Derivative Instruments

As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts to UET, NJRES, Gas South, and DFS and, therefore, no longer have natural gas futures and contracts recorded in our consolidated financial statements. The gains and losses associated with PESCO's financial instruments are reflected as discontinued operations in the consolidated statements of income and PESCO's assets and liabilities are reflected as held-for-sale in the consolidated balance sheets.

Volume of Derivative Activity

As of December 31, 2019, the volume of our open commodity derivative contracts were as follows:



Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest expiration date of hedge
Sharp	Propane (gallons)	9.9	Cash flows hedges	June 2022

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Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in December 2019 through June 2022) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $1.5 million from accumulated other comprehensive income to earnings during the next 12-month period ending December 31, 2020.

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily MTM relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp, with the balance related to the account is as follows:



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

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. As discussed in Note 4, Acquisitions and Divestitures, during the fourth quarter of 2019, we sold PESCO's assets and contracts. PESCO's derivative assets and liabilities are reflected as assets and liabilities held-for-sale in the consolidated balance sheet as of December 31, 2018. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2019 and 2018 are as follows:



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



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

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

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

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

9. FAIR VALUE OF FINANCIAL INSTRUMENTS

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



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

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Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2019 and 2018, respectively:



			Fair Value Measurements Using:
As of December 31, 2019	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	27	$	27	$	—	$	—
Investments—guaranteed income fund	803		—		—		803
Investments—mutual funds and other	8,399		8,399		—		—
Total investments	9,229		8,426		—		803
Derivative assets	—		—		—		—
Total assets	$	9,229	$	8,426	$	—	$	803
Liabilities:
Derivative liabilities	$	1,844	$	—	$	1,844	$	—



			Fair Value Measurements Using:
As of December 31, 2018	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	686		—		—		686
Investments—mutual funds and other	6,003		6,003		—		—
Total investments	6,711		6,025		—		686
Derivative assets⁽¹⁾	82		—		82		—
Total assets	$	6,793	$	6,025	$	82	$	686
Liabilities:
Derivative liabilities ⁽¹⁾	$	1,604	$	—	$	1,604	$	—

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

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



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

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

At December 31, 2019 and 2018, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable, other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).

At December 31, 2019, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $486.6 million, compared to the estimated fair value of $505.0 million. At December 31, 2018, long-term debt, which includes the current maturities but excludes finance lease obligations and debt issuance costs, had a carrying value of $327.2 million, compared to a fair value of $323.8 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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

10. INVESTMENTS

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



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

We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2019, 2018 and 2017, we recorded net unrealized gains of $1.6 million, net unrealized losses of $0.4 million, and net unrealized gains of $1.0 million, respectively in other income (expense) in the consolidated statements of income related to these investments. For the investments in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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11. GOODWILL AND OTHER INTANGIBLE ASSETS

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



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

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

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

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

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

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



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

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

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

The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted average of 11 years. Amortization expense of intangible assets for the year ended December 31, 2019 was $0.8 million and $0.4 million for both years ended December 31, 2018 and 2017. Amortization expense of intangible assets is expected to be $1.2 million for the years 2020 and 2021, $0.9 million for the year 2022 and $0.8 million for the years 2023 and 2024.

12. INCOME TAXES

We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our state returns for tax years after 2014 are subject to examination. At December 31, 2019, the 2015 through 2018 federal income tax returns are under examination, and no report has been issued at this time.

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

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

Federal Tax Reform

On December 22, 2017, President Trump signed into law the TCJA. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 19, Rates and Other Regulatory Activities, for further discussion of the TCJA's impact on our regulated businesses.

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

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



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

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

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

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

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



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

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13. LONG-TERM DEBT

Our outstanding long-term debt is shown below:



	As of December 31,
(in thousands)	2019			2018
FPU secured first mortgage bonds:
9.08% bond, due June 1, 2022	$	7,990		$	7,986
Uncollateralized Senior Notes:
5.50% note, due October 12, 2020	2,000			4,000
5.93% note, due October 31, 2023	12,000			15,000
5.68% note, due June 30, 2026	20,300			23,200
6.43% note, due May 2, 2028	6,300			7,000
3.73% note, due December 16, 2028	18,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
3.25% note, due April 30, 2032	70,000			70,000
3.48% note, due May 31, 2038	50,000			50,000
3.58% note, due November 30, 2038	50,000			50,000
3.98% note, due August 20, 2039	100,000			—
2.98% note, due December 20, 2034	70,000			—
Term Note due January 21, 2020	—			30,000
Term Note due February 28, 2020	30,000			—
Promissory notes	—			26
Finance lease obligations	—			1,310
Less: debt issuance costs	(822		)	(567		)
Total long-term debt	485,768			327,955
Less: current maturities	(45,600		)	(11,935		)
Total long-term debt, net of current maturities	$	440,168		$	316,020

Annual maturities

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



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

Shelf Agreements

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

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

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



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

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

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

Term Notes

In December 2018, we issued a $30 million unsecured term note through PNC Bank N.A. with a maturity date of January 21, 2020. This note was paid off in December 2019 utilizing the proceeds from the issuance of uncollateralized senior notes discussed below. In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. The interest rate, at December 31, 2019, was 2.46%, which equals the one-month LIBOR rate plus 75 basis points. As of December 31, 2019, this term note is included in the current maturities of long-term debt.

Secured First Mortgage Bonds

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

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

Uncollateralized Senior Notes

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

Certain uncollateralized Senior Notes contain a “restricted payments” covenant as defined in the respective note agreements. The most restrictive covenants of this type are included within the 5.93% Senior Note, due October 31, 2023. The covenant provides that we cannot pay or declare any dividends or make any other restricted payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2019, the cumulative consolidated net income base was $509.5 million, offset by restricted payments of $227.5 million, leaving $282.0 million of cumulative net income free of restrictions. As of December 31, 2019, we are in compliance with all of our debt covenants.

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14. SHORT-TERM BORROWINGS

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



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

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

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

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

The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of December 31, 2019, we are in compliance with all of our debt covenants.

15. LEASES

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

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25

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Notes to the Consolidated Financial Statements

years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at December 31, 2019, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants which preclude our ability to pay dividends, obtain financing or enter into additional leases. As of December 31, 2019, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income:



		Year Ended
		December 31,
( in thousands)	Classification	2019		2018
Operating lease cost ⁽¹⁾	Operations expense	$	2,577	$	3,339
Finance lease cost:
Amortization of lease assets	Depreciation and amortization	650		1,451
Interest on lease liabilities	Interest expense	5		49
Net lease cost		$	3,232	$	4,839

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

The following table presents the balance and classifications of our right-of-use assets and lease liabilities included in our consolidated balance sheet at December 31, 2019:



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

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



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

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows as of December 31, 2019 and 2018:



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

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



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

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

16. STOCKHOLDERS' EQUITY

Accumulated Other Comprehensive (Loss)

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



	Defined Benefit Pension and Postretirement Plan Items			Commodity Contract Cash Flow Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	(602		)	(3,130		)	(3,732		)
Amounts reclassified from accumulated other comprehensive income	439			1,759			2,198
Net current-period other comprehensive loss	(163		)	(1,371		)	(1,534		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of December 31, 2018	(5,928		)	(785		)	(6,713		)
Other comprehensive income/(loss) before reclassifications	(872		)	2,161			1,289
Amounts reclassified from accumulated other comprehensive income/(loss)	1,867			(2,595		)	(728		)
Net current-period other comprehensive income/(loss)	995			(434		)	561
Prior-year reclassification	—			(115		)	(115		)
As of December 31, 2019	$	(4,933	)	$	(1,334	)	$	(6,267	)

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

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	For the Year Ended December 31,
(in thousands)	2019			2018			2017
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	77		$	77		$	77
Net gain ⁽¹⁾	(2,600		)	(579		)	(636		)
Total before income taxes	(2,523		)	(502		)	(559		)
Income tax benefit ⁽⁴⁾	656			63			223
Net of tax	$	(1,867	)	$	(439	)	$	(336	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	1,520		$	(647	)	$	1,607
Natural gas swaps ⁽²⁾⁽³⁾	7			197			(822		)
Natural gas futures ⁽²⁾⁽³⁾	2,096			(2,010		)	(456		)
Total before income taxes	3,623			(2,460		)	329
Income tax impact ⁽⁴⁾	(1,028		)	701			(159		)
Net of tax	$	2,595		$	(1,759	)	$	170

Total reclassifications for the period	$	728		$	(2,198	)	$	(166	)

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

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

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

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

17. EMPLOYEE BENEFIT PLANS

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

Defined Benefit Pension Plans

We sponsor three defined benefit pension plans: the Chesapeake Pension Plan, the FPU Pension Plan and the Chesapeake unfunded supplemental executive retirement pension plan ("SERP").

The Chesapeake Pension Plan, a qualified plan, was closed to new participants, effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation, effective January 1, 2005. Benefits under the Chesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake Pension Plan was frozen were credited with two additional years of service. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result, during the fourth quarter of 2019, we purchased annuities for those retirees currently receiving monthly payments and offered lump-sum payments to terminated vested employees. Accordingly, the pension settlement expense associated with the de-risking strategy allocated to our Regulated Energy operations was recorded as regulatory assets or deferred pending regulatory approval authorizing recovery through rates. The remaining portion of the pension settlement expense totaling $0.7 million was recorded in other expense in our consolidated statement of income which reflected the amount allocated to our Unregulated Energy operations or was deemed not recoverable through the regulatory process.

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

The Chesapeake SERP, a nonqualified plan, is comprised of two sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the Chesapeake SERP for the first sub-plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan. Active participants on the date the Chesapeake SERP was frozen were credited with two additional years of service. The second sub-

Chesapeake Utilities Corporation 2019 Form 10-K Page 79

Table of Contents

Notes to the Consolidated Financial Statements

plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit.

The unfunded liability for all three plans at both December 31, 2019 and 2018, is included in the other pension and benefit costs liability in our consolidated balance sheets.

The following schedules set forth the funded status at December 31, 2019 and 2018 and the net periodic cost for the years ended December 31, 2019, 2018 and 2017 for the Chesapeake and FPU Pension Plans as well as the Chesapeake SERP:



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



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

Chesapeake Utilities Corporation 2019 Form 10-K Page 80

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Notes to the Consolidated Financial Statements

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

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

Our funding policy provides that payments to the trustee of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The changes in investment types for the Chesapeake Pension Plan at December 31, 2019, compared to same period in 2018, are associated with the de-risking strategy executed during the fourth quarter of 2019. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2019, 2018 and 2017:



	Chesapeake Pension Plan						FPU Pension Plan
At December 31,	2019		2018		2017		2019		2018		2017
Asset Category
Equity securities	—	%	49	%	53	%	53	%	50	%	55	%
Debt securities	92	%	41	%	38	%	37	%	41	%	37	%
Other	8	%	10	%	9	%	10	%	9	%	8	%
Total	100	%	100	%	100	%	100	%	100	%	100	%

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

The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the plans’ goals and objectives (this allocation range applied to Chesapeake Pension Plan prior to the de-risking strategy executed during the fourth quarter of 2019):



Asset Allocation Strategy
Asset Class	Minimum Allocation Percentage		Maximum Allocation Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%	32	%
Foreign Equities (Developed and Emerging Markets)	13	%	25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%	40	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%	14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%	19	%
Cash	0	%	5	%

Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance.

Chesapeake Utilities Corporation 2019 Form 10-K Page 81

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Notes to the Consolidated Financial Statements

At December 31, 2019 and 2018, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:



	Fair Value Measurement Hierarchy

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

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

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

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

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

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

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

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

⁽⁸⁾ Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.

At December 31, 2019 and 2018, all of the investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees.

Chesapeake Utilities Corporation 2019 Form 10-K Page 82

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Notes to the Consolidated Financial Statements

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



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



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



(in thousands)	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan			Total
Prior service cost (credit)	$	—	$	—	$	—	$	(447	)	$	—		$	(447	)
Net loss (gain)	2,241		19,339		575		604			(32		)	22,727
Total	$	2,241	$	19,339	$	575	$	157		$	(32	)	$	22,280

Accumulated other comprehensive loss (gain) pre-tax⁽¹⁾	$	2,241	$	3,674	$	575	$	157		$	(6	)	$	6,641
Post-merger regulatory asset	—		15,665		—		—			(26		)	15,639
Subtotal	2,241		19,339		575		157			(32		)	22,280
Pre-merger regulatory asset	—		—		—		—			6			6
Total unrecognized cost	$	2,241	$	19,339	$	575	$	157		$	(26	)	$	22,286



	Chesapeake Pension Plan⁽¹⁾		FPU Pension Plan⁽¹⁾		Chesapeake SERP⁽²⁾		Chesapeake Postretirement Plan⁽²⁾		FPU Medical Plan⁽²⁾
(in thousands)
2020	$	115	$	3,281	$	151	$	90	$	86
2021	$	368	$	3,348	$	150	$	87	$	90
2022	$	106	$	3,424	$	148	$	85	$	91
2023	$	927	$	3,498	$	146	$	67	$	79
2024	$	111	$	3,549	$	144	$	64	$	80
Years 2025 through 2029	$	2,300	$	18,429	$	748	$	264	$	389



	Number of Shares		Weighted Average Fair Value
Outstanding — December 31, 2017	132,642		$	59.31
Granted	49,494		67.76
Vested	(29,786	)	47.39
Vested - Accelerated pursuant to separation agreement	(16,676	)	75.78
Expired	(3,933	)	49.66
Outstanding — December 31, 2018	131,741		67.24
Granted ⁽¹⁾	88,048		92.74
Vested	(25,831	)	67.08
Expired	(15,086	)	69.28
Forfeited ⁽²⁾	(21,055	)	71.67
Outstanding — December 31, 2019	157,817		$	80.28



	Regulatory Liabilities related to ADIT
Operation and Regulatory Jurisdiction	Amount (in thousands)	Status	Status of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)	$34,190	Will be addressed in Eastern Shore's next rate case filing.	Implemented one-time bill credit (totaling $0.9 million) in April 2018. Customer rates were adjusted in April 2018.
Delaware Division (Delaware PSC)	$12,847	PSC approved amortization of ADIT in January 2019.	Implemented one-time bill credit (totaling $1.5 million) in April 2019. Customer rates were adjusted in March 2019.
Maryland Division (Maryland PSC)	$4,087	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.4 million) in July 2018. Customer rates were adjusted in May 2018.
Sandpiper Energy (Maryland PSC)	$3,765	PSC approved amortization of ADIT in May 2018.	Implemented one-time bill credit (totaling $0.6 million) in July 2018. Customer rates were adjusted in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,304	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.	Florida PSC's final order was issued in February 2019. Excluding GRIP, tax savings arising from the TCJA rate reduction will be retained by the Company. GRIP: Tax savings for 2018 will be refunded to customers in 2020 through the annual GRIP cost recovery mechanism. Future customer GRIP surcharges will be adjusted to reflect tax savings associated with TCJA.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,218	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$294	Same treatment on a net basis as Chesapeake Florida Gas Division (above).	Tax rate reduction: The impact was immaterial for the divisions. GRIP (Applicable to Fort Meade division only): Same treatment as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,769	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.	TCJA benefit will flow back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.



MGP Site (Jurisdiction)	Status	Estimated Cost to Clean Up (Expect to Recover through Rates)
West Palm Beach (Florida)	Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. We expect to implement similar remedial actions on the site's west parcel in 2020.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, and any potential costs associated with future redevelopment of the properties.
Sanford (Florida)	In March 2018, the United States Environmental Protection Agency ("EPA") approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be immaterial.
Winter Haven (Florida)	Remediation is ongoing.	Not expected to exceed $0.4 million.
Seaford (Delaware)	Conducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction is being implemented, in accordance with the DNREC-approved Work Plan.	Between $0.2 million and $0.5 million.



	For the Quarters Ended
	March 31			June 30			September 30			December 31
(in thousands except per share amounts)
2019 ⁽¹⁾
Operating Revenues	$	160,464		$	94,541		$	92,626		$	131,973
Operating Income	$	44,123		$	18,164		$	14,358		$	29,642
Net Income:
Income from Continuing Operations	$	28,814		$	8,913		$	6,246		$	17,169
Loss from Discontinued Operations, Net of Tax	(149		)	(609		)	(624		)	(9		)
Gain on sale of Discontinued Operations, Net of Tax	—			—			—			5,402
	$	28,665		$	8,304		$	5,622		$	22,562
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.76		$	0.54		$	0.38		$	1.05
Earnings/(Loss) Per Share from Discontinued Operations	(0.01		)	(0.03		)	(0.04		)	0.33
	$	1.75		$	0.51		$	0.34		$	1.38
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.75		$	0.54		$	0.38		$	1.04
Earnings/(Loss) Per Share from Discontinued Operations	(0.01		)	(0.04		)	(0.04		)	0.33
	$	1.74		$	0.50		$	0.34		$	1.37
2018 ⁽¹⁾
Operating Revenues	$	168,831		$	93,872		$	93,400		$	134,214
Operating Income	$	40,853		$	12,238		$	12,879		$	28,873
Net Income:
Income from Continuing Operations	$	27,271		$	5,705		$	6,090		$	17,796
Income/(Loss) from Discontinued Operations	(415		)	680			(552		)	5
	$	26,856		$	6,385		$	5,538		$	17,801
Basic Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.67		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.03		)	0.04			(0.03		)	—
	$	1.64		$	0.39		$	0.34		$	1.09
Diluted Earnings Per Share of Common Stock:
Earnings Per Share from Continuing Operations	$	1.66		$	0.35		$	0.37		$	1.09
Earnings/(Loss) Per Share from Discontinued Operations	(0.02		)	0.04			(0.04		)	—
	$	1.64		$	0.39		$	0.33		$	1.09




• Exhibit 3.1		Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated herein by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q for the period ended June 30, 2010, File No. 001-11590.

• Exhibit 3.2		Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 4, 2012, are incorporated herein by reference to Exhibit 3 of our Current Report on Form 8-K, filed December 7, 2012, File No. 001-11590.

• Exhibit 3.3		First Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective December 3, 2014, is incorporated herein by reference to Exhibit 3.3 of our Annual Report on Form 10-K for the year ended December 31, 2014.

• Exhibit 3.4		Second Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective November 2, 2016, is incorporated herein by reference to Exhibit 3.3 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2016, File No. 001-11590.

• Exhibit 3.5		Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 9, 2017, File No. 001-11590.

• Exhibit 3.6		Certificate of Elimination of Series A Participating Cumulative Preferred Stock of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.6 to our Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-11590.

• Exhibit 3.7		Third Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective May 8, 2019, is incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 14, 2019, File No. 001-11590.

• Exhibit 4.1		Note Agreement dated October 18, 2005, between Chesapeake Utilities Corporation, as issuer, and Prudential Investment Management, Inc., relating to the private placement of Chesapeake Utilities Corporation’s 5.5% Senior Notes due 2020, is incorporated herein by reference to Exhibit 4.1 of our Annual Report on Form 10-K for the year ended December 31, 2005, File No. 001-11590.

• Exhibit 4.2		Note Agreement dated October 31, 2008, among Chesapeake Utilities Corporation, as issuer, General American Life Insurance Company and New England Life Insurance Company, relating to the private placement of Chesapeake Utilities Corporation's 5.93% Senior Notes due 2023.†

• Exhibit 4.3		Note Agreement dated June 29, 2010, among Chesapeake Utilities Corporation, as issuer, Metropolitan Life Insurance Company and New England Life Insurance Company, relating to the private placement of Chesapeake Utilities Corporation’s 5.68% Senior Notes due 2026 and Chesapeake Utilities Corporation’s 6.43% Senior Notes due 2028.†

• Exhibit 4.4		Note Agreement dated September 5, 2013, among Chesapeake Utilities Corporation, as issuer, and certain note holders, relating to the private placement of Chesapeake Utilities Corporation’s 3.73% Senior Notes due 2028 and Chesapeake Utilities Corporation’s 3.88% Senior Notes due 2029.†

• Exhibit 4.5		Form of Indenture of Mortgage and Deed of Trust dated September 1, 1942, between Florida Public Utilities Company and the trustee, for the First Mortgage Bonds, is incorporated herein by reference to Exhibit 7-A of Florida Public Utilities Company’s Registration No. 2-6087.

• Exhibit 4.6		Seventeenth Supplemental Indenture dated April 12, 2011, between Chesapeake Utilities Corporation and Florida Public Utilities Company, pursuant to which Chesapeake Utilities Corporation guarantees the payment and performance obligations of Florida Public Utilities Company under the Indenture, is incorporated herein by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2011, File No. 001-11590.



• Exhibit 4.7		Sixteenth Supplemental Indenture dated December 1, 2009, between Chesapeake Utilities Corporation and Florida Public Utilities Company, pursuant to which Chesapeake Utilities Corporation guaranteed the secured First Mortgage Bonds of Florida Public Utilities Company under the Merger Agreement, is incorporated herein by reference to Exhibit 4.9 of our Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-11590.

• Exhibit 4.8		Thirteenth Supplemental Indenture dated June 1, 1992, pursuant to which Florida Public Utilities, on May 1, 1992, privately placed $8,000,000 of its 9.08% First Mortgage Bonds due 2022, is incorporated herein by reference to Exhibit 4 to Florida Public Utilities Company’s Quarterly Report on Form 10-Q for the period ended June 30, 1992.

• Exhibit 4.9		Private Shelf Agreement dated October 8, 2015, between Chesapeake Utilities Corporation, as issuer, and Prudential Investment Management Inc., relating to the private placement of Chesapeake Utilities Corporation's 3.25% Senior Notes due 2032 and the sale of other Chesapeake Utilities Corporation unsecured Senior Notes from time to time, is incorporated herein by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2015, File No. 001-11590.

• Exhibit 4.10		First Amendment to Private Shelf Agreement dated September 14, 2018, between Chesapeake Utilities Corporation, as issuer, and PGIM, Inc. (formerly known as Prudential Investment Management, Inc.), and other purchasers that may become party thereto. †

• Exhibit 4.11		Master Note Agreement dated March 2, 2017, among Chesapeake Utilities Corporation, as issuer, NYL Investors LLC, and other certain note holders that may become party thereto from time to time relating to the private placement of Chesapeake Utilities Corporation’s 3.48% Senior Notes due 2038 and Chesapeake Utilities Corporation’s 3.58% Senior Notes due 2038. †

• Exhibit 10.1*		Chesapeake Utilities Corporation Cash Bonus Incentive Plan, effective January 1, 2015, is incorporated herein by reference to our Proxy Statement dated March 31, 2015, in connection with our Annual Meeting held on May 6, 2015, File No. 001-11590.

• Exhibit 10.2*		Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan, effective May 2, 2013 is incorporated herein by reference to our Proxy Statement dated March 29, 2013 in connection with our Annual Meeting held on May 2, 2013, File No. 001-11590.

• Exhibit 10.3*		Non-Qualified Deferred Compensation Plan, effective January 1, 2014, is incorporated herein by reference to Exhibit 10.8 of our Annual Report on Form 10-K for the year ended December 31, 2013, File No. 001-11590.

• Exhibit 10.4*		Executive Employment Agreement dated January 9, 2013, between Chesapeake Utilities Corporation and Beth W. Cooper, is incorporated herein by reference to Exhibit 10.10 of our Annual Report on Form 10-K for the year ended December 31, 2012, File No. 001-11590.

• Exhibit 10.5*		Executive Employment Agreement dated January 1, 2015, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.15 of our Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-11590.

• Exhibit 10.6*		Form of Performance Share Agreement, effective January 13, 2015 for the period 2015 to 2017, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.19 of our Annual Report on Form 10-K for the year ended December 31, 2014, File No. 001-11590.

• Exhibit 10.7*		Form of Performance Share Agreement, dated March 6, 2015 for the period 2015 to 2017, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and James F. Moriarty is incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the year ended September 30, 2015, File No. 001-11590.

• Exhibit 10.8*		Form of Performance Share Agreement, dated January 12, 2016 for the period 2016 to 2018, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner, Jeffry M. Householder and James F. Moriarty, is incorporated herein by reference to Exhibit 10.19 to our Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-11590.



• Exhibit 10.9*		Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.27 of our Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.

• Exhibit 10.10*		First Amendment to the Chesapeake Utilities Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.30 of our Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-11590.

• Exhibit 10.11		Revolving Credit Agreement dated October 8, 2015, between Chesapeake Utilities Corporation and PNC Bank, National Association, Bank of America, N.A., Citizens Bank N.A., Royal Bank of Canada and Wells Fargo Bank, National Association as lenders, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2015, File No. 001-11590.

• Exhibit 10.12		First Amendment dated February 25, 2016 to the Revolving Credit Agreement dated October 8, 2015, between Chesapeake Utilities Corporation and PNC Bank, National Association, Bank of America, N.A., Citizens Bank N.A., Royal Bank of Canada and Wells Fargo Bank, National Association as lenders, is incorporated herein by reference to Exhibit 10.24 of our Annual Report on Form 10-K for the year ended December 31, 2015, File No. 001-11590.

• Exhibit 10.13*		Executive Employment Agreement dated May 10, 2016, between Chesapeake Utilities Corporation and James F. Moriarty, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the year ended June 30, 2016, File No. 001-11590.

• Exhibit 10.14*		Form of Performance Share Agreement, effective February 23, 2017 for the period 2017 to 2019, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Elaine B. Bittner, Jeffry M. Householder, and James F. Moriarty, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the year ended June 30, 2017, File No. 001-11590.

• Exhibit 10.15		Credit Agreement, dated November 28, 2017, by and between Chesapeake Utilities Corporation and Branch Banking and Trust Company is incorporated herein by reference to Exhibit 10.20 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.

• Exhibit 10.16*		Separation Agreement and Release, effective as of June 7, 2018, by and between Chesapeake Utilities Corporation and Elaine B. Bittner, is incorporated herein by reference to Exhibit 10.1 of our Current Report on Form 8-K filed on June 8, 2018, File No. 001-11590.

• Exhibit 10.17*		Form of Performance Share Agreement, effective February 26, 2018 for the period 2018 to 2020, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Jeffry M. Householder and James F. Moriarty, is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended March 31, 2018, File No. 001-11590.

• Exhibit 10.18		Term Note dated December 21, 2018 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is incorporated herein by reference to Exhibit 10.23 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.

• Exhibit 10.19*		Form of Performance Share Agreement, effective February 25, 2019 for the period January 01, 2019 to December 31, 2021, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and Jeffry M. Householder is incorporated herein by reference to Exhibit 10.24 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590..

• Exhibit 10.20*		Executive Employment Agreement dated February 25, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is incorporated herein by reference to Exhibit 10.25 of our Annual Report on Form 10-K for the year ended December 31, 2018, File No. 001-11590.

• Exhibit 10.21		Term Note dated January 31, 2019 issued by Chesapeake Utilities Corporation in favor of Branch Banking & Trust Company is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended March 30, 2019, File No. 001-11590.



• Exhibit 10.22		Term Loan Credit Agreement, dated January 31, 2019, by and between Chesapeake Utilities Corporation and Branch Banking and Trust Company is incorporated herein by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q for the quarter ended March 30, 2019, File No. 001-11590.

• Exhibit 10.23*		Executive Retirement Agreement dated October 9, 2019, between Chesapeake Utilities Corporation and Stephen C. Thompson is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the quarter ended September 30, 2019, File No. 001-11590.

• Exhibit 10.24		Note Purchase Agreement dated November 19, 2019, between Chesapeake Utilities Corporation, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Berkshire Life Insurance Company of America, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and CMFG Life Insurance Company is incorporated herein by reference to our Current Report on Form 8-K filed on November 20, 2019, File No. 001-11590.

• Exhibit 10.25*		Form of Performance Share Agreement, effective December 3, 2019 for the period 2019 to 2020, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty and Kevin Webber is filed herewith.

• Exhibit 10.26*		Form of Performance Share Agreement, effective December 3, 2019 for the period 2019 to 2021, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty and Kevin Webber is filed herewith.

• Exhibit 10.27*		Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Kevin Webber, is filed herewith.

• Exhibit 10.28*		Form of Performance Share Agreement, effective February 25, 2020 for the period 2020 to 2022, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty and Kevin Webber is filed herewith.

• Exhibit 10.29*		Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Jeffry M. Householder, is filed herewith.

• Exhibit 10.30*		Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and Beth W. Cooper, is filed herewith.

• Exhibit 10.31*		Amendment to Executive Employment Agreement dated December 4, 2019, between Chesapeake Utilities Corporation and James F. Moriarty, is filed herewith.

• Exhibit 21		Subsidiaries of the Registrant is filed herewith.

• Exhibit 23.1		Consent of Independent Registered Public Accounting Firm is filed herewith.

• Exhibit 31.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.

• Exhibit 31.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d – 14(a), is filed herewith.

• Exhibit 32.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.

• Exhibit 32.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is filed herewith.

• Exhibit 101.INS XBRL Instance Document is filed herewith.

• Exhibit 101.SCH XBRL Taxonomy Extension Schema Document is filed herewith.

• Exhibit 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document is filed herewith.

• Exhibit 101.DEF XBRL Taxonomy Extension Definition Linkbase Document is filed herewith.

• Exhibit 101.LAB XBRL Taxonomy Extension Label Linkbase Document is filed herewith.




• Exhibit 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document is filed herewith.

• Exhibit 104		Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101.



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



	CHESAPEAKE UTILITIES CORPORATION

	By:		/s/ JEFFRY M. HOUSEHOLDER
			Jeffry M. Householder
			President, Chief Executive Officer and Director
			February 26, 2020



/s/ JEFFRY M. HOUSEHOLDER			/S/ BETH W. COOPER
Jeffry M. Householder			Beth W. Cooper, Executive Vice President,
President, Chief Executive Officer and Director			Chief Financial Officer,
February 26, 2020			and Assistant Corporate Secretary
			(Principal Financial and Accounting Officer)
			February 26, 2020

/S/ JOHN R. SCHIMKAITIS			/S/ DENNIS S. HUDSON, III
John R. Schimkaitis			Dennis S. Hudson, III, Director
Chair of the Board and Director			February 26, 2020
February 26, 2020

/S/ EUGENE H. BAYARD, ESQ			/S/ LILA A. JABER
Eugene H. Bayard, Esq., Director			Lila A. Jaber, Director
February 26, 2020			February 26, 2020

/S/ THOMAS J. BRESNAN			/S/ PAUL L. MADDOCK, JR.
Thomas J. Bresnan, Director			Paul L. Maddock, Jr., Director
February 26, 2020			February 26, 2020

/S/ RONALD G. FORSYTHE, JR.			/S/ CALVERT A. MORGAN, JR.
Dr. Ronald G. Forsythe, Jr., Director			Calvert A. Morgan, Jr., Director
February 26, 2020			February 26, 2020

/S/ THOMAS P. HILL, JR.			/S/ DIANNA F. MORGAN
Thomas P. Hill, Jr., Director			Dianna F. Morgan, Director
February 26, 2020			February 26, 2020



		Additions
For the Year Ended December 31,	Balance at Beginning of Year	Charged to Income		Other Accounts ⁽¹⁾		Deductions ⁽²⁾			Balance at End of Year
(In thousands)
Reserve Deducted From Related Assets
Reserve for Uncollectible Accounts
2019	1,058	$	1,392	$	278	$	(1,391	)	$	1,337
2018	876	1,119		133		(1,070		)	1,058
2017	897	541		339		(901		)	876