10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended: June 30, 2021

OR

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

For the transition period from                       to                      

Commission File Number: 001-11590 

CHESAPEAKE UTILITIES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	51-0064146
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer 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(s)	Name of each exchange on which registered
Common Stock - par value per share $0.4867	CPK	New York Stock Exchange, Inc.

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 definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☒	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

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

☐

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

Common Stock, par value $0.4867 — 17,578,367 shares outstanding as of July 31, 2021.

Table of Contents

PART I—FINANCIAL INFORMATION		1
ITEM 1.	FINANCIAL STATEMENTS	1
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
ITEM 4.	CONTROLS AND PROCEDURES	61
PART II—OTHER INFORMATION		62
ITEM 1.	LEGAL PROCEEDINGS	62
ITEM 1A.	RISK FACTORS	62
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	62
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	63
ITEM 5.	OTHER INFORMATION	63
ITEM 6.	EXHIBITS	64
SIGNATURES		65

GLOSSARY OF DEFINITIONS

Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities

Aspire Energy Express: Aspire Energy Express, LLC, a wholly-owned subsidiary of Chesapeake Utilities

ASU: Accounting Standards Update issued by the FASB

ATM: At-the-market

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

CDD: Cooling Degree-Day

CFG: Central Florida Gas Company

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

CHP: Combined Heat and Power Plant

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

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

CNG: Compressed natural gas

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

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

DRIP: Dividend Reinvestment and Direct Stock Purchase Plan

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

Dts/d: Dekatherms per day

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

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

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

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

Florida

ESG: Environmental, Social and Governance

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission

FGT: Florida Gas Transmission Company

Florida OPC: The Office of Public Counsel, an agency established by the Florida legislature who advocates on behalf of Florida's Utility consumers prior to actions or rule changes

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

GAAP: Generally Accepted Accounting Principles

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

LNG: Liquefied Natural Gas

Marlin Gas Services: Marlin Gas Services, LLC, a wholly-owned subsidiary of Chesapeake Utilities

MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we have previously issued Senior Notes and which is a party to the current MetLife Shelf Agreement, as amended

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

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

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

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

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

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

Revolver: Our $375 million unsecured revolving credit facility with certain lenders

RNG: Renewable natural gas

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

SEC: Securities and Exchange Commission

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

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

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

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

SICP: 2013 Stock and Incentive Compensation Plan

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

TETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline

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

U.S.: The United States of America

Western Natural Gas: Western Natural Gas Company

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	80,910	$	73,518	$	202,107	$	176,473
Unregulated Energy and other	30,172		23,533		100,161		73,268
Total Operating Revenues	111,082		97,051		302,268		249,741
Operating Expenses
Regulated Energy cost of sales	14,447		16,387		57,491		51,219
Unregulated Energy and other cost of sales	12,254		6,575		43,506		24,611
Operations	36,371		34,605		75,810		70,557
Maintenance	4,259		4,143		8,300		7,979
Gain from settlement	—		(130)		—		(130)
Depreciation and amortization	15,298		12,247		30,662		24,500
Other taxes	5,875		5,247		12,324		10,894
Total Operating Expenses	88,504		79,074		228,093		189,630
Operating Income	22,578		17,977		74,175		60,111
Other income (expense), net	1,456		(279)		1,841		3,039
Interest charges	5,054		5,054		10,159		10,868
Income from Continuing Operations Before Income Taxes	18,980		12,644		65,857		52,282
Income Taxes on Continuing Operations	5,165		1,983		17,570		12,580
Income from Continuing Operations	13,815		10,661		48,287		39,702
Income (Loss) from Discontinued Operations, Net of Tax	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886
Weighted Average Common Shares Outstanding:
Basic	17,546,346		16,448,490		17,516,273		16,431,724
Diluted	17,616,496		16,503,603		17,585,006		16,487,807
Basic Earnings Per Share of Common Stock:
Earnings from Continuing Operations	$	0.79	$	0.65	$	2.76	$	2.42
Earnings from Discontinued Operations	—		0.02		—		0.01
Basic Earnings Per Share of Common Stock	$	0.79	$	0.67	$	2.76	$	2.43
Diluted Earnings Per Share of Common Stock:
Earnings from Continuing Operations	$	0.78	$	0.64	$	2.75	$	2.41
Earnings from Discontinued Operations	—		0.02		—		0.01
Diluted Earnings Per Share of Common Stock	$	0.78	$	0.66	$	2.75	$	2.42

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

1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Net Income	$	13,813	$	10,956	$	48,279	$	39,886
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5), $(5), $(10) and $(10), respectively	(14)		(14)		(28)		(28)
Net gain, net of tax of $28, $28, $53 and $55, respectively	78		80		156		160
Cash Flow Hedges, net of tax:
Unrealized gain on commodity contract cash flow hedges, net of tax of $1,193, $651, $1,257 and $653, respectively	3,126		1,703		3,291		1,710
Unrealized gain/(loss) on interest rate swap cash flow hedges, net of tax of $2, $(14), $1 and $(14), respectively	6		(37)		4		(37)
Total Other Comprehensive Income, net of tax	3,196		1,732		3,423		1,805
Comprehensive Income	$	17,009	$	12,688	$	51,702	$	41,691

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

2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	June 30, 2021		December 31, 2020
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,643,904	$	1,577,576
Unregulated Energy	309,139		300,647
Other businesses and eliminations	34,767		30,769
Total property, plant and equipment	1,987,810		1,908,992
Less: Accumulated depreciation and amortization	(393,111)		(368,743)
Plus: Construction work in progress	78,187		60,929
Net property, plant and equipment	1,672,886		1,601,178
Current Assets
Cash and cash equivalents	5,011		3,499
Trade and other receivables	45,206		61,675
Less: Allowance for credit losses	(3,895)		(4,785)
Trade and other receivables, net	41,311		56,890
Accrued revenue	13,370		21,527
Propane inventory, at average cost	6,076		5,906
Other inventory, at average cost	6,524		5,539
Regulatory assets	9,429		10,786
Storage gas prepayments	2,385		2,455
Income taxes receivable	8,371		12,885
Prepaid expenses	9,497		13,239
Derivative assets, at fair value	8,056		3,269
Other current assets	523		436
Total current assets	110,553		136,431
Deferred Charges and Other Assets
Goodwill	38,803		38,731
Other intangible assets, net	7,625		8,292
Investments, at fair value	11,745		10,776
Operating lease right-of-use assets	10,020		11,194
Regulatory assets	109,244		113,806
Receivables and other deferred charges	11,464		12,079
Total deferred charges and other assets	188,901		194,878
Total Assets	$	1,972,340	$	1,932,487

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

3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	June 30, 2021		December 31, 2020
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—	$	—
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	8,550		8,499
Additional paid-in capital	357,520		348,482
Retained earnings	374,936		342,969
Accumulated other comprehensive income (loss)	558		(2,865)
Deferred compensation obligation	7,203		5,679
Treasury stock	(7,203)		(5,679)
Total stockholders’ equity	741,564		697,085
Long-term debt, net of current maturities	498,450		508,499
Total capitalization	1,240,014		1,205,584
Current Liabilities
Current portion of long-term debt	13,600		13,600
Short-term borrowing	169,294		175,644
Accounts payable	49,408		60,253
Customer deposits and refunds	33,983		33,302
Accrued interest	2,697		2,905
Dividends payable	8,433		7,683
Accrued compensation	10,767		13,994
Regulatory liabilities	13,911		6,284
Derivative liabilities, at fair value	351		127
Other accrued liabilities	19,812		15,240
Total current liabilities	322,256		329,032
Deferred Credits and Other Liabilities
Deferred income taxes	219,490		205,388
Regulatory liabilities	143,681		142,736
Environmental liabilities	3,904		4,299
Other pension and benefit costs	29,463		30,673
Operating lease - liabilities	8,719		9,872
Deferred investment tax credits and other liabilities	4,813		4,903
Total deferred credits and other liabilities	410,070		397,871
Environmental and other commitments and contingencies (Notes 6 and 7)
Total Capitalization and Liabilities	$	1,972,340	$	1,932,487

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

4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Six Months Ended
	June 30,
	2021		2020
(in thousands)
Operating Activities
Net income	$	48,279	$	39,886
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,662		24,500
Depreciation and accretion included in other costs	5,061		4,807
Deferred income taxes	12,810		12,232
Gain on sale of discontinued operations	—		(200)
Realized gain on commodity contracts and sale of assets	(5,342)		(3,496)
Unrealized (gain) loss on investments/commodity contracts	(988)		130
Employee benefits and compensation	(346)		21
Share-based compensation	3,315		2,322
Changes in assets and liabilities:
Accounts receivable and accrued revenue	23,664		11,455
Propane inventory, storage gas and other inventory	(1,085)		4,140
Regulatory assets/liabilities, net	7,711		4,133
Prepaid expenses and other current assets	2,789		6,016
Accounts payable and other accrued liabilities	6,563		(1,604)
Income taxes (payable) receivable	4,514		(1,480)
Customer deposits and refunds	681		(232)
Accrued compensation	(3,397)		(7,086)
Other assets and liabilities, net	(675)		(3,866)
Net cash provided by operating activities	134,216		91,678
Investing Activities
Property, plant and equipment expenditures	(104,631)		(82,779)
Proceeds from sale of assets	497		4,273
Proceeds from the sale of discontinued operations	—		200
Environmental expenditures	(395)		(1,948)
Net cash used in investing activities	(104,529)		(80,254)
Financing Activities
Common stock dividends	(15,047)		(12,976)
Issuance of stock under the Dividend Reinvestment Plan, net of offering fees	4,799		359
Tax withholding payments related to net settled stock compensation	(1,478)		(977)
Change in cash overdrafts due to outstanding checks	(1,101)		(1,690)
Net advances (repayments) under line of credit agreements	(5,249)		40,578
Repayment of long-term debt, net of offering fees	—		(13)
Repayment of long-term debt	(10,099)		(40,100)
Net cash used in financing activities	(28,175)		(14,819)
Net Increase (Decrease) in Cash and Cash Equivalents	1,512		(3,395)
Cash and Cash Equivalents—Beginning of Period	3,499		6,985
Cash and Cash Equivalents—End of Period	$	5,011	$	3,590

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

5

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

	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 Income/(Loss)		Deferred Compensation		Treasury Stock		Total
Balance at March 31, 2020	16,433,105	$	7,998	$	259,521	$	322,804	$	(6,194)	$	5,468	$	(5,468)	$	584,129
Net income	—	—		—		10,956		—		—		—		10,956
Other comprehensive gain	—	—		—		—		1,732		—		—		1,732
Dividend declared ($0.440 per share)	—	—		—		(7,306)		—		—		—		(7,306)
Dividend reinvestment plan	21,833	11		1,921		—		—		—		—		1,932
Share-based compensation and tax benefit (3)(4)	8,870	4		1,830		—		—		—		—		1,834
Treasury stock activities	—	—		—		—		—		191		(191)		—
Balance at June 30, 2020	16,463,808	$	8,013	$	263,272	$	326,454	$	(4,462)	$	5,659	$	(5,659)	$	593,277
Balance at December 31, 2019	16,403,776	$	7,984	$	259,253	$	300,607	$	(6,267)	$	4,543	$	(4,543)	$	561,577
Net income	—	—		—		39,886		—		—		—		39,886
Other comprehensive income	—	—		—		—		1,805		—		—		1,805
Dividend declared ($0.845 per share)	—	—		—		(14,009)		—		—		—		(14,009)
Dividend reinvestment plan	25,576	13		2,273		—		—		—		—		2,286
Share-based compensation and tax benefit (3) (4)	34,456	16		1,746		—		—		—		—		1,762
Treasury stock activities	—	—		—		—		—		1,116		(1,116)		—
Cumulative effect of the adoption of ASU 2016-13	—	—		—		(30)		—		—		—		(30)
Balance at June 30, 2020	16,463,808	$	8,013	$	263,272	$	326,454	$	(4,462)	$	5,659	$	(5,659)	$	593,277
Balance at March 31, 2021	17,521,493	$	8,528	$	350,875	$	369,623	$	(2,638)	$	6,992	$	(6,992)	$	726,388
Net income	—	—		—		13,813		—		—		—		13,813
Other comprehensive income	—	—		—		—		3,196		—		—		3,196
Dividend declared ($0.480 per share)	—	—		—		(8,500)		—		—		—		(8,500)
Dividend reinvestment plan	39,605	19		4,602		—		—		—		—		4,621
Share-based compensation and tax benefit (3) (4)	6,830	3		2,043		—		—		—		—		2,046
Treasury stock activities	—	—		—		—		—		211		(211)		—
Balance at June 30, 2021	17,567,928	$	8,550	$	357,520	$	374,936	$	558	$	7,203	$	(7,203)	$	741,564
Balance at December 31, 2020	17,461,841	8,499		348,482		342,969		(2,865)		5,679		(5,679)		$	697,085
Net income	—	—		—		48,279		—		—		—		48,279
Other comprehensive income	—	—		—		—		3,423		—		—		3,423
Dividend declared ($0.920 per share)	—	—		—		(16,312)		—		—		—		(16,312)
Dividend reinvestment plan	60,116	29		6,806		—		—		—		—		6,835
Share-based compensation and tax benefit (3) (4)	45,971	22		2,232		—		—		—		—		2,254
Treasury stock activities	—	—		—		—		—		1,524		(1,524)		—
Balance at June 30, 2021	17,567,928	$	8,550	$	357,520	$	374,936	$	558	$	7,203	$	(7,203)	$	741,564

(1)2,000,000 shares of preferred stock at $0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity.

(2)Includes 117,193, 105,087, 107,141, and 95,329 shares at June 30, 2021, December 31, 2020, June 30, 2020 and December 31, 2019, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

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

(4)The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2021 and 2020, we withheld 14,020 and 10,319 shares, respectively, for employee taxes.

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

6

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.    Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2020. In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

Effects of COVID-19

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of the new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19.

FASB Statements and Other Authoritative Pronouncements

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

7

2.    Calculation of Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	13,815	$	10,661	$	48,287	$	39,702
Income/(Loss) from Discontinued Operations	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886
Weighted average shares outstanding	17,546,346		16,448,490		17,516,273		16,431,724
Basic Earnings Per Share from Continuing Operations	$	0.79	$	0.65	$	2.76	$	2.42
Basic Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Basic Earnings Per Share	$	0.79	$	0.67	$	2.76	$	2.43
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic	17,546,346		16,448,490		17,516,273		16,431,724
Effect of dilutive securities—Share-based compensation	70,150		55,113		68,733		56,083
Adjusted denominator—Diluted	17,616,496		16,503,603		17,585,006		16,487,807
Diluted Earnings Per Share from Continuing Operations	$	0.78	$	0.64	$	2.75	$	2.41
Diluted Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Diluted Earnings Per Share	$	0.78	$	0.66	$	2.75	$	2.42

3.     Acquisitions

Escambia Meter Station Asset Purchase

In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light for $7.5 million and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline which provide gas supply to a natural gas fired power plant owned by Florida Power & Light in Pensacola, Florida.

Acquisition of Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired. Additionally, the purchase price included $0.3 million of working capital. We recorded contingent consideration of $0.3 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy segment beginning in the fourth quarter of 2020. There are multiple strategic benefits to this acquisition including it: (i) expanded our propane territory serviced in Florida and (ii) included an established customer base with additional opportunities for future growth.

In connection with this acquisition, we recorded $3.5 million in property plant and equipment, $1.4 million in intangible assets associated with customer relationships and non-compete agreements and $1.8 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021. For the three months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $0.6 million and $0.1 million, respectively. For the six months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $1.4 million and $0.3 million, respectively.

Acquisition of Elkton Gas

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

In connection with this acquisition,     we recorded $15.9 million in property, plant and equipment, $0.6 million in accounts receivable, $2.6 million in other liabilities, $2.6 million in regulatory liabilities and $4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021. For the three months ended June 30, 2021, Elkton Gas generated operating revenue and income of $0.5 million and $0.3 million, respectively. For the six months ended June 30, 2021, Elkton Gas generated operating revenue and income of $3.1 million and $0.9 million, respectively.

4.     Revenue Recognition

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays our revenue from continuing operations by major source based on product and service type for the three months ended June 30, 2021 and 2020:

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	Three months ended June 30, 2021								Three months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	10,068	$	—	$	—	$	10,068	$	11,758	$	—	$	—	$	11,758
Florida natural gas division	8,446		—		—		8,446		7,231		—		—		7,231
FPU electric distribution	18,898		—		—		18,898		15,701		—		—		15,701
FPU natural gas distribution	23,159		—		—		23,159		19,498		—		—		19,498
Maryland natural gas division	3,224		—		—		3,224		3,979		—		—		3,979
Sandpiper natural gas/propane operations	3,814		—		—		3,814		2,858		—		—		2,858
Elkton Gas	1,195		—		—		1,195		—		—		—		—
Total energy distribution	68,804		—		—		68,804		61,025		—		—		61,025
Energy transmission
Aspire Energy	—		5,578		—		5,578		—		4,554		—		4,554
Aspire Energy Express	47		—		—		47		—		—		—		—
Eastern Shore	18,617		—		—		18,617		18,277		—		—		18,277
Peninsula Pipeline	6,610		—		—		6,610		5,361		—		—		5,361
Total energy transmission	25,274		5,578		—		30,852		23,638		4,554		—		28,192
Energy generation
Eight Flags	—		4,173		—		4,173		—		3,694		—		3,694
Propane operations
Propane delivery operations	—		23,098		—		23,098		—		17,260		—		17,260
Energy delivery services
Marlin Gas Services	—		1,989		—		1,989		—		2,248		—		2,248
Other and eliminations
Eliminations	(13,168)		(65)		(4,734)		(17,967)		(11,145)		(16)		(4,340)		(15,501)
Other	—		—		133		133		—		—		133		133
Total other and eliminations	(13,168)		(65)		(4,601)		(17,834)		(11,145)		(16)		(4,207)		(15,368)
Total operating revenues (1)	$	80,910	$	34,773	$	(4,601)	$	111,082	$	73,518	$	27,740	$	(4,207)	$	97,051

(1) Total operating revenues for the three months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.1 million and $0.09 million for our Regulated and Unregulated Energy segments, respectively, and $0.1 million and $0.04 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

The following table displays our revenue from continuing operations by major source based on product and service type for the six months ended June 30, 2021 and 2020:

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	Six months ended June 30, 2021								Six months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	43,340	$	—	$	—	$	43,340	$	38,325	$	—	$	—	$	38,325
Florida natural gas division	17,402		—		—		17,402		15,708		—		—		15,708
FPU electric distribution	37,449		—		—		37,449		29,920		—		—		29,920
FPU natural gas distribution	50,020		—		—		50,020		44,942		—		—		44,942
Maryland natural gas division	13,690		—		—		13,690		13,117		—		—		13,117
Sandpiper natural gas/propane operations	11,885		—		—		11,885		9,150		—		—		9,150
Elkton Gas	3,830		—		—		3,830		—		—		—		—
Total energy distribution	177,616		—		—		177,616		151,162		—		—		151,162
Energy transmission
Aspire Energy	—		18,484		—		18,484		—		14,335		—		14,335
Aspire Energy Express	93		—		—		93		—		—		—		—
Eastern Shore	38,589		—		—		38,589		37,556		—		—		37,556
Peninsula Pipeline	13,077		—		—		13,077		10,185		—		—		10,185
Total energy transmission	51,759		18,484		—		70,243		47,741		14,335		—		62,076
Energy generation
Eight Flags	—		8,502		—		8,502		—		8,017		—		8,017
Propane operations
Propane delivery operations	—		78,361		—		78,361		—		55,882		—		55,882
Energy delivery services
Marlin Gas Services	—		4,340		—		4,340		—		3,557		—		3,557
Other and eliminations
Eliminations	(27,268)		(156)		(9,635)		(37,059)		(22,430)		(39)		(8,749)		(31,218)
Other			—		265		265		—		—		265		265
Total other and eliminations	(27,268)		(156)		(9,370)		(36,794)		(22,430)		(39)		(8,484)		(30,953)
Total operating revenues (1)	$	202,107	$	109,531	$	(9,370)	$	302,268	$	176,473	$	81,752	$	(8,484)	$	249,741

(1) Total operating revenues for the six months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, and $0.8 million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late 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 condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2021 and December 31, 2020 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	18	$	4,816	$	644
Balance at 6/30/2021	37,341		18		5,179		342
Increase (decrease)	$	(18,259)	$	—	$	363	$	(302)

Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and primarily 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 condensed 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 three months ended June 30, 2021 and 2020, we recognized revenue of $0.2 million. For each of the six months ended June 30, 2021 and 2020, we recognized revenue of $0.6 million.

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 June 30, 2021, are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	18,561	$	31,914	$	24,570	$	22,402	$	21,550	$	20,494	$	176,316
Natural gas distribution operations	3,005		6,501		6,039		5,807		5,266		5,062		33,448
FPU electric distribution	489		652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	22,055	$	39,067	$	31,261	$	28,861	$	27,091	$	25,831	$	210,314

5.     Rates and Other Regulatory Activities

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

Delaware

There were no material regulatory activities in the second quarter of 2021.

Maryland

Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement plan with the Maryland PSC. The STRIDE plan proposes to

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increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of fixed charge rider through a proposed five-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. In June 2021, we reached a settlement with the Maryland PSC Staff and the Maryland Office of the Peoples Counsel. The settlement agreement is currently being reviewed by a Maryland Public Utilities Law Judge, who must issue a final recommendation to the Commission. A final order is expected in August 2021.

Florida

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

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

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

Electric Depreciation Study: In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The petition was joined to the Hurricane Michael docket, and was approved at the Florida PSC Agenda in September 2020. The approved rates were retroactively applied effective January 1, 2020.

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

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

Escambia Meter Station: In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline, which provides gas supply to their natural gas fired power plant owned by Florida Power & Light in Pensacola,

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Florida. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021.

Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline will construct approximately 11.33 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021.

Eastern Shore

Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021.

Capital Cost Surcharge: In June 2021, Eastern Shore filed with the FERC a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge is an approved item in the settlement of Eastern Shore’s last rate case. In conjunction with the filing of this surcharge, pursuant to the settlement agreement, a true-up of the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge will become effective July 15, 2021.

COVID-19 Impact

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place.

In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during these unprecedented times.

At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May followed by Delaware and Maryland in July, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities.

In April 2020, the Maryland PSC issued an order that authorized utilities to establish a regulatory asset to record prudently incurred incremental costs related to COVID-19, beginning on March 16, 2020. The Maryland PSC found that the creation of a regulatory asset for COVID-19 related expenses will facilitate the recovery of those costs prudently incurred to serve customers during this period, and that the deferral of such costs is appropriate because the

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current catastrophic health emergency is outside the control of the utility and is a non-recurring event. The Maryland PSC is working on a plan that will provide funds to assist with the repayment of arrearages for customers in need and those impacted by COVID-19. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas will receive funds in the third quarter of 2021 to credit the accounts of those customers experiencing financial hardship in becoming current on their past due balances.

In May 2020, the Delaware PSC issued an order that authorized Delaware utilities to establish a regulatory asset to record COVID-19 related incremental costs incurred to ensure customers have essential utility services, for the period beginning on March 24, 2020 and ending 30 days after the state of emergency ends. The state of emergency was lifted July 12, 2021. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs.

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset will allow us to seek recovery of these costs in the next base rate proceedings. In November 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset treatment, contending that the order should be a reversed or modified and to request a hearing on the protest. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allows the units to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units will amortize the amount over two years and recover the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric division. This settlement agreement was approved by the Florida PSC on July 8, 2021.

In the fourth quarter of 2020, we began recording regulatory assets based on the net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric business units as authorized by the Delaware, Maryland and Florida PSCs. As of June 30, 2021 our total COVID-19 regulatory asset balance was $1.6 million.

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    Summary TCJA Table

Customer rates for our regulated businesses were adjusted as approved by the regulators, prior to 2020 with the exception of Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarizes the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of June 30, 2021 and December 31, 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	June 30, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,660	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,905	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,684	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,108	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,149	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$303	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,569	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,124	$1,124	PSC approved amortization of ADIT in March 2018.

6. Environmental Commitments and Contingencies

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances.

MGP Sites

We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida.

As of June 30, 2021 and December 31, 2020, we had approximately $5.6 million and $5.9 million, respectively, in environmental liabilities related to FPU’s four MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of June 30, 2021 and December 31, 2020, we had recovered approximately $12.6 million and $12.4 million, respectively, leaving approximately $1.4 million and $1.6 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

Remediation is ongoing for the MGPs in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The

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Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial.

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

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

7.     Other Commitments and Contingencies

Natural Gas and Electric

In March 2020, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2020 and expire in March 2023.

FPU natural gas distribution operations and Eight Flags have entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements are for a 10-year term that commenced in November 2020 and expire in October 2030.

Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency.

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2021, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of June 30, 2021 was $20.0 million. The aggregate amount guaranteed at June 30, 2021 was approximately $8.0 million with the guarantees expiring on various dates through March 30, 2022.

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As of June 30, 2021, we have issued letters of credit totaling approximately $4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn on these letters of credit as of June 30, 2021 and do not anticipate that the counterparties will draw upon these letters of credit. We expect that they will be renewed to the extent necessary in the future.

8.    Segment Information

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

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

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

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions 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, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations.

The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments:

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	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	80,374	$	73,044	$	201,095	$	175,512
Unregulated Energy	30,708		24,007		101,173		74,229
Total operating revenues, unaffiliated customers	$	111,082	$	97,051	$	302,268	$	249,741
Intersegment Revenues (1)
Regulated Energy	$	536	$	474	$	1,012	$	961
Unregulated Energy	4,065		3,733		8,358		7,523
Other businesses	133		133		265		265
Total intersegment revenues	$	4,734	$	4,340	$	9,635	$	8,749
Operating Income
Regulated Energy	$	22,808	$	18,006	$	55,673	$	45,894
Unregulated Energy	(445)		281		18,660		14,142
Other businesses and eliminations	215		(310)		(158)		75
Operating income	22,578		17,977		74,175		60,111
Other income (expense), net	1,456		(279)		1,841		3,039
Interest charges	5,054		5,054		10,159		10,868
Income from Continuing Operations before Income Taxes	18,980		12,644		65,857		52,282
Income Taxes on Continuing Operations	5,165		1,983		17,570		12,580
Income from Continuing Operations	13,815		10,661		48,287		39,702
Income (Loss) from Discontinued Operations, Net of Tax	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886

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

(in thousands)	June 30, 2021		December 31, 2020
Identifiable Assets
Regulated Energy segment	$	1,568,136	$	1,547,619
Unregulated Energy segment	359,971		347,665
Other businesses and eliminations	44,233		37,203
Total identifiable assets	$	1,972,340	$	1,932,487

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9.    Stockholders' Equity

Common Stock Issuances

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

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. In the third and fourth quarters of 2020, we issued 0.3 million shares at an average price per share of $86.12 and received net proceeds of $22.0 million under the DRIP. In the first six months of 2021, we issued less than 0.1 million shares at an average price per share of $113.51 and received net proceeds of $4.5 million under the DRIP.

We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Accumulated Other Comprehensive Gain (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive gain (loss) as of June 30, 2021 and 2020. All amounts in the following tables are presented net of tax.

	Defined Benefit		Commodity		Interest Rate
	Pension and		Contracts		Swap
	Postretirement		Cash Flow		Cash Flow
	Plan Items		Hedges		Hedges		Total
(in thousands)
As of December 31, 2020	$	(5,146)	$	2,309	$	(28)	$	(2,865)
Other comprehensive income before reclassifications	—		5,825		23		5,848
Amounts reclassified from accumulated other comprehensive income (loss)	128		(2,534)		(19)		(2,425)
Net current-period other comprehensive income	128		3,291		4		3,423
As of June 30, 2021	$	(5,018)	$	5,600	$	(24)	$	558

(in thousands)
As of December 31, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income/(loss) before reclassifications	—		2,770		(29)		$	2,741
Amounts reclassified from accumulated other comprehensive income/(loss)	132		(1,060)		(8)		(936)
Net prior-period other comprehensive income/(loss)	132		1,710		(37)		1,805
As of June 30, 2020	$	(4,801)	$	376	$	(37)	$	(4,462)

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The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2021 and 2020. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19	$	19	$	38	$	38
Net loss(1)	(106)		(108)		(209)		(215)
Total before income taxes	(87)		(89)		(171)		(177)
Income tax benefit	23		23		43		45
Net of tax	$	(64)	$	(66)	$	(128)	$	(132)
Gains on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	455	$	238	$	3,502	$	1,465
Income tax expense	(126)		(66)		(968)		(405)
Net of tax	$	329	$	172	$	2,534	$	1,060
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	22	$	11	$	26	$	11
Income tax expense	(6)		(3)		(7)		(3)
Net of tax	$	16	$	8	$	19	$	8
Total reclassifications for the period	$	281	$	114	$	2,425	$	936

(1) These amounts are included in the computation of net periodic costs (benefits). See Note 10, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items are included in other expense, net gains and losses on propane swap agreements, natural gas swaps, and natural gas futures contracts are included in cost of sales, the realized gain or loss on interest rate swap agreements is recognized as a component of interest charges in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

10.    Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2021 and 2020 are set forth in the following tables:

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	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Three Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	34	$	46	$	429	$	518	$	12	$	16	$	6	$	8	$	6	$	10
Expected return on plan assets	(40)		(42)		(830)		(745)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(19)		(19)		—		—
Amortization of net (gain) loss	60		65		155		135		7		5		10		12		(2)		—
Net periodic cost (benefit)	54		69		(246)		(92)		19		21		(3)		1		4		10
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		2
Total periodic cost (benefit)	$	54	$	69	$	(246)	$	(92)	$	19	$	21	$	(3)	$	1	$	4	$	12

	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Six Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	68	$	92	$	858	$	1,036	$	24	$	32	$	12	$	16	$	12	$	20
Expected return on plan assets	(80)		(84)		(1,660)		(1,490)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(38)		(38)		—		—
Amortization of net (gain) loss	120		130		310		270		14		10		18		24		(4)		—
Net periodic cost (benefit)	108		138		(492)		(184)		38		42		(8)		2		8		20
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		4
Total periodic cost (benefit)	$	108	$	138	$	(492)	$	(184)	$	38	$	42	$	(8)	$	2	$	8	$	24

We expect to record $0.7 million in pension and post-retirement benefits for 2021. The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result of this strategy, we are planning to terminate the Chesapeake Pension Plan in the fourth quarter of 2021.

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2021 and 2020: 

For the Three Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	60		155		7		10		(2)		230
Total recognized in net periodic benefit cost	60		155		7		(9)		(2)		211
Recognized from accumulated other comprehensive loss/(gain) (1)	60		29		7		(9)		—		87
Recognized from regulatory asset	—		126		—		—		(2)		124
Total	$	60	$	155	$	7	$	(9)	$	(2)	$	211

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For the Three Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	65		135		5		12		—		217
Total recognized in net periodic benefit cost	65		135		5		(7)		—		198
Recognized from accumulated other comprehensive loss/(gain) (1)	65		26		5		(7)		—		89
Recognized from regulatory asset	—		109		—		—		—		109
Total	$	65	$	135	$	5	$	(7)	$	—	$	198

For the Six Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	120		310		14		18		(4)		458
Total recognized in net periodic benefit cost	120		310		14		(20)		(4)		420
Recognized from accumulated other comprehensive loss/(gain) (1)	120		58		14		(20)		(1)		171
Recognized from regulatory asset	—		252		—		—		(3)		249
Total	$	120	$	310	$	14	$	(20)	$	(4)	$	420

For the Six Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	130		270		10		24		—		434
Total recognized in net periodic benefit cost	130		270		10		(14)		—		396
Recognized from accumulated other comprehensive loss/(gain) (1)	130		52		10		(14)		—		178
Recognized from regulatory asset	—		218		—		—		—		218
Total	$	130	$	270	$	10	$	(14)	$	—	$	396

    

(1) See Note 9, Stockholders' Equity.

During the three and six months ended June 30, 2021, we contributed approximately $0.1 million to the Chesapeake Pension Plan and approximately $0.5 million to the FPU Pension Plan. We expect to contribute approximately $0.3 million and $2.1 million, respectively, to the Chesapeake Pension Plan and FPU Pension Plans during 2021, which represents the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2021 were immaterial and $0.1 million, respectively. We expect to pay total cash benefits of approximately $0.2 million under the Chesapeake SERP in 2021. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2021 were immaterial and $0.2 million, respectively. We estimate that approximately $0.2 million will be paid for such benefits under the Chesapeake Postretirement Plan in 2021. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2021, were immaterial. We estimate that approximately $0.1 million will be paid for such benefits under the FPU Medical Plan in 2021.

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11.    Investments

The investment balances at June 30, 2021 and December 31, 2020, consisted of the following:

(in thousands)	June 30, 2021		December 31, 2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	11,723	$	10,755
Investments in equity securities	22		21
Total	$	11,745	$	10,776

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $0.6 million and $1.4 million, respectively, in other income, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $1.0 million and a net unrealized loss of approximately $0.1 million, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

12.    Share-Based Compensation

Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2021 and 2020:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Awards to non-employee directors	$	192	$	181	$	380	$	357
Awards to key employees	1,247		1,085		2,935		1,965
Total compensation expense	1,439		1,266		3,315		2,322
Less: tax benefit	(384)		(331)		(885)		(607)
Share-based compensation amounts included in net income	$	1,055	$	935	$	2,430	$	1,715

    Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2021, after the most recent election of directors, each of our non-employee directors received an annual retainer of 683 shares of common stock under the SICP for service as a director through the 2022 Annual Meeting of Stockholders; accordingly, 6,830 shares, with a weighted average fair value of $117.11 per share, were issued and vested in 2021. At June 30, 2021, there was approximately $0.7 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May of 2022.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2021: 

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	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2020	186,878	$	87.06
Granted	66,612	$	102.73
Vested	(53,147)	$	76.31
Expired	(852)	$	74.85
Forfeited	(5,384)	$	93.39
Outstanding—June 30, 2021	194,107	$	94.61

In February 2021, we granted awards of 66,612 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted.

In March 2021, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in February 2021 for the performance period ended December 31, 2020, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 14,020 shares, based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $1.5 million.

At June 30, 2021, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $23.4 million. At June 30, 2021, there was approximately $6.1 million of unrecognized compensation cost related to these awards, which will be recognized as expense for the remainder of 2021 through 2023.

Stock Options

There were no stock options outstanding or issued during the six months ended June 30, 2021 and 2020.

13.    Derivative Instruments

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. We have also entered into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of June 30, 2021, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of June 30, 2021, the volume of our commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
Sharp	Propane (gallons)	Purchases	23.3	Cash flows hedges	June 2024
Sharp	Propane (gallons)	Sales	5.0	Cash flows hedges	March 2022

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes that are expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in

25

June 2021 through June 2024) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $5.4 million from accumulated other comprehensive income to earnings during the next 12-month period ended June 30, 2022.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In the fourth quarter of 2020, we entered into interest rate swaps with notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

We designated and accounted for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges. We expect to reclassify less than $0.1 million from accumulated other comprehensive (loss) to earnings during the next 12-month period ended June 30, 2022.

Broker Margin

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

(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,808	$	1,505

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020, are as follows: 

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	8,056		3,255
Total asset derivatives		$	8,056	$	3,269

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	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	317		64
Interest rate swap agreements	Derivative liabilities, at fair value	34		40
Total liability derivatives		$	351	$	127

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2021		2020		2021		2020
Derivatives designated as fair value hedges
Propane put options	Cost of sales	$	—	$	—	$	(24)	$	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	455		238		3,502		1,465
Propane swap agreements	Other comprehensive income	4,319		2,354		4,548		2,363
Interest rate swap agreements	Interest expense	22		11		26		11
Interest rate swap agreements	Other comprehensive income (loss)	8		(51)		5		(51)
Total		$	4,804	$	2,552	$	8,057	$	3,788

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14.    Fair Value of Financial Instruments

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

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

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2021 and December 31, 2020:

			Fair Value Measurements Using:
As of June 30, 2021	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	2,191		—		—		2,191
Investments—mutual funds and other	9,532		9,532		—		—
Total investments	11,745		9,554		—		2,191
Derivative assets	8,056		—		8,056		—
Total assets	$	19,801	$	9,554	$	8,056	$	2,191
Liabilities:
Derivative liabilities	$	351	$	—	$	351	$	—

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			Fair Value Measurements Using:
As of December 31, 2020	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2021 and 2020:

	Six months ended June 30,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	70		226
Transfers	—		1,345
Distribution	(51)		(50)
Investment income	16		10
Ending Balance	$	2,191	$	2,334

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

At June 30, 2021, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At June 30, 2021, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $512.9 million, compared to the estimated fair value of $541.5 million. At December 31, 2020, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $523.0 million, compared to a fair value of approximately $548.5 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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15.    Long-Term Debt

Our outstanding long-term debt is shown below: 

	June 30,		December 31,
(in thousands)	2021		2020
Uncollateralized senior notes:
5.93% note, due October 31, 2023	$	7,500	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	16,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
Less: debt issuance costs	(850)		(901)
Total long-term debt	512,050		522,099
Less: current maturities	(13,600)		(13,600)
Total long-term debt, net of current maturities	$	498,450	$	508,499

    

.

    Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at June 30, 2021:

(in thousands)	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (1)	150,000		—		—		150,000
NYL Shelf Agreement (1)	150,000		(140,000)		—		10,000
Total Shelf Agreements as of June 30, 2021	$	670,000	$	(360,000)	$	—	$	310,000

     (1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively.

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.

16.    Short-Term Borrowings

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At June 30, 2021 and December 31, 2020, we had $169.3 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent. Included in the June 30, 2021 balance, is $100.0 million in short-term debt for which we have entered into interest rate swap agreements. In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million

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through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

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

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of June 30, 2021, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon total indebtedness to total capitalization ratio. As of June 30, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the Revolver at June 30, 2021 was $200.9 million. As of June 30, 2021, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

17.    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 our employees in several locations throughout the Mid-Atlantic, Mid-West and in Florida. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at June 30, 2021, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of June 30, 2021, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
( in thousands)	Classification	2021		2020		2021		2020
Operating lease cost (1)	Operations expense	$	515	$	629	$	1,038	$	1,255

(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 condensed consolidated balance sheet at June 30, 2021 and December 31, 2020:

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(in thousands)	Balance sheet classification	June 30, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,020	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,732	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,719		9,872
Total lease liabilities		$	10,451	$	11,619

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2021 and December 31, 2020:

	June 30, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.65		8.70
Weighted-average discount rate
Operating leases	3.8	%	3.8	%

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2021 and 2020:

	Six Months Ended
	June 30,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	936	$	1,034

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating  Leases (1)
Remainder of 2021	$	1,060
2022	1,845
2023	1,762
2024	1,607
2025	1,387
2026	951
Thereafter	3,596
Total lease payments	$	12,208
Less: Interest	1,757
Present value of lease liabilities	$	10,451

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

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2020, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of 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, uncertainties and other important factors that could cause actual future results to differ materially from those expressed in the forward-looking statements. In addition to the risk factors described under Item 1A, Risk Factors in our 2020 Annual Report on Form 10-K, such factors include, but are not limited to:

•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;

•the availability to materials necessary to construct new capital projects;

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

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

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

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

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

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

•customers' preferred energy sources;

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

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

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

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

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

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

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

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

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

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

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

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

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

Introduction

We are an energy delivery company engaged in the distribution of natural gas, electricity, and propane; the transmission of natural gas; the generation of electricity and steam, and in providing related services to our customers.

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. We are focused on identifying and developing opportunities across the energy value chain, with emphasis on midstream and downstream investments that are accretive to earnings per share, consistent with our long-term growth strategy and create opportunities to continue our record of top tier returns on equity relative to our peer group.

Currently, our growth strategy is focused on the following platforms, including:

•Optimizing the earnings growth in our existing businesses, which includes organic growth, territory expansions, new pipeline expansions, and new products and services as well as increased opportunities for collaboration and efficiencies across the organization as a result of our ongoing business transformation.

•Growth of Marlin Gas Services’ CNG transport business and expansion into LNG and RNG transport services as well as methane capture.

•Identifying and undertaking additional strategic propane and complementary business acquisitions that provide a larger foundation in current markets and expand our brand and presence into new strategic growth markets.

•Pursuit of growth opportunities that enable us to utilize our integrated set of energy delivery businesses to participate in renewable energy opportunities.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is normally highest due to colder temperatures.

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 for continuing operations on a diluted basis, unless otherwise noted.

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Results of Operations for the Three and Six Months Ended June 30, 2021

Overview

Chesapeake Utilities is a Delaware corporation formed in 1947. We are a diversified energy company engaged, through our operating divisions and subsidiaries, in regulated energy, unregulated energy and other businesses. We operate primarily on the Delmarva Peninsula and in Florida, Pennsylvania and Ohio and provide natural gas distribution and transmission; electric distribution and generation; propane gas distribution; mobile compressed natural gas services; steam generation; and other energy-related services.

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of the new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC and the Occupational Safety and Health Administration, in order to protect our employees, customers and the communities.

Impacts from the restrictions imposed in our service territories and the implementation of our pandemic response plan, included reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during these unprecedented times. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19.

Environmental, Social and Governance Initiatives

ESG initiatives are embedded within Chesapeake Utilities culture and are an integral part of our strategy. ESG is at the core of our well-established culture and our informed business decisions. Over the years, we have reduced our greenhouse gas emissions, while responsibly growing our businesses. We have also helped to accelerate the reduction of emissions by many of our customers. Our combined efforts have enhanced the sustainability of our local communities. We look forward to publishing our inaugural Corporate Responsibility and Sustainability Report later this year. Below we have highlighted several of Chesapeake Utilities initiatives in each area of ESG:

Advancing Environmental Initiatives

Our three-part action plan continues to make progress. We are pursuing a three-part action plan that supports decarbonization and a lower carbon energy future. First, we are taking actions that will continue to reduce our greenhouse gas emissions. For example, we have largely completed our Florida GRIP, as we commonly refer to it, which replaces older portions of our natural gas distribution system. The remaining capital expenditures associated with this program will be invested through 2022. Our Elkton Gas subsidiary also recently reached a settlement agreement with the Maryland PSC to accelerate its Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of a fixed charge rider through a proposed 5-year surcharge. Throughout our pipeline system, we have also implemented improved emission detection technology at our pipeline compressor stations.

The second component of our action plan is providing services and support to our customers who are reducing their greenhouse gas emissions. Our current Del-Mar Energy Pathway Project, which is expected to be complete by the end of the year, will bring natural gas to Somerset County, Maryland for the first time. As part of this project, our services will support the conversion by two significant industrial customers in Somerset County from less environmentally friendly fuel sources, including in one case, wood chips. Similarly, several of our commercial customers continue to convert their vehicle fleet to compressed natural gas or propane, further reducing their greenhouse gas emissions and positively impacting the environment.

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We continue to see significant demand for new natural gas service in both our Delmarva and Florida territories, with our growth rates more than double the industry’s growth rates. In many of our local markets, natural gas is a cleaner fuel option than alternative energy sources. Natural gas is an important component of the country’s energy transition and we are committed to responsibly expanding the infrastructure in our growing service areas.

These same markets are also presenting RNG opportunities with ongoing projects to transform landfill, food, dairy and poultry waste into usable energy. The development of several RNG projects is the third component of our action plan. Our participation in these projects extends from transporting the RNG to market by pipeline or our Marlin Gas Services compressed natural gas trailers, to potential investments in biogas plants and, in some cases, the solar energy facilities to provide electricity to the plants and significantly improve the RNG carbon intensity score. To date, we’ve announced three projects that, if developed, will introduce RNG into two of our services territories for the first time. We are continuing to actively consider other renewable projects and the potential of increasing the number of RNG projects in our diversified energy portfolio. We are committed to remaining disciplined in our approach by pursuing projects that meet our return thresholds and strategic goals.

We also have several other initiatives underway, including plans to add additional small solar facilities along our system, and our participation in a pilot program to blend hydrogen into the natural gas distribution system that serves our Eight Flags combined heat and power plant. We are optimistic about this pilot program and believe that hydrogen will continue to gain in efficiency and become more price competitive over time.

To finance these projects, we are working with many of our key banking partners to establish sustainable debt financing capacity at attractive pricing.

Advancing Social Initiatives

Promoting equity, diversity and inclusion (“EDI”). Our success is the direct result of our employees and our strong culture that fully engages our team and promotes equity, diversity, inclusion, integrity, accountability and reliability. We believe that a combination of diverse team members and an inclusive culture contributes to the success of our Company and to enhanced societal advancement. Our eleven member Board of Directors includes, two female directors, an African American Director and a Director who is of Middle Eastern descent.

We established an EDI Council in 2020, complementing and broadening the work our Women in Energy group started years ago. The Council oversees our efforts to improve diversity in recruitment, employee development and advancement, cultural awareness and related policies. These efforts are expanded through the broad reach of our six Employee Resource Groups and other partnerships we have in the community. Employees have access to communications and on-demand learning sessions on an array of topics, including equity, diversity and inclusion, through our “EDI Wise” webinars. We have also expanded our supplier diversity program to gather information that will enable us to further expand, measure and report on the diversity of our suppliers and associated spend.

Safety at the center of Chesapeake Utilities culture and the way we do business. There is nothing more important than the safety of our team, our customers and our communities. The importance of safety is exhibited throughout our organization, with the direction and tone set by the Board of Directors and our President and Chief Executive Officer. Employees are required to attend monthly safety meetings and incorporate safety moments at operational and other meetings. The achievement of superior safety performance is both an important short and long-term strategic initiative in managing our operations. Our new state-of-the-art training center, named ‘Safety Town,’ provides employees hands-on training and simulated on-the-job field experiences, further developing our team and enhancing the reliability and integrity of our systems. Safety Town has also expanded our community outreach by offering safety training to many regional first responders. Our second Safety Town facility will be located in Florida and is in the final stages of planning.

Advancing Governance Initiatives

Commitment to sound governance practices. Consistent with our culture of teamwork, the broad responsibility of ESG stewardship is supported across our organization by the dedication and efforts of the Board and its Committees, as well as the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, the Board is committed to overseeing the sustainability of the Company. The Board and Corporate Governance Committee annually reviews our corporate governance documents and practices to ensure that they provide the appropriate framework under which we operate. In recent years, we have received national recognition as the Governance Team of the Year, and also Best for Corporate Governance Among North American Utilities. To learn more about our corporate governance practices and transparency, stakeholder

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engagement, the experience and diversity of our Board members, and our Business Code of Ethics and Conduct, which highlights our commitment to the highest ethical standards and the importance of engaging in sustainable practices, please view our Proxy Statement filed with the Securities and Exchange Commission on March 22, 2021. Additionally, please view Chesapeake Utilities historical quarterly earnings conference calls for additional discussions on ESG and our sustainability practices.

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Operational Highlights

Our income from continuing operations for the three months ended June 30, 2021 was $13.8 million, or $0.78 per share, compared to $10.7 million, or $0.64 per share, for the same quarter of 2020. Operating income for the three months ended June 30, 2021 increased by $4.6 million, or 25.6 percent, over the same period in 2020. Higher earnings for the second quarter of 2021 reflected continued pipeline expansion projects, margin generated from consumption returning to pre-pandemic levels, contributions from 2020 acquisitions, natural gas distribution growth and margin growth from increased investment in GRIP, and the timing of the impact of the Hurricane Michael regulatory proceeding settlement. The margin increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments and operating expenses associated primarily with growth initiatives and a return to pre-pandemic conditions, including payroll, benefits and other employee-related expenses and outside services costs. The operating expense increases were partially offset by $2.2 million of lower pandemic related costs and the regulatory deferral of COVID-19 expenses.

	Three Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands except per share)
Gross Margin
Regulated Energy segment	$	66,463	$	57,131	$	9,332
Unregulated Energy segment	17,952		17,032		920
Other businesses and eliminations	(34)		(73)		39
Total Gross Margin	$	84,381	$	74,090	$	10,291
Operating Income
Regulated Energy segment	$	22,808	$	18,006	$	4,802
Unregulated Energy segment	(445)		281		(726)
Other businesses and eliminations	215		(310)		525
Total Operating Income	22,578		17,977		4,601
Other income (expense), net	1,456		(279)		1,735
Interest charges	5,054		5,054		—
Income from Continuing Operations Before Income Taxes	18,980		12,644		6,336
Income Taxes on Continuing Operations	5,165		1,983		3,182
Income from Continuing operations	13,815		10,661		3,154
Income (Loss) from Discontinued Operations	(2)		295		(297)
Net Income	$	13,813	$	10,956	$	2,857
Basic Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	0.79	$	0.65	$	0.14
Earnings from Discontinued Operations	—		0.02		(0.02)
Basic Earnings Per Share of Common Stock	$	0.79	$	0.67	$	0.12
Diluted Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	0.78	$	0.64	$	0.14
Earnings from Discontinued Operations	—		0.02		(0.02)
Diluted Earnings Per Share of Common Stock	$	0.78	$	0.66	$	0.12

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Key variances in continuing operations, between the second quarter of 2021 and the second quarter of 2020, included: 

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Second Quarter of 2020 Reported Results from Continuing Operations	$	12,644	$	10,661	$	0.64
Adjusting for Unusual Items:
Gains from sales of assets	1,294		942		0.05
Regulatory deferral of COVID-19 expenses per PSCs orders	748		544		0.03
Absence of the favorable income tax impact associated with the CARES Act recorded in the second quarter of 2020	—		(1,669)		(0.10)
	2,042		(183)		(0.02)
Increased (Decreased) Gross Margins:
Hurricane Michael Settlement margin impact*	3,145		2,289		0.13
Eastern Shore and Peninsula Pipeline service expansions*	2,259		1,644		0.09
Increased customer consumption - primarily due to a return to pre-pandemic conditions	1,974		1,437		0.08
Margin contributions from Elkton Gas and Western Natural Gas*	1,135		826		0.05
Natural gas growth (excluding service expansions)	752		547		0.04
Aspire Energy improved margin including natural gas liquid processing	677		493		0.03
Florida GRIP*	572		416		0.02
	10,514		7,652		0.44
(Increased) Decreased Operating Expenses (Excluding Cost of Sales):
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	(2,268)		(1,651)		(0.09)
Hurricane Michael settlement agreement - depreciation and amortization impact	(1,774)		(1,291)		(0.07)
Depreciation, amortization and property tax costs due to new capital investments	(1,505)		(1,095)		(0.06)
Payroll, Benefits and other employee-related expenses	(1,320)		(961)		(0.05)
Operating expenses for Elkton Gas and Western Natural Gas acquisitions	(939)		(683)		(0.04)
Reduction in expenses associated with the COVID-19 pandemic	1,465		1,066		0.06
	(6,341)		(4,615)		(0.25)
Other income tax effects	—		214		0.01
Net other changes	121		86		—
Change in shares outstanding due to 2020 and 2021 equity offerings	—		—		(0.04)
	121		300		(0.03)
Second Quarter of 2021 Reported Results from Continuing Operations	$	18,980	$	13,815	$	0.78

*See the Major Projects and Initiatives table.

Our income from continuing operations for the six months ended June 30, 2021 was $48.3 million, or $2.75 per share, compared to $39.7 million, or $2.41 per share, for the same period of 2020. Operating income for the six months ended June 30, 2021 increased by $14.1 million, or 23.4 percent, over the same period in 2020. Higher earnings for the first six months of 2021 reflected a return to more normal weather compared to 2020 that was warmer than normal. Our earnings also increased from expansion projects and acquisitions completed in 2020. Further contributing to the improved performance in the first six months of 2021 were organic growth, consumption returning to pre-pandemic levels, increased retail propane margins per gallon, and the timing of the impact of the Hurricane Michael regulatory proceeding settlement. The margin increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments and operating expenses associated primarily with growth initiatives, including payroll, benefits and other employee-related

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expenses and outside services costs. The operating expense increases were partially offset by $2.8 million of lower pandemic expenses and the regulatory deferral of COVID-19 expenses.

	Six Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands except per share)
Gross Margin
Regulated Energy segment	$	144,616	$	125,254	$	19,362
Unregulated Energy segment	56,728		48,814		7,914
Other businesses and eliminations	(73)		(157)		84
Total Gross Margin	$	201,271	$	173,911	$	27,360
Operating Income
Regulated Energy segment	$	55,673	$	45,894	$	9,779
Unregulated Energy segment	18,660		14,142		4,518
Other businesses and eliminations	(158)		75		(233)
Total Operating Income	74,175		60,111		14,064
Other income, net	1,841		3,039		(1,198)
Interest charges	10,159		10,868		(709)
Income from Continuing Operations Before Income Taxes	65,857		52,282		13,575
Income Taxes on Continuing Operations	17,570		12,580		4,990
Income from Continuing operations	48,287		39,702		8,585
Income (Loss) from Discontinued Operations	(8)		184		(192)
Net Income	$	48,279	$	39,886	$	8,393
Basic Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	2.76	$	2.42	$	0.34
Earnings from Discontinued Operations	—		0.01		(0.01)
Basic Earnings Per Share of Common Stock	$	2.76	$	2.43	$	0.33
Diluted Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	2.75	$	2.41	$	0.34
Earnings from Discontinued Operations	—		0.01		(0.01)
Diluted Earnings Per Share of Common Stock	$	2.75	$	2.42	$	0.33

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Key variances in continuing operations, between the six months ended June 30, 2021 and the six months ended June 30, 2020, included: 

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Six Months Ended June 30, 2020 Reported Results from Continuing Operations	$	52,282	$	39,702	$	2.41
Adjusting for Unusual Items:
Gains from sales of assets	(1,563)		(1,146)		(0.07)
Regulatory deferral of COVID-19 expenses per PSCs orders	944		692		0.04
Absence of the favorable income tax impact associated with the CARES Act recorded in the second quarter of 2020	—		(1,669)		(0.10)
	(619)		(2,123)		(0.13)
Increased (Decreased) Gross Margins:
Increased customer consumption - primarily weather related	5,936		4,352		0.25
Hurricane Michael Settlement margin impact *	5,720		4,194		0.24
Eastern Shore and Peninsula Pipeline service expansions*	5,239		3,841		0.22
Margin contributions from Elkton Gas and Western Natural Gas*	2,998		2,198		0.12
Increased customer consumption - primarily due to a return to pre-pandemic conditions	1,744		1,279		0.07
Natural gas growth (excluding service expansions)	1,691		1,240		0.07
Increased retail propane margins per gallon	1,137		834		0.05
Florida GRIP*	931		682		0.04
Aspire Energy improved margin including natural gas liquid processing	691		506		0.03
Sandpiper infrastructure rider associated with conversions	455		334		0.03
	26,542		19,460		1.12
(Increased) Decreased Operating Expenses (Excluding Cost of Sales):
Hurricane Michael settlement agreement - depreciation and amortization impact	(3,550)		(2,603)		(0.15)
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	(3,370)		(2,471)		(0.14)
Payroll, benefits and other employee-related expenses due to growth	(3,301)		(2,421)		(0.14)
Depreciation, amortization and property tax costs due to new capital investments	(3,215)		(2,357)		(0.13)
Operating expenses for Elkton Gas and Western Natural Gas acquisitions	(1,968)		(1,443)		(0.08)
Insurance expense (non-health) - both insured and self-insured	(513)		(376)		(0.02)
Reduction in expenses associated with the COVID-19 pandemic	1,893		1,388		0.08
	(14,024)		(10,283)		(0.58)
Interest charges (1)	765		561		0.03
Other income tax effects	—		302		0.02
Net other changes	911		668		0.03
Change in shares outstanding due to 2020 and 2021 equity offerings	—		—		(0.15)
	1,676		1,531		(0.07)
Six Months Ended June 30, 2021 Reported Results from Continuing Operations	$	65,857	$	48,287	$	2.75

*See the Major Projects and Initiatives table.

(1) Interest charges include amortization of a regulatory liability of $0.6 million related to the Hurricane Michael regulatory proceeding settlement.

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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, and to further grow our businesses and earnings, with the intention to increase shareholder value. The following table includes the major projects/initiatives recently completed and currently underway. Major projects and initiatives that have generated consistent year-over-year margin contributions are removed from the table. In the future, we will add new projects and initiatives to this table once negotiations are substantially completed and the associated earnings can be estimated.

	Gross Margin for the Period
	Three Months Ended				Six Months Ended				Year Ended		Estimate for
	June 30,				June 30,				December 31,		Fiscal
in thousands	2021		2020		2021		2020		2020		2021		2022
Pipeline Expansions:
Western Palm Beach County, Florida Expansion (1)	$	1,172	$	967	$	2,340	$	1,968	$	4,167	$	4,811	$	5,227
Del-Mar Energy Pathway (1) (2)	921		452		1,805		641		2,462		4,134		6,708
Callahan Intrastate Pipeline (2)	2,121		536		4,239		536		3,851		7,564		7,598
Guernsey Power Station	47		—		94		—		—		514		1,486
Winter Haven Expansion	—		—		—		—		—		—		426
Beachside Pipeline Expansion	—		—		—		—		—		—		—
Total Pipeline Expansions	4,261		1,955		8,478		3,145		10,480		17,023		21,445
CNG Transportation	1,708		2,107		3,785		3,454		7,231		7,900		8,500
RNG Transportation	—		—		—		—		—		150		1,000
Acquisitions:
Elkton Gas	746		—		2,058		—		1,344		3,992		4,113
Western Natural Gas	389		—		939		—		389		2,066		2,251
Escambia Meter Station	83		—		83		—		—		583		1,000
Total Acquisitions	1,218		—		3,080		—		1,733		6,641		7,364
Regulatory Initiatives:
Florida GRIP	4,181		3,609		8,236		7,305		15,178		16,848		17,882
Hurricane Michael Regulatory Proceeding	3,145		—		5,720		—		10,864		11,014		11,014
Capital Cost Surcharge Programs	120		128		257		261		523		1,186		1,985
Elkton STRIDE Plan	—		—		—		—		—		45		299
Total Regulatory Initiatives	7,446		3,737		14,213		7,566		26,565		29,093		31,180
Total	$	14,633	$	7,799	$	29,556	$	14,165	$	46,009	$	60,807	$	69,489

(1) Includes gross margin generated from interim services.

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

Detailed Discussion of Major Projects and Initiatives

Pipeline Expansions

West 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 $0.2 million and $0.4 million for the three and six months ended June 30, 2021, respectively, compared to 2020. We expect to complete the remainder of the project in phases through the fourth quarter of 2021, and estimate that the project will generate annual gross margin of $4.8 million in 2021 and $5.2 million annually thereafter.

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Del-Mar Energy Pathway

In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021. The new facilities will: (i) ensure an additional 14,300 Dekatherms per day ("Dts/d")/d of firm service to four customers, (ii) provide additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (iii) represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Construction of the project began in January 2020, and interim services in advance of this project generated additional gross margin of $0.5 million and $1.2 million for the three and six months ended June 30, 2021, respectively. The estimated annual gross margin from this project including natural gas distribution service in Somerset County, Maryland, is approximately $4.1 million in 2021 and $6.7 million annually thereafter.

Callahan Intrastate Pipeline

Peninsula Pipeline completed the construction of a jointly owned intrastate transmission pipeline with Seacoast Gas Transmission in Nassau County, Florida in June 2020. The 26-mile pipeline serves growing demand for energy in both Nassau and Duval Counties. For the three and six months ended June 30, 2021, the project generated $1.6 million and $3.7 million, respectively, in additional gross margin, which includes margin from natural gas distribution service. The estimated annual gross margin from this project including natural gas distribution service is approximately $7.6 million in 2021 and beyond.

Guernsey Power Station

Guernsey Power Station and our affiliate, 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 firm natural gas transportation service to this facility. Guernsey Power Station commenced construction of the project in October 2019. In the second quarter of 2021, Aspire Energy Express commenced construction of the gas transmission facilities to provide the firm transportation service to the power generation facility. For the six months ended June 30, 2021, we received approximately $0.1 million, related to the construction delay of the in-service date of the project. The project is expected to be in service in the fourth quarter of 2021, and produce gross margin of approximately $0.5 million in 2021 and $1.5 million in 2022 and beyond.

Winter Haven Expansion

In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use the additional firm service to support new incremental load due to growth in the area, including providing service most immediately to a new can manufacturing facility, as well as provide reliability and operational benefits to CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. We expect this expansion to generate additional gross margin of $0.4 million beginning in 2022 and beyond.

Beachside Pipeline Expansion

In June 2021, Peninsula Pipeline and Florida City Gas entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline will construct approximately 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida, area east under the ICW and southward on the barrier island. We expect this expansion to generate additional annual gross margin of $2.5 million in 2023 and beyond.

CNG Transportation

Marlin Gas Services provides CNG temporary hold services, contracted pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. While margin was slightly down for the quarter by $0.4 million, on a year-to-date basis, Marlin Gas Services generated additional gross margin of $0.3 million. We estimate that Marlin Gas Services will generate annual gross margin of approximately $7.9 million in 2021 and $8.5 million in 2022, with the potential for additional growth in future years. Marlin Gas Services continues to actively expand the territories it serves, as well as leverage its patented technology to serve other markets, including pursuing liquefied natural gas transportation opportunities and RNG transportation opportunities from diverse supply sources to various pipeline interconnection points, as further outlined below.

RNG Transportation

Noble Road Landfill RNG Project

In September 2020, Fortistar and Rumpke Waste & Recycling announced commencement of construction of the Noble Road Landfill RNG Project in Shiloh, Ohio. The project includes the construction of a new state-of-the-art facility that will utilize

43

advanced, patented technology to treat landfill gas by removing carbon dioxide and other components to purify the gas and produce pipeline quality RNG. Aspire Energy has begun constructing an approximately 17.5 mile pipeline to inject the RNG from this project to its system for distribution to end use customers. Once flowing, the RNG volume will represent nearly 10 percent of Aspire Energy’s gas gathering volumes.

Bioenergy DevCo

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

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

CleanBay Project

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

At the present time, we expect to generate $0.2 million in 2021 in incremental margin from these RNG transportation projects beginning in 2021. Timing of incremental margin from RNG transportation projects is dependent upon the construction schedules of each project. As we continue to finalize contract terms and complete the necessary permitting associated with each of these projects, additional information will be provided regarding incremental margin. In addition to these projects, the Company is continuing to pursue other RNG projects that provide opportunities for the Company across the entire value chain.

Acquisitions

Elkton Gas

In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland. The purchase price was approximately $15.6 million, which included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland. For the three and six months ended June 30, 2021 we generated $0.7 million and $2.1 million, respectively, in additional gross margin from Elkton Gas and estimate that this acquisition will generate gross margin of approximately $4.0 million in 2021 and $4.1 million thereafter.

Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired. The acquisition was accounted for as a business combination within our Unregulated Energy Segment in the fourth quarter of 2020. We generated $0.4 million and $0.9 million in additional gross margin for the three and six months ended June 30, 2021, respectively, from Western Natural Gas and we estimate that this acquisition will generate gross margin of approximately $2.1 million in 2021 and growing to $2.3 million in 2022, with additional opportunities for growth.

Escambia Meter Station

In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light’s Crist Lateral pipeline. The Florida Power & Light Crist Lateral provides gas supply to their natural gas fired power plant owned by Florida Power & Light in Pensacola, Florida. We generated $0.1 million in additional gross margin in the second quarter of 2021 and we estimate that this acquisition will generate gross margin of approximately $0.6 million in 2021 and growing to $1.0 million in 2022.

Regulatory Initiatives

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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 $178.9 million of capital expenditures to replace 333 miles of qualifying distribution mains, including $13.0 million of new pipes during the first six months of 2021. We expect to generate annual gross margin of approximately $16.8 million in 2021, and $17.9 million in 2022.

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.

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. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs, and included costs related to Hurricane Dorian.

In September 2019, FPU filed a petition with the Florida PSC, for approval of its consolidated electric depreciation rates. The petition was joined to the Hurricane Michael docket. The approved rates, which were part of the settlement agreement in September 2020 that is described below, were retroactively applied effective January 1, 2020.

In September 2020, the Florida PSC approved a settlement agreement between FPU and the Office of the Public Counsel regarding final cost recovery and rates associated with Hurricane Michael. Previously, in late 2019, the Florida PSC approved an interim rate increase, subject to refund, effective January 1, 2020, associated with the restoration effort following Hurricane Michael. We fully reserved these interim rates, pending a final resolution and settlement of the limited proceeding. The settlement agreement allowed us to: (a) refund the over-collection of interim rates through the fuel clause; (b) record regulatory assets for storm costs in the amount of $45.8 million including interest which will be amortized over six years; (c) recover these storm costs through a surcharge for a total of $7.7 million annually; and (d) collect an annual increase in revenue of $3.3 million to recover capital costs associated with new plant investments and a regulatory asset for the cost of removal and undepreciated plant. The new base rates and storm surcharge were effective on November 1, 2020. The following table summarizes the impact of Hurricane Michael regulatory proceeding for the three and six months ended June 30, 2021:

	Three Months Ended		Six Months Ended
(in thousands)	June 30, 2021		June 30, 2021
Gross Margin	$	3,145	$	5,720
Depreciation	(305)		(608)
Amortization of regulatory assets	2,079		4,158
Operating income	1,371		2,170
Amortization of liability associated with interest expense	(310)		(637)
Pre-tax income	1,681		2,807
Income tax expense	457		749
Net income	$	1,224	$	2,058

Capital Cost Surcharge Programs

In December 2019, the FERC approved Eastern Shore’s capital cost surcharge which became effective January 1, 2020. The surcharge, an approved item in the settlement of Eastern Shore’s last general rate case, allows Eastern Shore to recover capital costs associated with mandated highway or railroad relocation projects that required the replacement of existing Eastern Shore facilities. Eastern Shore expects to produce gross margin of approximately $1.2 million in 2021 and $2.0 million in 2022 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

Elkton Gas STRIDE Plan

In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement ("STRIDE") plan with the Maryland PSC. The STRIDE plan proposes to increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of a fixed charge rider through a proposed 5-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. In June 2021, we reached a settlement with the Maryland PSC Staff and

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the Maryland Office of the Peoples Counsel. The STRIDE plan is expected to go into service in the third quarter of 2021 and is expected to generate less than $0.1 million of margin for the remainder of the year. We expect to generate $0.3 million of additional gross margin from the STRIDE plan in 2022 and $0.4 million annually thereafter.

COVID-19 Regulatory Proceeding

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset will allow us to seek recovery of these costs in the next base rate proceedings. In November 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset treatment, contending that the order should be a reversed or modified and to request a hearing on the protest. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allows the business units to establish a regulatory asset of $2.1 million. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units will amortize the amount over two years beginning January 1, 2022 and recover the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric division. This results in annual additional gross margin of $1.0 million that will be offset by a corresponding amortization of regulatory asset expense for both 2022 and 2023.

Other major factors influencing gross margin

Weather Impact

Weather was not a significant factor in the second quarter. For the six-month period, weather conditions accounted for a $5.9 million increased gross margin compared to the same period in 2020, primarily due to an 8.7 percent increase in HDDs that resulted in increased customer consumption. Assuming normal temperatures, as detailed below, gross margin would have been higher by $1.9 million. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") the three and six months ended June 30, 2021 and 2020.

	Three Months Ended			Six Months Ended
	June 30,			June 30,
	2021	2020	Variance	2021	2020	Variance
Delmarva Peninsula
Actual HDD	400	514	(114)	2,586	2,373	213
10-Year Average HDD ("Normal")	396	400	(4)	2,676	2,749	(73)
Variance from Normal	4	114		(90)	(376)
Florida
Actual HDD	69	41	28	572	410	162
10-Year Average HDD ("Normal")	43	43	—	549	613	(64)
Variance from Normal	26	(2)		23	(203)
Ohio
Actual HDD	676	801	(125)	3,448	3,297	151
10-Year Average HDD ("Normal")	623	593	30	3,582	3,612	(30)
Variance from Normal	53	208		(134)	(315)
Florida
Actual CDD	826	949	(123)	1,010	1,272	(262)
10-Year Average CDD ("Normal")	966	975	(9)	1,161	1,143	18
Variance from Normal	(140)	(26)		(151)	129

Natural Gas Distribution Margin Growth

Customer growth for our natural gas distribution operations, as a result of the addition of new customers and the conversion of customers from alternative fuel sources to natural gas service, generated $0.8 million and $1.7 million of additional margin for the three and six months ended June 30, 2021, respectively. The average number of residential customers served on the Delmarva Peninsula increased by 4.4 percent and 4.5 percent for the three and six months ended June 30, 2021, while Florida increased by and 5.2 percent and 5.1 percent, for the three and six months ended June 30, 2021, respectively. A larger

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percentage of the margin growth was generated from residential growth given the expansion of natural gas into new housing communities and conversions to natural gas as the Company's distribution infrastructure continues to build out. In addition, as new communities continue to build out due to population growth and infrastructure is added to support the growth, there is also increased load from new commercial and industrial customers. The details for the three and six months ended June 30, 2021 are provided in the following table:

	Three Months Ended				Six Months Ended
	June 30, 2021				June 30, 2021
(in thousands)	Delmarva Peninsula		Florida		Delmarva Peninsula		Florida
Customer Growth:
Residential	$	333	$	274	$	823	$	580
Commercial and industrial	102		43		173		115
Total Customer Growth	$	435	$	317	$	996	$	695

Regulated Energy Segment

For the quarter ended June 30, 2021, compared to the quarter ended June 30, 2020:

	Three Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	80,910	$	73,518	$	7,392
Cost of sales	14,447		16,387		(1,940)
Gross margin	66,463		57,131		9,332
Operations & maintenance	26,882		25,456		1,426
Depreciation & amortization	11,830		9,347		2,483
Other taxes	4,943		4,322		621
Total operating expenses	43,655		39,125		4,530
Operating income	$	22,808	$	18,006	$	4,802

Operating income for the Regulated Energy segment for the second quarter of 2021 was $22.8 million, an increase of $4.8 million, or 26.7 percent, over the same period in 2020. Higher operating income reflects continued pipeline expansions by Eastern Shore and Peninsula Pipeline, increased consumption from return to pre-pandemic consumption levels, organic growth in our natural gas distribution businesses, operating results from the Elkton Gas acquisition completed in the third quarter of 2020, and timing of the impact of the Hurricane Michael regulatory proceeding settlement, which was settled in the third quarter of 2020. The margin increases were offset by higher depreciation, amortization and property taxes, including amortization of the regulatory asset associated with the Hurricane Michael regulatory proceeding settlement, new expenses associated with Elkton Gas, and higher other operating expenses. The operating expense increases were also partially offset by $1.6 million due to lower pandemic expenses and the regulatory deferral of COVID-19 expenses. While the Hurricane Michael settlement positively impacted the quarter, the full year impact for 2021 is expected to be negligible.

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

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(in thousands)
Margin contribution from the Hurricane Michael regulatory proceeding settlement	$	3,145
Eastern Shore and Peninsula Pipeline service expansions	2,259
Increased customer consumption - primarily due to a return to pre-pandemic conditions	1,769
Natural gas growth (excluding service expansions)	752
Margin contribution from the Elkton Gas acquisition (completed in July 2020)	746
Florida GRIP	572
Other variances	89
Quarter-over-quarter increase in gross margin	$	9,332

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

Margin Contribution from Hurricane Michael Regulatory Proceeding Settlement

We generated $3.1 million in additional gross margin as a result of the settlement of the Hurricane Michael regulatory proceeding. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information. While the Hurricane Michael settlement positively impacted the period, on an annual basis, the incremental impact year-over-year (2021 vs. 2020) is expected to be negligible.

Eastern Shore and Peninsula Pipeline Service Expansions

We generated additional gross margin of $1.8 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $0.5 million from Eastern Shore's Del-Mar Energy Pathway project.

Increased customer consumption - primarily due to return to a pre-pandemic consumption

The absence of unfavorable COVID-19 impacts, resulted in a return to pre-pandemic consumption, positively impacting gross margin by $1.8 million for the three months ended June 30, 2021 compared to the same period in 2020.

Natural Gas Distribution Customer Growth

We generated additional gross margin of $0.7 million from natural gas customer growth. Gross margin increased by $0.3 million in Florida and $0.4 million on the Delmarva Peninsula for the three months ended June 30, 2021, as compared to the same period in 2020, due primarily to residential customer growth of 4.4 percent and 5.2 percent on the Delmarva Peninsula and in Florida, respectively.

Elkton Gas

Gross margin increased by $0.7 million due to margin contributed from Elkton Gas which was acquired in July 2020.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $0.6 million in second quarter of 2021 compared to the same period in 2020.

Operating Expenses

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

(in thousands)
Hurricane Michael regulatory proceeding settlement - depreciation and amortization impact	$	1,774
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	1,568
Payroll, benefits and other employee-related expenses due to growth	1,157
Depreciation, asset removal and property tax costs due to new capital investments	1,108
Operating expenses from the Elkton Gas acquisition	510
Reduction in expenses associated with the COVID-19 pandemic	(811)
Regulatory deferral of COVID-19 expenses per PSCs orders	(748)
Other variances	(28)
Quarter-over-quarter increase in operating expenses	$	4,530

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For the Six Months Ended June 30, 2021, compared to the six months ended June 30, 2020:

	Six Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	202,107	$	176,473	$	25,634
Cost of sales	57,491		51,219		6,272
Gross margin	144,616		125,254		19,362
Operations & maintenance	54,886		51,697		3,189
Depreciation & amortization	23,860		18,666		5,194
Other taxes	10,197		8,997		1,200
Total operating expenses	88,943		79,360		9,583
Operating income	$	55,673	$	45,894	$	9,779

Operating income for the Regulated Energy segment for the first six months of 2021 was $55.7 million, an increase of $9.8 million, or 21.3 percent, over the same period in 2020. Higher operating income reflects continued pipeline expansions by Eastern Shore and Peninsula Pipeline, operating results from the Elkton Gas acquisition completed in the third quarter of 2020, and increased consumption from a return to pre-pandemic consumption levels. Further contributing to the operating income growth was margin from organic growth in the our natural gas distribution businesses and increased consumption driven primarily by colder weather compared to the same period of 2020, and timing of the impact of the Hurricane Michael regulatory proceeding settlement. The margin increases were offset by higher depreciation, amortization and property taxes, including amortization of the regulatory asset associated with the Hurricane Michael regulatory proceeding settlement, new expenses associated with Elkton Gas, and higher other operating expenses. The operating expense increases were partially offset by $2.0 million due to lower pandemic expenses and the regulatory deferral of COVID-19 expenses. While the Hurricane Michael settlement positively impacted the period, on an annual basis, the incremental impact year-over-year (2021 vs. 2020) is expected to be negligible.

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

(in thousands)
Margin contribution from the Hurricane Michael regulatory proceeding settlement	$	5,720
Eastern Shore and Peninsula Pipeline service expansions	5,239
Margin contribution from the Elkton Gas acquisition (completed in July 2020)	2,059
Increased customer consumption - primarily due to a return to pre-pandemic conditions	1,798
Natural gas growth (excluding service expansions)	1,691
Increased customer consumption - primarily weather related	1,314
Florida GRIP	931
Sandpiper Energy infrastructure rider associated with conversions	455
Other variances	155
Period-over-period increase in gross margin	$	19,362

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

Margin Contribution from Hurricane Michael Regulatory Proceeding Settlement

We generated $5.7 million in additional gross margin as a result of the settlement of the Hurricane Michael regulatory proceeding. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information. While the Hurricane Michael settlement positively impacted the period, on an annual basis, the incremental impact year-over-year (2021 vs. 2020) is expected to be negligible.

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Eastern Shore and Peninsula Pipeline Service Expansions

We generated additional gross margin of $4.0 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $1.2 million from Eastern Shore's Del-Mar Energy Pathway project.

Elkton Gas

Gross margin increased by $2.1 million due to margin contributed from Elkton Gas which was acquired in July 2020.

Increased customer consumption - primarily due to return to pre-pandemic conditions

The absence of unfavorable COVID-19 impacts during the first six months of 2021, resulted in a return to pre-pandemic consumption, positively impacting gross margin by $1.8 million compared to the same period in 2020.

Natural Gas Distribution Customer Growth

We generated additional gross margin of $1.7 million from natural gas customer growth. Gross margin increased by $0.7 million in Florida and $1.0 million on the Delmarva Peninsula for the six months ended June 30, 2021, as compared to the same period in 2020, due primarily to residential customer growth of 4.5 percent and 5.1 percent on the Delmarva Peninsula and in Florida, respectively.

Increased Customer Consumption - Primarily Weather Related

Gross margin increased by $1.3 million for the for the six months ended June 30, 2021, compared to the same period in 2020, primarily due to a 9 percent increase in HDDs on the Delmarva Peninsula and a 40 percent increase in HDDs in Florida that resulted in increased customer consumption of energy.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $0.9 million for the six months ended June 30, 2021 compared to the same period in 2020.

Sandpiper Infrastructure Rider Associated with Conversions

We generated additional margin of $0.5 million associated with the conversion of Sandpiper's propane customers to natural gas customers for the six months ended June 30, 2021 compared to the same period in 2020.

Operating Expenses

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

(in thousands)
Hurricane Michael regulatory proceeding settlement - depreciation and amortization impact	$	3,550
Depreciation, asset removal and property tax costs due to new capital investments	2,500
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	2,459
Payroll, benefits and other employee-related expenses due to growth	1,958
Operating expenses from the Elkton Gas acquisition	1,034
Reduction in expenses associated with the COVID-19 pandemic	(1,078)
Regulatory deferral of COVID-19 expenses per PSCs orders	(944)
Other variances	104
Period-over-period increase in operating expenses	$	9,583

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Unregulated Energy Segment

For the quarter ended June 30, 2021, compared to the quarter ended June 30, 2020:

	Three Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	34,773	$	27,741	$	7,032
Cost of sales	16,821		10,709		6,112
Gross margin	17,952		17,032		920
Operations & maintenance	14,017		12,959		1,058
Depreciation & amortization	3,456		2,889		567
Other taxes	924		903		21
Total operating expenses	18,397		16,751		1,646
Operating income	$	(445)	$	281	$	(726)

Operating results for the Unregulated Energy segment for the second quarter of 2021 declined by $0.7 million compared to the same period in 2020. The operating results for this segment typically exhibit seasonality with the first and fourth quarters producing higher results due to colder temperatures. The results for the second quarter are not indicative of the results for the entire year.

Lower operating results during the second quarter were driven by higher operating expenses, depreciation, amortization and property taxes related to recent capital investments, and expenses associated with Western Natural Gas. Lower performance by Marlin Gas Services resulting from reduced customer demand for pipeline integrity and emergency services during the quarter also contributed to this decrease. Operating expenses were partially offset by increased gross margin generated from the acquisition of Western Natural Gas and by Aspire Energy as well as consumption in the propane businesses returning towards pre-pandemic levels.

Gross Margin

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

(in thousands)
Propane Operations
Western Natural Gas acquisition (completed in October 2020)	$	389
Increased customer consumption - primarily due to a return to pre-pandemic conditions	204
Marlin Gas Services
Decreased demand for CNG services	(400)
Aspire Energy
Increased margin including improvements from natural gas liquid processing	677
Other variances	50
Quarter-over-quarter increase in gross margin	$	920

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

Propane Operations

•Western Natural Gas - Gross margin increased by $0.4 million due to the margin generated from Western Natural Gas, which was acquired by Sharp in October 2020.

•Increased Customer Consumption - primarily due to a return to pre-pandemic conditions - Gross margin increased due to the absence of unfavorable COVID-19 impacts, resulted in a return to pre-pandemic consumption, positively impacting gross margin by $0.2 million for the three months ended June 30, 2021 compared to the same period in 2020.

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Marlin Gas Services

•Gross margin decreased by $0.4 million during the second quarter of 2021, as compared to the same period in the prior year due to lower demand for CNG hold services.

Aspire Energy

•Gross margin increased by $0.7 million during the second quarter of 2021 over the same period in 2020, including improvements from natural gas liquid processing.

Other Operating Expenses

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

(in thousands)
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	$	705
Depreciation, amortization and property tax costs due to new capital investments	559
Operating expenses from the Western Natural Gas acquisition	269
Payroll, benefits and other employee-related expenses due to growth	231
Reduction in expenses associated with the COVID-19 pandemic	(418)
Other variances	300
Quarter-over-quarter increase in operating expenses	$	1,646

For the six months ended June 30, 2021, compared to the six months ended June 30, 2020:

	Six Months Ended
	June 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	109,532	$	81,752	$	27,780
Cost of sales	52,804		32,938		19,866
Gross margin	56,728		48,814		7,914
Operations & maintenance	29,178		26,996		2,182
Depreciation & amortization	6,780		5,806		974
Other taxes	2,110		1,870		240
Total operating expenses	38,068		34,672		3,396
Operating income	$	18,660	$	14,142	$	4,518

Operating income for the Unregulated Energy segment for the six months ended June 30, 2021 was $18.7 million, an increase of $4.5 million or 31.9 percent, over the same period in 2020. Higher operating income resulted from increased consumption driven primarily by colder weather compared to the first half of 2020, higher retail propane margins per gallon, and contributions from the acquisition of the Western Natural Gas propane assets. These margin increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments, new expenses associated with Western Natural Gas and higher other operating expenses. The operating expense increases were partially offset by $0.6 million due to lower pandemic related costs.

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Gross Margin

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

(in thousands)
Propane Operations
Increased customer consumption - primarily weather related	$	3,701
Increased retail propane margins per gallon driven by favorable supply costs	1,137
Western Natural Gas acquisition (completed in October 2020)	939
Marlin Gas Services
Increased demand for CNG services	331
Aspire Energy
Increased customer consumption - primarily weather related	921
Improved margin including natural gas liquid processing	691
Other variances	194
Period-over-period increase in gross margin	$	7,914

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

Propane Operations

•Increased Customer Consumption Primarily Weather Related - Gross margin increased by $3.7 million, as weather on the Delmarva Peninsula was 9 percent colder for the six months ended June 30, 2021 compared to the same period in 2020.

•Increased Retail Propane Margins - Gross margin increased by $1.1 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.

•Western Natural Gas - Gross margin increased by $0.9 million due to the margin generated from Western Natural Gas, which was acquired by Sharp in October 2020.

Marlin Gas Services

•Gross margin increased by $0.3 million for the six months ended June 30, 2021, as compared to the same period in the prior year due to higher demand for CNG hold services.

Aspire Energy

•Increased Customer Consumption Primarily Weather Related - Gross margin increased by $0.9 million due to higher consumption of gas as weather in Ohio was approximately 5 percent colder for the six months ended June 30, 2021 over the same period in 2020.

•Improved Margin including natural gas liquid processing - Gross margin increased by $0.7 million including improvements from natural gas liquid processing for the six months ended June 30, 2021, as compared to the same period in 2020.

Other Operating Expenses

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

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(in thousands)
Depreciation, amortization and property tax costs due to new capital investments	$	1,066
Facilities and maintenance costs and outside services associated with a return to pre-pandemic conditions	921
Payroll, benefits and other employee-related expenses due to growth	723
Operating expenses from the Western Natural Gas acquisition	607
Insurance expense (non-health)	347
Reduction in expenses associated with the COVID-19 pandemic	(620)
Other variances	352
Period-over-period increase in operating expenses	$	3,396

OTHER EXPENSE, NET

For the quarter ended June 30, 2021 compared to the quarter ended June 30, 2020

Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, increased by $1.7 million in the second quarter of 2021, compared to the same period in 2020. The increase was primarily due to gains recognized on the sales of Community Gas Systems ("CGS") from our affiliate Sharp to our Delaware Division, in conjunction with the acquisitions of the CGS and conversion of customers from propane to natural gas service.

For the six months ended June 30, 2021 compared to the six months ended June 30, 2020

Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, decreased by $1.2 million in the first six months of 2021, compared to the same period in 2020. The decrease was primarily due to gains on two property sales which were completed in the first quarter of 2020, partially offset by gains from the sales of CGS from Sharp to our Delaware Division as discussed in the preceding paragraph.

INTEREST CHARGES

For the quarter ended June 30, 2021 compared to the quarter ended June 30, 2020

Interest charges were $5.1 million for both quarters ended June 30, 2021 and 2020.

For the six months ended June 30, 2021 compared to the six months ended June 30, 2020

Interest charges for the six months ended June 30, 2021 decreased by $0.7 million, compared to the same period in 2020, attributable primarily to a decrease of $0.9 million in lower interest expense from lower levels outstanding under our revolving credit facilities, and $0.6 million of an amortization credit/reduction in interest expense associated with a regulatory liability that was established in connection with the Hurricane Michael regulatory proceeding settlement. Partially offsetting the interest savings was an increase of $0.5 million in interest expense as a result of several long-term debt placements in 2020 and $0.4 million due to lower capitalized interest associated with growth projects.

INCOME TAXES

For the quarter ended June 30, 2021 compared to the quarter ended June 30, 2020

Income tax expense was $5.2 million for the quarter ended June 30, 2021, compared to $2.0 million for the quarter ended June 30, 2020. Our effective income tax rate was 27.2 percent and 15.7 percent, for the three months ended June 30, 2021 and 2020, respectively. The second quarter of 2021 included a favorable income tax impact associated with the CARES Act that reduced the effective tax rate by 13.2 percent, from 28.9 percent to 15.7 percent.

For the six months ended June 30, 2021 compared to the six months ended June 30, 2020

Income tax expense was $17.6 million for the six months ended June 30, 2021, compared to $12.6 million for the six months ended June 30, 2020. Our effective income tax rate was 26.7 percent and 24.1 percent, for the six months ended June 30, 2021 and 2020, respectively. The second quarter included a favorable income tax impact associated with the CARES Act that reduced the effective tax rate on a year to date basis by 3.2 percent, from 27.3 percent to 24.1 percent.

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FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to maintain our capital structure within our target capital structure range. We maintain an effective shelf registration statement with the SEC for the issuance of shares of common stock in various types of equity offerings, including shares of common stock under our ATM equity program, as well as an effective registration statement with respect to the DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may consider issuing additional shares under the direct share purchase component of the DRIP and/or under the ATM equity program. Beginning in the third quarter of 2020, we issued shares of common stock under both the DRIP and the ATM equity program.

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

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $107.8 million for the six months ended June 30, 2021. In the table below, we have provided a range of our forecasted capital expenditures for 2021:

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

The 2021 forecast, which excludes any potential acquisitions, includes capital expenditures associated with the following projects: Delmarva Natural Gas distribution's Somerset County expansion, Eastern Shore's Del-Mar Energy Pathway, Florida's Western Palm Beach County expansion and other potential pipeline projects, continued expenditures under the Florida GRIP, further expansions of our natural gas distribution and transmission systems, continued natural gas and electric system infrastructure improvement activities, facilities to support Marlin Gas Services' CNG transport growth and expansion into RNG and LNG transport, information technology systems, and other strategic initiatives and investments, including renewable energy investments.

The capital expenditure projection is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, capital delays due to COVID-19 that are greater than currently anticipated, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.

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

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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 June 30, 2021 and December 31, 2020:

	June 30, 2021				December 31, 2020
(in thousands)
Long-term debt, net of current maturities	$	498,450	40	%	$	508,499	42	%
Stockholders’ equity	741,564		60	%	697,085		58	%
Total capitalization, excluding short-term debt	$	1,240,014	100	%	$	1,205,584	100	%
	June 30, 2021				December 31, 2020
(in thousands)
Short-term debt	$	169,294	12	%	$	175,644	13	%
Long-term debt, including current maturities	512,050		36	%	522,099		37	%
Stockholders’ equity	741,564		52	%	697,085		50	%
Total capitalization, including short-term debt	$	1,422,908	100	%	$	1,394,828	100	%

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was 52 percent as of June 30, 2021. We seek to align permanent financing with the in-service dates of our capital projects. We may utilize more temporary short-term debt when the financing cost is attractive as a bridge to the permanent long-term financing or if the equity markets are volatile.

In the third and fourth quarters of 2020, we issued 1.0 million shares of common stock through our DRIP and the ATM programs and received net proceeds of approximately $83.0 million which was added to the general funds and then used to pay down short-term borrowing. In the first six months of 2021, we issued less than 0.1 million shares at an average price per share of $113.51 and received net proceeds of $4.5 million under the DRIP. See Note 9, Stockholders’ Equity, in the condensed consolidated financial statements for additional information on commissions and fees paid in connection with these issuances.

We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at June 30, 2021:

(in thousands)	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (1)	150,000		—		—		150,000
NYL Shelf Agreement (1)	150,000		(140,000)		—		10,000
Total Shelf Agreements as of June 30, 2021	$	670,000	$	(360,000)	$	—	$	310,000

(1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively.

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

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Short-term Borrowings

We are authorized by our Board of Directors to borrow up to $400 million of short-term debt, as required. At June 30, 2021 and December 31, 2020, we had $169.3 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent, respectively. Included in the June 30, 2021 balance is $100.0 million in short-term debt for which we have entered into interest rate swap agreements.

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

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of June 30, 2021, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon our total indebtedness to total capitalization ratio. As of June 30, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the new Revolver at June 30, 2021 was $200.9 million. As of June 30, 2021, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the six months ended June 30, 2021 and 2020:

	Six Months Ended
	June 30,
(in thousands)	2021		2020
Net cash provided by (used in):
Operating activities	$	134,216	$	91,678
Investing activities	(104,529)		(80,254)
Financing activities	(28,175)		(14,819)
Net increase (decrease) in cash and cash equivalents	1,512		(3,395)
Cash and cash equivalents—beginning of period	3,499		6,985
Cash and cash equivalents—end of period	$	5,011	$	3,590

57

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 working capital. Changes in working capital 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.

During the six months ended June 30, 2021 and 2020, net cash provided by operating activities was $134.2 million and $91.7 million, respectively, resulting in an increase in cash flows of $42.5 million. Significant operating activities generating the cash flows change were as follows:

•Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities increased cash flows by $20.4 million;

•Net income, adjusted for non-cash adjustments and reconciling activities, increased cash flows by $13.2 million, due primarily to higher net income, depreciation and amortization and gain on sale of assets;

•Net cash flows from income taxes receivable increased by $6.0 million;

•Changes in net prepaid expenses and other current assets, customer deposits and refunds, accrued compensation and other net assets and liabilities, increased cash flows by $4.6 million;

•Changes in net regulatory assets and liabilities increased cash flows by $3.6 million due primarily to the change in fuel costs collected through the various cost recovery mechanisms; and

•Net cash flows from changes in propane inventory, storage gas and other inventories decreased by approximately $5.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $104.5 million and $80.3 million during the six months ended June 30, 2021 and 2020, respectively, resulting in a decrease in cash flows of $24.2 million. Cash paid for capital expenditures was $104.6 million for the first six months of 2021, compared to $82.8 million for the same period in 2020, resulting in decreased cash flows of $21.8 million. The remaining decrease was largely attributable to several property sales that occurred in the first quarter of 2020.

Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $28.2 million during the six months ended June 30, 2021 compared to $14.8 million of net cash used in financing activities over the same period in 2020, resulting in a decrease in cash flows of $13.4 million. The increase in net cash used in financing activities resulted primarily from the following:

•Long-term debt repayments of $10.1 million and repayments of short-term debt of $5.2 million;

•Cash dividends of $15.0 million paid during the six months ended June 30, 2021, compared to $13.0 million for the six months ended June 30, 2020; and

•Cash flows of $4.8 million as a result of issuing shares of our common stock under the DRIP program

Off-Balance Sheet Arrangements

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of June 30, 2021 was $20.0 million. The aggregate amount guaranteed at June 30, 2021 was $8.0 million, with the guarantees expiring on various dates through March 30, 2022.

As of June 30, 2021, we have issued letters of credit totaling approximately $4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, to our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn upon these letters of credit as of June 30, 2021 and do not anticipate that the counterparties will draw upon these letters of credit. We expect that they will be renewed to the extent necessary in the future. Additional information is presented in Note 7, Other Commitments and Contingencies, in the condensed consolidated financial statements.

Contractual Obligations

There has been no material change in the contractual obligations presented in our 2020 Annual Report on Form 10-K, except for commodity purchase obligations entered into in the ordinary course of our business. The following table summarizes commodity purchase contract obligations at June 30, 2021:

58

	Payments Due by Period
	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Purchase obligations - Commodity (1)	$	29,826	$	27,879	$	—	$	—	$	57,705
Total	$	29,826	$	27,879	$	—	$	—	$	57,705

(1) In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively. At June 30, 2021, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 5, Rates and Other Regulatory Activities, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments, applicable to us, and their impact on our financial position, results of operations and cash flows are described in Note 1, Summary of Accounting Policies, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

59

Item 3. 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. Increases in interest rates expose us to potential increased costs we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. We utilize interest rate swap agreements to mitigate short-term borrowing rate risk. Additional information about our long-term debt and short-term borrowing is disclosed in Note 15, Long-Term Debt, and Note 16, Short-Term Borrowings, respectively, in the condensed 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 respective PSCs that allow us to recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.

Unregulated Energy Segment

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

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

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

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2020 to June 30, 2021:

(in thousands)	Balance at December 31, 2020		Increase (Decrease) in Fair Market Value		Less Amounts Settled		Balance at June 30, 2021
Sharp	$	3,182	$	8,059	$	(3,502)	$	7,739
Total	$	3,182	$	8,059	$	(3,502)	$	7,739

There were no changes in methods of valuations during the six months ended June 30, 2021.

The following is a summary of fair market value of financial derivatives as of June 30, 2021, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2021		2022		2023		2024		2025		Total Fair Value
Price based on Mont Belvieu - Sharp	$	2,971	$	2,937	$	1,236	$	595	$	—	$	7,739
Total	$	2,971	$	2,937	$	1,236	$	595	$	—	$	7,739

60

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 Note 13, Derivative Instruments, in the condensed 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.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of June 30, 2021. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2021.

Changes in Internal Control over Financial Reporting

In response to the COVID-19 pandemic and the current social distancing restrictions that have been established in our service territories, we have implemented our pandemic response plan, which includes having office staff work remotely to promote social distancing in efforts to reduce the spread of COVID-19. During the quarter ended June 30, 2021, our pandemic response plan did not result in a change in the design or operations of our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

61

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 7, Other Commitments and Contingencies, of the condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2020, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating Chesapeake Utilities, our business and the forward-looking statements contained in this Quarterly Report on Form 10-Q.

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

The cybersecurity risks associated with the protection of our infrastructure and facilities is evolving and increasingly complex. We continue to heavily rely on technological tools that support our business operations and corporate functions while enhancing our security. There are various risks associated with our information technology infrastructure, including hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, cyber-attacks, cyber-terrorism, data breaches, programming mistakes, and other inadvertent errors or deliberate human acts. Further, the U.S. government has issued public warnings that indicate energy assets might be specific targets of cybersecurity threats by foreign sources.

The failure of, or security breaches related to, our information technology infrastructure, could lead to system disruptions or cause facility shutdowns. Any such failure, attack, or security breach could adversely impact our ability to safely and reliably deliver services to our customers through our transmission, distribution, and generation systems, subject to us to reputational and other harm, and subject us to legal and regulatory proceedings and claims and demands from third parties, any of which could adversely affect our business, our earnings, results of operation and financial condition. In addition, the protection of customer, employee and Company data is crucial to our operational security. A breach or breakdown of our systems that results in the unauthorized release of individually identifiable customer or other sensitive data could have an adverse effect on our reputation, results of operations and financial condition and could also materially increase our costs of maintaining our system and protecting it against future breakdowns or breaches. We take reasonable precautions to safeguard our information systems from cyber-attacks and security breaches; however, there is no guarantee that the procedures implemented to protect against unauthorized access to our information systems are adequate to safeguard against all attacks and breaches. We also cannot assure that any redundancies built into our networks and technology, or the procedures we have implemented to protect against cyber-attacks and other unauthorized access to secured data, are adequate to safeguard against all failures of technology or security breaches.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 

62

	Total Number of Shares	Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares That May Yet Be Purchased Under the Plans
Period	Purchased	per Share		or Programs (2)	or Programs (2)
April 1, 2021 through April 30, 2021(1)	442	$	116.18	—	—
May 1, 2021 through May 31, 2021	—	—		—	—
June 1, 2021 through June 30, 2021	—	—		—	—
Total	442	$	116.18	—	—

(1) Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts for certain directors and senior executives under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 9, Employee Benefit Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2020. During the quarter ended June 30, 2021, 442 shares were purchased through the reinvestment of dividends on deferred stock units.

(2) Except for the purposes described in Footnote (1), Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

    None.

63

Item 6.     Exhibits

10.1*	Amendment to Executive Employment Agreement dated February 22, 2021, between Chesapeake Utilities Corporation and Beth W. Cooper
31.1*	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2*	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1*	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
32.2*	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.
104	Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101

*Filed herewith

64

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President, Chief Financial Officer, and Assistant Corporate Secretary

Date: August 4, 2021

65

EX-10.1

Exhibit 10.1

EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Jeffry M. Householder, certify that:

1.I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2021 of Chesapeake Utilities Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 4, 2021

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder
President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1.I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2021 of Chesapeake Utilities Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b)designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b)any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 4, 2021

/S/ BETH W. COOPER

Beth W. Cooper
Executive Vice President, Chief Financial Officer, and Assistant Corporate Secretary

EX-32.1

EXHIBIT 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Jeffry M. Householder, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2021, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/s/ JEFFRY M. HOUSEHOLDER

Jeffry M. Householder

May 4, 2021

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Executive Vice President, Chief Financial Officer and Assistant Corporate Secretary of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2021, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ BETH W. COOPER

Beth W. Cooper

May 4, 2021

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

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	Jun. 30, 2021	Jul. 31, 2021
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Entity Incorporation, State or Country Code	DE
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Entity Address, Address Line One	909 Silver Lake Boulevard
Entity Address, City or Town	Dover
Entity Address, State or Province	DE
Entity Address, Postal Zip Code	19904
City Area Code	302
Local Phone Number	734-6799
Title of 12(b) Security	Common Stock - par value per share $0.4867
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Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Operating Revenues
Regulated Energy	$ 80,910	$ 73,518	$ 202,107	$ 176,473
Unregulated Energy and other	30,172	23,533	100,161	73,268
Total Operating Revenues	111,082	97,051	302,268	249,741
Operating Expenses
Regulated Energy cost of sales	14,447	16,387	57,491	51,219
Unregulated Energy and other cost of sales	12,254	6,575	43,506	24,611
Operations	36,371	34,605	75,810	70,557
Maintenance	4,259	4,143	8,300	7,979
Settlement Gain			(130)	(130)
Depreciation and amortization	15,298	12,247	30,662	24,500
Other taxes	5,875	5,247	12,324	10,894
Total Operating Expenses	88,504	79,074	228,093	189,630
Total operating income	22,578	17,977	74,175	60,111
Other income (expense), net	1,456	(279)	1,841	3,039
Interest charges	5,054	5,054	10,159	10,868
Income from Continuing Operations Before Income Taxes	18,980	12,644	65,857	52,282
Income Taxes on Continuing Operations	5,165	1,983	17,570	12,580
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	13,815	10,661	48,287	39,702
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	(2)	295	(8)	184
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886
Weighted Average Common Shares Outstanding:
Basic (shares)	17,546,346	16,448,490	17,516,273	16,431,724
Diluted (shares)	17,616,496	16,503,603	17,585,006	16,487,807
Basic Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share	$ 0.79	$ 0.65	$ 2.76	$ 2.42
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0	0.02	0	0.01
Basic (in dollars per share)	0.79	0.67	2.76	2.43
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share	0.78	0.64	2.75	2.41
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0	0.02	0	0.01
Diluted (in dollars per share)	$ 0.78	$ 0.66	$ 2.75	$ 2.42

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	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Comprehensive Income [Abstract]
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886
Amortization of prior service cost, net of tax of $(5), $(5), $(10) and $(10), respectively	(14)	(14)	(28)	(28)
Net gain, net of tax of $28, $28, $53 and $55, respectively	(78)	(80)	(156)	(160)
Unrealized gain on commodity contract cash flow hedges, net of tax of $1,193, $651, $1,257 and $653, respectively	3,126	1,703	3,291	1,710
Unrealized gain/(loss) on interest rate swap cash flow hedges, net of tax of $2, $(14), $1 and $(14), respectively	6	(37)	4	(37)
Other comprehensive income (loss)	3,196	1,732	3,423	1,805
Comprehensive Income (Loss), Net of Tax, Attributable to Parent	$ 17,009	$ 12,688	$ 51,702	$ 41,691

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Statement of Other Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (5)	$ (5)	$ (10)	$ (10)
Net gain, tax	28	28	53	55
Unrealized (loss)/gain on commodity contract cash flow hedges, tax	1,193	651	1,257	653
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	$ 2	$ (14)	$ 1	$ (14)

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Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2021		Dec. 31, 2020
Property, Plant and Equipment
Regulated Energy	$ 1,643,904		$ 1,577,576
Unregulated Energy	309,139		300,647
Other businesses and eliminations	34,767		30,769
Total property, plant and equipment	1,987,810		1,908,992
Less: Accumulated depreciation and amortization	(393,111)		(368,743)
Plus: Construction work in progress	78,187		60,929
Net property, plant and equipment	1,672,886		1,601,178
Current Assets
Cash and cash equivalents	5,011		3,499
Trade and other receivables	41,311		56,890
Accounts Receivable, Allowance for Credit Loss, Current	(3,895)		(4,785)
Accounts Receivable, before Allowance for Credit Loss, Current	45,206		61,675
Accrued revenue	13,370		21,527
Propane inventory, at average cost	6,076		5,906
Other inventory, at average cost	6,524		5,539
Regulatory assets	9,429		10,786
Storage gas prepayments	2,385		2,455
Income taxes receivable	8,371		12,885
Prepaid expenses	9,497		13,239
Derivative assets, at fair value	8,056		3,269
Other current assets	523		436
Total current assets	110,553		136,431
Deferred Charges and Other Assets
Goodwill	38,803		38,731
Other intangible assets, net	7,625		8,292
Investments, at fair value	11,745		10,776
Operating Lease, Right-of-Use Asset	10,020		11,194
Regulatory assets	109,244		113,806
Receivables and other deferred charges	11,464		12,079
Total deferred charges and other assets	188,901		194,878
Total Assets	1,972,340		1,932,487
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	0		0
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	8,550		8,499
Additional paid-in capital	357,520		348,482
Retained earnings	374,936		342,969
Accumulated other comprehensive income (loss)	558		(2,865)
Deferred compensation obligation	7,203		5,679
Treasury stock	(7,203)		(5,679)
Total stockholders’ equity	741,564	[1]	697,085
Long-term debt, net of current maturities	498,450		508,499
Total capitalization	1,240,014		1,205,584
Current Liabilities
Less: current maturities	13,600		13,600
Short-term borrowing	169,294		175,644
Accounts payable	49,408		60,253
Customer deposits and refunds	33,983		33,302
Accrued interest	2,697		2,905
Dividends payable	8,433		7,683
Accrued compensation	10,767		13,994
Regulatory liabilities	13,911		6,284
Derivative liabilities, at fair value	351		127
Other accrued liabilities	19,812		15,240
Total current liabilities	322,256		329,032
Deferred Credits and Other Liabilities
Deferred income taxes	219,490		205,388
Regulatory liabilities	143,681		142,736
Environmental liabilities	3,904		4,299
Other pension and benefit costs	29,463		30,673
Operating Lease, Liability, Noncurrent	8,719		9,872
Deferred investment tax credits and other liabilities	4,813		4,903
Total deferred credits and other liabilities	410,070		397,871
Environmental and other commitments and contingencies (Notes 5 and 6)
Total Capitalization and Liabilities	$ 1,972,340		$ 1,932,487

[1] 2,000,000 shares of preferred stock at $0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity.

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 3,895	$ 4,785
Common stock, par value (in dollars per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized (shares)	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Issued	0	0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Operating Activities
Net Income	$ 48,279	$ 39,886
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,662	24,500
Depreciation and accretion included in other costs	5,061	4,807
Deferred income taxes	12,810	12,232
Gain on sale of discontinued operations	0	(200)
Realized gain on commodity contracts and sale of assets	(5,342)	(3,496)
Unrealized (gain) loss on investments/commodity contracts	(988)	130
Employee benefits and compensation	(346)	21
Share-based compensation	3,315	2,322
Changes in assets and liabilities:
Accounts receivable and accrued revenue	23,664	11,455
Propane inventory, storage gas and other inventory	(1,085)	4,140
Regulatory assets/liabilities, net	7,711	4,133
Prepaid expenses and other current assets	2,789	6,016
Accounts payable and other accrued liabilities	6,563	(1,604)
Income taxes (payable) receivable	4,514	(1,480)
Customer deposits and refunds	681	(232)
Accrued compensation	(3,397)	(7,086)
Other assets and liabilities, net	(675)	(3,866)
Net cash provided by operating activities	134,216	91,678
Investing Activities
Property, plant and equipment expenditures	(104,631)	(82,779)
Proceeds from sale of assets	497	4,273
Proceeds from the sale of discontinued operations	0	200
Environmental expenditures	395	1,948
Net cash used in investing activities	(104,529)	(80,254)
Financing Activities
Common stock dividends	(15,047)	(12,976)
Issuance of stock under the Dividend Reinvestment Plan, net of offering fees	4,799	359
Tax withholding payments related to net settled stock compensation	(1,478)	(977)
Change in cash overdrafts due to outstanding checks	(1,101)	(1,690)
Net advances (repayments) under line of credit agreements	(5,249)	40,578
Repayment of long-term debt, net of offering fees	0	(13)
Repayment of long-term debt	(10,099)	(40,100)
Net cash used in financing activities	(28,175)	(14,819)
Net Increase (Decrease) in Cash and Cash Equivalents	1,512	(3,395)
Cash and Cash Equivalents—Beginning of Period	3,499	6,985
Cash and Cash Equivalents—End of Period	$ 5,011	$ 3,590

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Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands		Total		Common Stock [Member]		Additional Paid-In Capital [Member]		Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares Held In Trust For Deferred Compensation Plan		95,329
Common Stock, Dividends, Per Share, Declared		$ 0.845
Beginning Balances (shares) at Dec. 31, 2019	[1],[2]			16,403,776
Beginning Balances at Dec. 31, 2019		$ 561,577	[1],[2]	$ 7,984	[1],[2]	$ 259,253		$ 300,607	$ (6,267)	$ 4,543	$ (4,543)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		39,886						39,886
Other comprehensive income (loss)		1,805							1,805
Other Comprehensive Income (Loss), Net of Tax		1,805
Dividend declared		(14,009)						(14,009)
Retirement savings plan and dividend reinvestment plan (shares)				25,576
Dividend reinvestment plan		2,286		$ 13		2,273
Share-based compensation (shares)	[3],[4]			34,456
Share-based compensation and tax benefit		1,762		$ 16	[3],[4]	1,746	[3],[4]
Treasury stock activities		0								1,116	(1,116)
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, QuantificationPrincipleEffectOfAdoptionQuantification		(30)						(30)
Ending Balances (shares) at Jun. 30, 2020	[1],[2]			16,463,808
Ending Balances at Jun. 30, 2020		$ 593,277	[1]	$ 8,013	[1]	263,272		326,454	(4,462)	5,659	(5,659)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		10,319
Common Stock, Dividends, Per Share, Declared		$ 0.4400
Beginning Balances (shares) at Mar. 31, 2020	[1],[2]			16,433,105
Beginning Balances at Mar. 31, 2020		$ 584,129	[1]	$ 7,998	[1]	259,521		322,804	(6,194)	5,468	(5,468)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		10,956						10,956
Other comprehensive income (loss)		1,732							1,732
Other Comprehensive Income (Loss), Net of Tax		1,732
Dividend declared		(7,306)						(7,306)
Retirement savings plan and dividend reinvestment plan (shares)				21,833
Dividend reinvestment plan		1,932		$ 11		1,921
Share-based compensation (shares)	[3],[4]			8,870
Share-based compensation and tax benefit	[3],[4]	1,834		$ 4		1,830
Treasury stock activities										191	(191)
Ending Balances (shares) at Jun. 30, 2020	[1],[2]			16,463,808
Ending Balances at Jun. 30, 2020		$ 593,277	[1]	$ 8,013	[1]	263,272		326,454	(4,462)	5,659	(5,659)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares Held In Trust For Deferred Compensation Plan		107,141
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Shares Held In Trust For Deferred Compensation Plan		105,087
Common Stock, Dividends, Per Share, Declared		$ 0.92
Beginning Balances (shares) at Dec. 31, 2020	[1],[2]			17,461,841
Beginning Balances at Dec. 31, 2020		$ 697,085		$ 8,499	[1],[2]	348,482		342,969	(2,865)	5,679	(5,679)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		48,279						48,279
Other comprehensive income (loss)		3,423							3,423
Other Comprehensive Income (Loss), Net of Tax		3,423
Dividend declared		(16,312)						(16,312)
Retirement savings plan and dividend reinvestment plan (shares)				60,116
Dividend reinvestment plan		6,835		$ 29		6,806
Share-based compensation (shares)	[3],[4]			45,971
Share-based compensation and tax benefit	[3],[4]	2,254		$ 22		2,232
Treasury stock activities								0		1,524	(1,524)
Ending Balances (shares) at Jun. 30, 2021	[1],[2]			17,567,928
Ending Balances at Jun. 30, 2021		$ 741,564	[1]	$ 8,550	[1]	357,520		374,936	558	7,203	(7,203)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		14,020
Common Stock, Dividends, Per Share, Declared		$ 0.4800
Beginning Balances (shares) at Mar. 31, 2021	[1],[2]			17,521,493
Beginning Balances at Mar. 31, 2021		$ 726,388	[1]	$ 8,528	[1]	350,875		369,623	(2,638)	6,992	(6,992)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		13,813						13,813
Other comprehensive income (loss)		3,196							3,196
Other Comprehensive Income (Loss), Net of Tax		3,196
Dividend declared		(8,500)						(8,500)
Retirement savings plan and dividend reinvestment plan (shares)				39,605
Dividend reinvestment plan		4,621		$ 19		4,602
Share-based compensation (shares)	[3],[4]			6,830
Share-based compensation and tax benefit	[3],[4]	2,046		$ 3		2,043
Treasury stock activities		0								211	(211)
Ending Balances (shares) at Jun. 30, 2021	[1],[2]			17,567,928
Ending Balances at Jun. 30, 2021		$ 741,564	[1]	$ 8,550	[1]	$ 357,520		$ 374,936	$ 558	$ 7,203	$ (7,203)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Shares Held In Trust For Deferred Compensation Plan		117,193

[1] 2,000,000 shares of preferred stock at $0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity.

[2] Includes 117,193, 105,087, 107,141, and 95,329 shares at June 30, 2021, December 31, 2020, June 30, 2020 and December 31, 2019, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan.

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

[4] The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2021 and 2020, we withheld 14,020 and 10,319 shares, respectively, for employee taxes.

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Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.4800	$ 0.4400	$ 0.92	$ 0.845
Deferred compensation plan held Rabbi Trust (shares)	117,193	107,141	117,193	107,141	105,087	95,329
Preferred Stock, Shares Authorized	2,000,000		2,000,000		2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01		$ 0.01		$ 0.01
Shares issued under the performance incentive plan withheld for employee taxes (shares)			14,020	10,319

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Summary of Accounting Policies

6 Months Ended

Jun. 30, 2021

Accounting Policies [Abstract]

Summary of Accounting Policies

Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2020. In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

Effects of COVID-19

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of the new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19.

FASB Statements and Other Authoritative Pronouncements

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

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Calculation of Earnings Per Share

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	13,815	$	10,661	$	48,287	$	39,702
Income/(Loss) from Discontinued Operations	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886
Weighted average shares outstanding	17,546,346		16,448,490		17,516,273		16,431,724
Basic Earnings Per Share from Continuing Operations	$	0.79	$	0.65	$	2.76	$	2.42
Basic Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Basic Earnings Per Share	$	0.79	$	0.67	$	2.76	$	2.43
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic	17,546,346		16,448,490		17,516,273		16,431,724
Effect of dilutive securities—Share-based compensation	70,150		55,113		68,733		56,083
Adjusted denominator—Diluted	17,616,496		16,503,603		17,585,006		16,487,807
Diluted Earnings Per Share from Continuing Operations	$	0.78	$	0.64	$	2.75	$	2.41
Diluted Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Diluted Earnings Per Share	$	0.78	$	0.66	$	2.75	$	2.42

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Acquisitions and Divestitures (Notes)

6 Months Ended

Jun. 30, 2021

Discontinued Operations and Disposal Groups [Abstract]

Business Combination Disclosure [Text Block]

3.     Acquisitions

Escambia Meter Station Asset Purchase

In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light for $7.5 million and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline which provide gas supply to a natural gas fired power plant owned by Florida Power & Light in Pensacola, Florida.

Acquisition of Western Natural Gas

In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $6.7 million, net of cash acquired. Additionally, the purchase price included $0.3 million of working capital. We recorded contingent consideration of $0.3 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy segment beginning in the fourth quarter of 2020. There are multiple strategic benefits to this acquisition including it: (i) expanded our propane territory serviced in Florida and (ii) included an established customer base with additional opportunities for future growth.

In connection with this acquisition, we recorded $3.5 million in property plant and equipment, $1.4 million in intangible assets associated with customer relationships and non-compete agreements and $1.8 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021. For the three months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $0.6 million and $0.1 million, respectively. For the six months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $1.4 million and $0.3 million, respectively.

Acquisition of Elkton Gas

In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland for approximately, $15.6 million, net of cash acquired. Additionally, the purchase price included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland. In connection with this acquisition,     we recorded $15.9 million in property, plant and equipment, $0.6 million in accounts receivable, $2.6 million in other liabilities, $2.6 million in regulatory liabilities and $4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021. For the three months ended June 30, 2021, Elkton Gas generated operating revenue and income of $0.5 million and $0.3 million, respectively. For the six months ended June 30, 2021, Elkton Gas generated operating revenue and income of $3.1 million and $0.9 million, respectively.

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Revenue Recognition (Notes)

6 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenue RecognitionWe recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays our revenue from continuing operations by major source based on product and service type for the three months ended June 30, 2021 and 2020:

	Three months ended June 30, 2021								Three months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	10,068	$	—	$	—	$	10,068	$	11,758	$	—	$	—	$	11,758
Florida natural gas division	8,446		—		—		8,446		7,231		—		—		7,231
FPU electric distribution	18,898		—		—		18,898		15,701		—		—		15,701
FPU natural gas distribution	23,159		—		—		23,159		19,498		—		—		19,498
Maryland natural gas division	3,224		—		—		3,224		3,979		—		—		3,979
Sandpiper natural gas/propane operations	3,814		—		—		3,814		2,858		—		—		2,858
Elkton Gas	1,195		—		—		1,195		—		—		—		—
Total energy distribution	68,804		—		—		68,804		61,025		—		—		61,025
Energy transmission
Aspire Energy	—		5,578		—		5,578		—		4,554		—		4,554
Aspire Energy Express	47		—		—		47		—		—		—		—
Eastern Shore	18,617		—		—		18,617		18,277		—		—		18,277
Peninsula Pipeline	6,610		—		—		6,610		5,361		—		—		5,361
Total energy transmission	25,274		5,578		—		30,852		23,638		4,554		—		28,192
Energy generation
Eight Flags	—		4,173		—		4,173		—		3,694		—		3,694
Propane operations
Propane delivery operations	—		23,098		—		23,098		—		17,260		—		17,260
Energy delivery services
Marlin Gas Services	—		1,989		—		1,989		—		2,248		—		2,248
Other and eliminations
Eliminations	(13,168)		(65)		(4,734)		(17,967)		(11,145)		(16)		(4,340)		(15,501)
Other	—		—		133		133		—		—		133		133
Total other and eliminations	(13,168)		(65)		(4,601)		(17,834)		(11,145)		(16)		(4,207)		(15,368)
Total operating revenues (1)	$	80,910	$	34,773	$	(4,601)	$	111,082	$	73,518	$	27,740	$	(4,207)	$	97,051

(1) Total operating revenues for the three months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.1 million and $0.09 million for our Regulated and Unregulated Energy segments, respectively, and $0.1 million and $0.04 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

The following table displays our revenue from continuing operations by major source based on product and service type for the six months ended June 30, 2021 and 2020:

	Six months ended June 30, 2021								Six months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	43,340	$	—	$	—	$	43,340	$	38,325	$	—	$	—	$	38,325
Florida natural gas division	17,402		—		—		17,402		15,708		—		—		15,708
FPU electric distribution	37,449		—		—		37,449		29,920		—		—		29,920
FPU natural gas distribution	50,020		—		—		50,020		44,942		—		—		44,942
Maryland natural gas division	13,690		—		—		13,690		13,117		—		—		13,117
Sandpiper natural gas/propane operations	11,885		—		—		11,885		9,150		—		—		9,150
Elkton Gas	3,830		—		—		3,830		—		—		—		—
Total energy distribution	177,616		—		—		177,616		151,162		—		—		151,162
Energy transmission
Aspire Energy	—		18,484		—		18,484		—		14,335		—		14,335
Aspire Energy Express	93		—		—		93		—		—		—		—
Eastern Shore	38,589		—		—		38,589		37,556		—		—		37,556
Peninsula Pipeline	13,077		—		—		13,077		10,185		—		—		10,185
Total energy transmission	51,759		18,484		—		70,243		47,741		14,335		—		62,076
Energy generation
Eight Flags	—		8,502		—		8,502		—		8,017		—		8,017
Propane operations
Propane delivery operations	—		78,361		—		78,361		—		55,882		—		55,882
Energy delivery services
Marlin Gas Services	—		4,340		—		4,340		—		3,557		—		3,557
Other and eliminations
Eliminations	(27,268)		(156)		(9,635)		(37,059)		(22,430)		(39)		(8,749)		(31,218)
Other			—		265		265		—		—		265		265
Total other and eliminations	(27,268)		(156)		(9,370)		(36,794)		(22,430)		(39)		(8,484)		(30,953)
Total operating revenues (1)	$	202,107	$	109,531	$	(9,370)	$	302,268	$	176,473	$	81,752	$	(8,484)	$	249,741

(1) Total operating revenues for the six months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, and $0.8 million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2021 and December 31, 2020 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	18	$	4,816	$	644
Balance at 6/30/2021	37,341		18		5,179		342
Increase (decrease)	$	(18,259)	$	—	$	363	$	(302)

Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and primarily 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 condensed 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 three months ended June 30, 2021 and 2020, we recognized revenue of $0.2 million. For each of the six months ended June 30, 2021 and 2020, we recognized revenue of $0.6 million.

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 June 30, 2021, are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	18,561	$	31,914	$	24,570	$	22,402	$	21,550	$	20,494	$	176,316
Natural gas distribution operations	3,005		6,501		6,039		5,807		5,266		5,062		33,448
FPU electric distribution	489		652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	22,055	$	39,067	$	31,261	$	28,861	$	27,091	$	25,831	$	210,314

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Rates and Other Regulatory Activities

6 Months Ended

Jun. 30, 2021

Regulated Operations [Abstract]

Public Utilities Disclosure [Text Block]

Rates and Other Regulatory Activities

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

Delaware

There were no material regulatory activities in the second quarter of 2021.

Maryland

Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement plan with the Maryland PSC. The STRIDE plan proposes to

increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of fixed charge rider through a proposed five-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. In June 2021, we reached a settlement with the Maryland PSC Staff and the Maryland Office of the Peoples Counsel. The settlement agreement is currently being reviewed by a Maryland Public Utilities Law Judge, who must issue a final recommendation to the Commission. A final order is expected in August 2021.

Florida

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

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

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

Electric Depreciation Study: In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The petition was joined to the Hurricane Michael docket, and was approved at the Florida PSC Agenda in September 2020. The approved rates were retroactively applied effective January 1, 2020.

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

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

Escambia Meter Station: In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline, which provides gas supply to their natural gas fired power plant owned by Florida Power & Light in Pensacola,

Florida. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021.

Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline will construct approximately 11.33 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021.

Eastern Shore

Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021.

Capital Cost Surcharge: In June 2021, Eastern Shore filed with the FERC a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge is an approved item in the settlement of Eastern Shore’s last rate case. In conjunction with the filing of this surcharge, pursuant to the settlement agreement, a true-up of the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge will become effective July 15, 2021.

COVID-19 Impact

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place.

In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during these unprecedented times.

At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May followed by Delaware and Maryland in July, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities.

In April 2020, the Maryland PSC issued an order that authorized utilities to establish a regulatory asset to record prudently incurred incremental costs related to COVID-19, beginning on March 16, 2020. The Maryland PSC found that the creation of a regulatory asset for COVID-19 related expenses will facilitate the recovery of those costs prudently incurred to serve customers during this period, and that the deferral of such costs is appropriate because the

current catastrophic health emergency is outside the control of the utility and is a non-recurring event. The Maryland PSC is working on a plan that will provide funds to assist with the repayment of arrearages for customers in need and those impacted by COVID-19. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas will receive funds in the third quarter of 2021 to credit the accounts of those customers experiencing financial hardship in becoming current on their past due balances.

In May 2020, the Delaware PSC issued an order that authorized Delaware utilities to establish a regulatory asset to record COVID-19 related incremental costs incurred to ensure customers have essential utility services, for the period beginning on March 24, 2020 and ending 30 days after the state of emergency ends. The state of emergency was lifted July 12, 2021. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs.

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset will allow us to seek recovery of these costs in the next base rate proceedings. In November 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset treatment, contending that the order should be a reversed or modified and to request a hearing on the protest. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allows the units to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units will amortize the amount over two years and recover the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric division. This settlement agreement was approved by the Florida PSC on July 8, 2021.

In the fourth quarter of 2020, we began recording regulatory assets based on the net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric business units as authorized by the Delaware, Maryland and Florida PSCs. As of June 30, 2021 our total COVID-19 regulatory asset balance was $1.6 million.

    Summary TCJA Table

Customer rates for our regulated businesses were adjusted as approved by the regulators, prior to 2020 with the exception of Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarizes the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of June 30, 2021 and December 31, 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	June 30, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,660	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,905	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,684	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,108	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,149	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$303	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,569	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,124	$1,124	PSC approved amortization of ADIT in March 2018.

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Environmental Commitments and Contingencies

6 Months Ended

Jun. 30, 2021

Environmental Remediation Obligations [Abstract]

Environmental Commitments and Contingencies

Environmental Commitments and Contingencies

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances.

MGP Sites

We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida.

As of June 30, 2021 and December 31, 2020, we had approximately $5.6 million and $5.9 million, respectively, in environmental liabilities related to FPU’s four MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of June 30, 2021 and December 31, 2020, we had recovered approximately $12.6 million and $12.4 million, respectively, leaving approximately $1.4 million and $1.6 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

Remediation is ongoing for the MGPs in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The

Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial.

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

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

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Other Commitments and Contingencies

6 Months Ended

Jun. 30, 2021

Commitments and Contingencies Disclosure [Abstract]

Other Commitments and Contingencies

Other Commitments and Contingencies

Natural Gas and Electric

In March 2020, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2020 and expire in March 2023.

FPU natural gas distribution operations and Eight Flags have entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements are for a 10-year term that commenced in November 2020 and expire in October 2030.

Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency.

FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2021, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of June 30, 2021 was $20.0 million. The aggregate amount guaranteed at June 30, 2021 was approximately $8.0 million with the guarantees expiring on various dates through March 30, 2022.

As of June 30, 2021, we have issued letters of credit totaling approximately $4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn on these letters of credit as of June 30, 2021 and do not anticipate that the counterparties will draw upon these letters of credit. We expect that they will be renewed to the extent necessary in the future.

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Segment Information

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Segment Information

Segment Information

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

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

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

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions 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, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations.

The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	80,374	$	73,044	$	201,095	$	175,512
Unregulated Energy	30,708		24,007		101,173		74,229
Total operating revenues, unaffiliated customers	$	111,082	$	97,051	$	302,268	$	249,741
Intersegment Revenues (1)
Regulated Energy	$	536	$	474	$	1,012	$	961
Unregulated Energy	4,065		3,733		8,358		7,523
Other businesses	133		133		265		265
Total intersegment revenues	$	4,734	$	4,340	$	9,635	$	8,749
Operating Income
Regulated Energy	$	22,808	$	18,006	$	55,673	$	45,894
Unregulated Energy	(445)		281		18,660		14,142
Other businesses and eliminations	215		(310)		(158)		75
Operating income	22,578		17,977		74,175		60,111
Other income (expense), net	1,456		(279)		1,841		3,039
Interest charges	5,054		5,054		10,159		10,868
Income from Continuing Operations before Income Taxes	18,980		12,644		65,857		52,282
Income Taxes on Continuing Operations	5,165		1,983		17,570		12,580
Income from Continuing Operations	13,815		10,661		48,287		39,702
Income (Loss) from Discontinued Operations, Net of Tax	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886

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

(in thousands)	June 30, 2021		December 31, 2020
Identifiable Assets
Regulated Energy segment	$	1,568,136	$	1,547,619
Unregulated Energy segment	359,971		347,665
Other businesses and eliminations	44,233		37,203
Total identifiable assets	$	1,972,340	$	1,932,487

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2021

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Stockholders' Equity

Common Stock Issuances

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

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. In the third and fourth quarters of 2020, we issued 0.3 million shares at an average price per share of $86.12 and received net proceeds of $22.0 million under the DRIP. In the first six months of 2021, we issued less than 0.1 million shares at an average price per share of $113.51 and received net proceeds of $4.5 million under the DRIP.

We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Accumulated Other Comprehensive Gain (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive gain (loss) as of June 30, 2021 and 2020. All amounts in the following tables are presented net of tax.

	Defined Benefit		Commodity		Interest Rate
	Pension and		Contracts		Swap
	Postretirement		Cash Flow		Cash Flow
	Plan Items		Hedges		Hedges		Total
(in thousands)
As of December 31, 2020	$	(5,146)	$	2,309	$	(28)	$	(2,865)
Other comprehensive income before reclassifications	—		5,825		23		5,848
Amounts reclassified from accumulated other comprehensive income (loss)	128		(2,534)		(19)		(2,425)
Net current-period other comprehensive income	128		3,291		4		3,423
As of June 30, 2021	$	(5,018)	$	5,600	$	(24)	$	558

(in thousands)
As of December 31, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income/(loss) before reclassifications	—		2,770		(29)		$	2,741
Amounts reclassified from accumulated other comprehensive income/(loss)	132		(1,060)		(8)		(936)
Net prior-period other comprehensive income/(loss)	132		1,710		(37)		1,805
As of June 30, 2020	$	(4,801)	$	376	$	(37)	$	(4,462)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2021 and 2020. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19	$	19	$	38	$	38
Net loss(1)	(106)		(108)		(209)		(215)
Total before income taxes	(87)		(89)		(171)		(177)
Income tax benefit	23		23		43		45
Net of tax	$	(64)	$	(66)	$	(128)	$	(132)
Gains on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	455	$	238	$	3,502	$	1,465
Income tax expense	(126)		(66)		(968)		(405)
Net of tax	$	329	$	172	$	2,534	$	1,060
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	22	$	11	$	26	$	11
Income tax expense	(6)		(3)		(7)		(3)
Net of tax	$	16	$	8	$	19	$	8
Total reclassifications for the period	$	281	$	114	$	2,425	$	936

(1) These amounts are included in the computation of net periodic costs (benefits). See Note 10, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items are included in other expense, net gains and losses on propane swap agreements, natural gas swaps, and natural gas futures contracts are included in cost of sales, the realized gain or loss on interest rate swap agreements is recognized as a component of interest charges in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2021

Retirement Benefits [Abstract]

Employee Benefit Plans

Employee Benefit PlansNet periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2021 and 2020 are set forth in the following tables:

	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Three Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	34	$	46	$	429	$	518	$	12	$	16	$	6	$	8	$	6	$	10
Expected return on plan assets	(40)		(42)		(830)		(745)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(19)		(19)		—		—
Amortization of net (gain) loss	60		65		155		135		7		5		10		12		(2)		—
Net periodic cost (benefit)	54		69		(246)		(92)		19		21		(3)		1		4		10
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		2
Total periodic cost (benefit)	$	54	$	69	$	(246)	$	(92)	$	19	$	21	$	(3)	$	1	$	4	$	12

	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Six Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	68	$	92	$	858	$	1,036	$	24	$	32	$	12	$	16	$	12	$	20
Expected return on plan assets	(80)		(84)		(1,660)		(1,490)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(38)		(38)		—		—
Amortization of net (gain) loss	120		130		310		270		14		10		18		24		(4)		—
Net periodic cost (benefit)	108		138		(492)		(184)		38		42		(8)		2		8		20
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		4
Total periodic cost (benefit)	$	108	$	138	$	(492)	$	(184)	$	38	$	42	$	(8)	$	2	$	8	$	24

We expect to record $0.7 million in pension and post-retirement benefits for 2021. The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result of this strategy, we are planning to terminate the Chesapeake Pension Plan in the fourth quarter of 2021.

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2021 and 2020: 

For the Three Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	60		155		7		10		(2)		230
Total recognized in net periodic benefit cost	60		155		7		(9)		(2)		211
Recognized from accumulated other comprehensive loss/(gain) (1)	60		29		7		(9)		—		87
Recognized from regulatory asset	—		126		—		—		(2)		124
Total	$	60	$	155	$	7	$	(9)	$	(2)	$	211

For the Three Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	65		135		5		12		—		217
Total recognized in net periodic benefit cost	65		135		5		(7)		—		198
Recognized from accumulated other comprehensive loss/(gain) (1)	65		26		5		(7)		—		89
Recognized from regulatory asset	—		109		—		—		—		109
Total	$	65	$	135	$	5	$	(7)	$	—	$	198

For the Six Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	120		310		14		18		(4)		458
Total recognized in net periodic benefit cost	120		310		14		(20)		(4)		420
Recognized from accumulated other comprehensive loss/(gain) (1)	120		58		14		(20)		(1)		171
Recognized from regulatory asset	—		252		—		—		(3)		249
Total	$	120	$	310	$	14	$	(20)	$	(4)	$	420

For the Six Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	130		270		10		24		—		434
Total recognized in net periodic benefit cost	130		270		10		(14)		—		396
Recognized from accumulated other comprehensive loss/(gain) (1)	130		52		10		(14)		—		178
Recognized from regulatory asset	—		218		—		—		—		218
Total	$	130	$	270	$	10	$	(14)	$	—	$	396

    

(1) See Note 9, Stockholders' Equity.

During the three and six months ended June 30, 2021, we contributed approximately $0.1 million to the Chesapeake Pension Plan and approximately $0.5 million to the FPU Pension Plan. We expect to contribute approximately $0.3 million and $2.1 million, respectively, to the Chesapeake Pension Plan and FPU Pension Plans during 2021, which represents the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2021 were immaterial and $0.1 million, respectively. We expect to pay total cash benefits of approximately $0.2 million under the Chesapeake SERP in 2021. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2021 were immaterial and $0.2 million, respectively. We estimate that approximately $0.2 million will be paid for such benefits under the Chesapeake Postretirement Plan in 2021. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2021, were immaterial. We estimate that approximately $0.1 million will be paid for such benefits under the FPU Medical Plan in 2021.

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Investments

6 Months Ended

Jun. 30, 2021

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at June 30, 2021 and December 31, 2020, consisted of the following:

(in thousands)	June 30, 2021		December 31, 2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	11,723	$	10,755
Investments in equity securities	22		21
Total	$	11,745	$	10,776

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $0.6 million and $1.4 million, respectively, in other income, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $1.0 million and a net unrealized loss of approximately $0.1 million, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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Share-Based Compensation

6 Months Ended

Jun. 30, 2021

Share-based Payment Arrangement [Abstract]

Share-Based Compensation

Share-Based Compensation

Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2021 and 2020:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Awards to non-employee directors	$	192	$	181	$	380	$	357
Awards to key employees	1,247		1,085		2,935		1,965
Total compensation expense	1,439		1,266		3,315		2,322
Less: tax benefit	(384)		(331)		(885)		(607)
Share-based compensation amounts included in net income	$	1,055	$	935	$	2,430	$	1,715

    Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2021, after the most recent election of directors, each of our non-employee directors received an annual retainer of 683 shares of common stock under the SICP for service as a director through the 2022 Annual Meeting of Stockholders; accordingly, 6,830 shares, with a weighted average fair value of $117.11 per share, were issued and vested in 2021. At June 30, 2021, there was approximately $0.7 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May of 2022.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2021: 

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2020	186,878	$	87.06
Granted	66,612	$	102.73
Vested	(53,147)	$	76.31
Expired	(852)	$	74.85
Forfeited	(5,384)	$	93.39
Outstanding—June 30, 2021	194,107	$	94.61

In February 2021, we granted awards of 66,612 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted.

In March 2021, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in February 2021 for the performance period ended December 31, 2020, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 14,020 shares, based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $1.5 million.

At June 30, 2021, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $23.4 million. At June 30, 2021, there was approximately $6.1 million of unrecognized compensation cost related to these awards, which will be recognized as expense for the remainder of 2021 through 2023.

Stock Options

There were no stock options outstanding or issued during the six months ended June 30, 2021 and 2020.

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Derivative Instruments

6 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. We have also entered into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of June 30, 2021, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Volume of Derivative Activity

As of June 30, 2021, the volume of our commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
Sharp	Propane (gallons)	Purchases	23.3	Cash flows hedges	June 2024
Sharp	Propane (gallons)	Sales	5.0	Cash flows hedges	March 2022

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes that are expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in

June 2021 through June 2024) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $5.4 million from accumulated other comprehensive income to earnings during the next 12-month period ended June 30, 2022.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In the fourth quarter of 2020, we entered into interest rate swaps with notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

We designated and accounted for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges. We expect to reclassify less than $0.1 million from accumulated other comprehensive (loss) to earnings during the next 12-month period ended June 30, 2022.

Broker Margin

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

(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,808	$	1,505

Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020, are as follows: 

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	8,056		3,255
Total asset derivatives		$	8,056	$	3,269

	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	317		64
Interest rate swap agreements	Derivative liabilities, at fair value	34		40
Total liability derivatives		$	351	$	127

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2021		2020		2021		2020
Derivatives designated as fair value hedges
Propane put options	Cost of sales	$	—	$	—	$	(24)	$	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	455		238		3,502		1,465
Propane swap agreements	Other comprehensive income	4,319		2,354		4,548		2,363
Interest rate swap agreements	Interest expense	22		11		26		11
Interest rate swap agreements	Other comprehensive income (loss)	8		(51)		5		(51)
Total		$	4,804	$	2,552	$	8,057	$	3,788

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

Fair Value of Financial Instruments

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

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

Financial Assets and Liabilities Measured at Fair Value

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2021 and December 31, 2020:

			Fair Value Measurements Using:
As of June 30, 2021	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	2,191		—		—		2,191
Investments—mutual funds and other	9,532		9,532		—		—
Total investments	11,745		9,554		—		2,191
Derivative assets	8,056		—		8,056		—
Total assets	$	19,801	$	9,554	$	8,056	$	2,191
Liabilities:
Derivative liabilities	$	351	$	—	$	351	$	—

			Fair Value Measurements Using:
As of December 31, 2020	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2021 and 2020:

	Six months ended June 30,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	70		226
Transfers	—		1,345
Distribution	(51)		(50)
Investment income	16		10
Ending Balance	$	2,191	$	2,334

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

At June 30, 2021, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At June 30, 2021, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $512.9 million, compared to the estimated fair value of $541.5 million. At December 31, 2020, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $523.0 million, compared to a fair value of approximately $548.5 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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Long-Term Debt

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below: 

	June 30,		December 31,
(in thousands)	2021		2020
Uncollateralized senior notes:
5.93% note, due October 31, 2023	$	7,500	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	16,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
Less: debt issuance costs	(850)		(901)
Total long-term debt	512,050		522,099
Less: current maturities	(13,600)		(13,600)
Total long-term debt, net of current maturities	$	498,450	$	508,499

    

.

    Shelf Agreements

We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at June 30, 2021:

(in thousands)	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (1)	150,000		—		—		150,000
NYL Shelf Agreement (1)	150,000		(140,000)		—		10,000
Total Shelf Agreements as of June 30, 2021	$	670,000	$	(360,000)	$	—	$	310,000

     (1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively.

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.

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Short-Term Borrowings (Notes)

6 Months Ended

Jun. 30, 2021

Short-Term Borrowing [Abstract]

Short-term Debt [Text Block]

16.    Short-Term Borrowings

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At June 30, 2021 and December 31, 2020, we had $169.3 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent. Included in the June 30, 2021 balance, is $100.0 million in short-term debt for which we have entered into interest rate swap agreements. In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million

through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

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

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of June 30, 2021, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon total indebtedness to total capitalization ratio. As of June 30, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the Revolver at June 30, 2021 was $200.9 million. As of June 30, 2021, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver.

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Leases Leases

6 Months Ended

Jun. 30, 2021

Lease Disclosure [Abstract]

Lessee, Operating Leases [Text Block]

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 our employees in several locations throughout the Mid-Atlantic, Mid-West and in Florida. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at June 30, 2021, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of June 30, 2021, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income:

		Three Months Ended				Six Months Ended
		June 30,				June 30,
( in thousands)	Classification	2021		2020		2021		2020
Operating lease cost (1)	Operations expense	$	515	$	629	$	1,038	$	1,255

(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 condensed consolidated balance sheet at June 30, 2021 and December 31, 2020:

(in thousands)	Balance sheet classification	June 30, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,020	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,732	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,719		9,872
Total lease liabilities		$	10,451	$	11,619

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2021 and December 31, 2020:

	June 30, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.65		8.70
Weighted-average discount rate
Operating leases	3.8	%	3.8	%

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2021 and 2020:

	Six Months Ended
	June 30,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	936	$	1,034

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating  Leases (1)
Remainder of 2021	$	1,060
2022	1,845
2023	1,762
2024	1,607
2025	1,387
2026	951
Thereafter	3,596
Total lease payments	$	12,208
Less: Interest	1,757
Present value of lease liabilities	$	10,451

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

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Summary of Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2021

Accounting Policies [Abstract]

COVID-19 Effect [Policy Text Block]

Effects of COVID-19

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of the new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19.

Basis of Presentation

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2020. In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

FASB Statements and Other Authoritative Pronouncements

FASB Statements and Other Authoritative Pronouncements

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

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Calculation of Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2021

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	13,815	$	10,661	$	48,287	$	39,702
Income/(Loss) from Discontinued Operations	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886
Weighted average shares outstanding	17,546,346		16,448,490		17,516,273		16,431,724
Basic Earnings Per Share from Continuing Operations	$	0.79	$	0.65	$	2.76	$	2.42
Basic Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Basic Earnings Per Share	$	0.79	$	0.67	$	2.76	$	2.43
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic	17,546,346		16,448,490		17,516,273		16,431,724
Effect of dilutive securities—Share-based compensation	70,150		55,113		68,733		56,083
Adjusted denominator—Diluted	17,616,496		16,503,603		17,585,006		16,487,807
Diluted Earnings Per Share from Continuing Operations	$	0.78	$	0.64	$	2.75	$	2.41
Diluted Earnings Per Share from Discontinued Operations	—		0.02		—		0.01
Diluted Earnings Per Share	$	0.78	$	0.66	$	2.75	$	2.42

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Revenue Recognition (Tables)

6 Months Ended

Jun. 30, 2021

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table displays our revenue from continuing operations by major source based on product and service type for the three months ended June 30, 2021 and 2020:

	Three months ended June 30, 2021								Three months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	10,068	$	—	$	—	$	10,068	$	11,758	$	—	$	—	$	11,758
Florida natural gas division	8,446		—		—		8,446		7,231		—		—		7,231
FPU electric distribution	18,898		—		—		18,898		15,701		—		—		15,701
FPU natural gas distribution	23,159		—		—		23,159		19,498		—		—		19,498
Maryland natural gas division	3,224		—		—		3,224		3,979		—		—		3,979
Sandpiper natural gas/propane operations	3,814		—		—		3,814		2,858		—		—		2,858
Elkton Gas	1,195		—		—		1,195		—		—		—		—
Total energy distribution	68,804		—		—		68,804		61,025		—		—		61,025
Energy transmission
Aspire Energy	—		5,578		—		5,578		—		4,554		—		4,554
Aspire Energy Express	47		—		—		47		—		—		—		—
Eastern Shore	18,617		—		—		18,617		18,277		—		—		18,277
Peninsula Pipeline	6,610		—		—		6,610		5,361		—		—		5,361
Total energy transmission	25,274		5,578		—		30,852		23,638		4,554		—		28,192
Energy generation
Eight Flags	—		4,173		—		4,173		—		3,694		—		3,694
Propane operations
Propane delivery operations	—		23,098		—		23,098		—		17,260		—		17,260
Energy delivery services
Marlin Gas Services	—		1,989		—		1,989		—		2,248		—		2,248
Other and eliminations
Eliminations	(13,168)		(65)		(4,734)		(17,967)		(11,145)		(16)		(4,340)		(15,501)
Other	—		—		133		133		—		—		133		133
Total other and eliminations	(13,168)		(65)		(4,601)		(17,834)		(11,145)		(16)		(4,207)		(15,368)
Total operating revenues (1)	$	80,910	$	34,773	$	(4,601)	$	111,082	$	73,518	$	27,740	$	(4,207)	$	97,051

(1) Total operating revenues for the three months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.1 million and $0.09 million for our Regulated and Unregulated Energy segments, respectively, and $0.1 million and $0.04 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

The following table displays our revenue from continuing operations by major source based on product and service type for the six months ended June 30, 2021 and 2020:

	Six months ended June 30, 2021								Six months ended June 30, 2020
(in thousands)	Regulated Energy		Unregulated Energy		Other and Eliminations		Total		Regulated Energy		Unregulated Energy		Other and Eliminations		Total
Energy distribution
Delaware natural gas division	$	43,340	$	—	$	—	$	43,340	$	38,325	$	—	$	—	$	38,325
Florida natural gas division	17,402		—		—		17,402		15,708		—		—		15,708
FPU electric distribution	37,449		—		—		37,449		29,920		—		—		29,920
FPU natural gas distribution	50,020		—		—		50,020		44,942		—		—		44,942
Maryland natural gas division	13,690		—		—		13,690		13,117		—		—		13,117
Sandpiper natural gas/propane operations	11,885		—		—		11,885		9,150		—		—		9,150
Elkton Gas	3,830		—		—		3,830		—		—		—		—
Total energy distribution	177,616		—		—		177,616		151,162		—		—		151,162
Energy transmission
Aspire Energy	—		18,484		—		18,484		—		14,335		—		14,335
Aspire Energy Express	93		—		—		93		—		—		—		—
Eastern Shore	38,589		—		—		38,589		37,556		—		—		37,556
Peninsula Pipeline	13,077		—		—		13,077		10,185		—		—		10,185
Total energy transmission	51,759		18,484		—		70,243		47,741		14,335		—		62,076
Energy generation
Eight Flags	—		8,502		—		8,502		—		8,017		—		8,017
Propane operations
Propane delivery operations	—		78,361		—		78,361		—		55,882		—		55,882
Energy delivery services
Marlin Gas Services	—		4,340		—		4,340		—		3,557		—		3,557
Other and eliminations
Eliminations	(27,268)		(156)		(9,635)		(37,059)		(22,430)		(39)		(8,749)		(31,218)
Other			—		265		265		—		—		265		265
Total other and eliminations	(27,268)		(156)		(9,370)		(36,794)		(22,430)		(39)		(8,484)		(30,953)
Total operating revenues (1)	$	202,107	$	109,531	$	(9,370)	$	302,268	$	176,473	$	81,752	$	(8,484)	$	249,741

(1) Total operating revenues for the six months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, and $0.8 million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

Contract with Customer, Asset and Liability [Table Text Block]

The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2021 and December 31, 2020 were as follows:

	Trade Receivables		Contract Assets (Current)		Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020	$	55,600	$	18	$	4,816	$	644
Balance at 6/30/2021	37,341		18		5,179		342
Increase (decrease)	$	(18,259)	$	—	$	363	$	(302)

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

Revenue for these businesses for the remaining performance obligations, at June 30, 2021, are expected to be recognized as follows:

(in thousands)	2021		2022		2023		2024		2025		2026		2027 and thereafter
Eastern Shore and Peninsula Pipeline	$	18,561	$	31,914	$	24,570	$	22,402	$	21,550	$	20,494	$	176,316
Natural gas distribution operations	3,005		6,501		6,039		5,807		5,266		5,062		33,448
FPU electric distribution	489		652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	22,055	$	39,067	$	31,261	$	28,861	$	27,091	$	25,831	$	210,314

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

6 Months Ended

Jun. 30, 2021

Rates and Regulatory Activities [Abstract]

Summary of Effects of Federal Tax Reform on Regulated Businesses [Table Text Block]

The following table summarizes the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of June 30, 2021 and December 31, 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	June 30, 2021	December 31, 2020	Status
Eastern Shore (FERC)	$34,190	$34,190	Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)	$12,660	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,905	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,684	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,108	$8,184	PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC)	$19,149	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$303	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$6,569	$6,694	In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)	$1,124	$1,124	PSC approved amortization of ADIT in March 2018.

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Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables)

6 Months Ended

Jun. 30, 2021

Environmental Commitments and Contingencies [Abstract]

Environmental Remedies [Table Text Block]

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

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2021

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	80,374	$	73,044	$	201,095	$	175,512
Unregulated Energy	30,708		24,007		101,173		74,229
Total operating revenues, unaffiliated customers	$	111,082	$	97,051	$	302,268	$	249,741
Intersegment Revenues (1)
Regulated Energy	$	536	$	474	$	1,012	$	961
Unregulated Energy	4,065		3,733		8,358		7,523
Other businesses	133		133		265		265
Total intersegment revenues	$	4,734	$	4,340	$	9,635	$	8,749
Operating Income
Regulated Energy	$	22,808	$	18,006	$	55,673	$	45,894
Unregulated Energy	(445)		281		18,660		14,142
Other businesses and eliminations	215		(310)		(158)		75
Operating income	22,578		17,977		74,175		60,111
Other income (expense), net	1,456		(279)		1,841		3,039
Interest charges	5,054		5,054		10,159		10,868
Income from Continuing Operations before Income Taxes	18,980		12,644		65,857		52,282
Income Taxes on Continuing Operations	5,165		1,983		17,570		12,580
Income from Continuing Operations	13,815		10,661		48,287		39,702
Income (Loss) from Discontinued Operations, Net of Tax	(2)		295		(8)		184
Net Income	$	13,813	$	10,956	$	48,279	$	39,886

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

(in thousands)	June 30, 2021		December 31, 2020
Identifiable Assets
Regulated Energy segment	$	1,568,136	$	1,547,619
Unregulated Energy segment	359,971		347,665
Other businesses and eliminations	44,233		37,203
Total identifiable assets	$	1,972,340	$	1,932,487

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2021

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss

	Defined Benefit		Commodity		Interest Rate
	Pension and		Contracts		Swap
	Postretirement		Cash Flow		Cash Flow
	Plan Items		Hedges		Hedges		Total
(in thousands)
As of December 31, 2020	$	(5,146)	$	2,309	$	(28)	$	(2,865)
Other comprehensive income before reclassifications	—		5,825		23		5,848
Amounts reclassified from accumulated other comprehensive income (loss)	128		(2,534)		(19)		(2,425)
Net current-period other comprehensive income	128		3,291		4		3,423
As of June 30, 2021	$	(5,018)	$	5,600	$	(24)	$	558

(in thousands)
As of December 31, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income/(loss) before reclassifications	—		2,770		(29)		$	2,741
Amounts reclassified from accumulated other comprehensive income/(loss)	132		(1,060)		(8)		(936)
Net prior-period other comprehensive income/(loss)	132		1,710		(37)		1,805
As of June 30, 2020	$	(4,801)	$	376	$	(37)	$	(4,462)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2021 and 2020. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19	$	19	$	38	$	38
Net loss(1)	(106)		(108)		(209)		(215)
Total before income taxes	(87)		(89)		(171)		(177)
Income tax benefit	23		23		43		45
Net of tax	$	(64)	$	(66)	$	(128)	$	(132)
Gains on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	455	$	238	$	3,502	$	1,465
Income tax expense	(126)		(66)		(968)		(405)
Net of tax	$	329	$	172	$	2,534	$	1,060
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	22	$	11	$	26	$	11
Income tax expense	(6)		(3)		(7)		(3)
Net of tax	$	16	$	8	$	19	$	8
Total reclassifications for the period	$	281	$	114	$	2,425	$	936

(1) These amounts are included in the computation of net periodic costs (benefits). See Note 10, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments, for additional details.

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Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2021

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2021 and 2020 are set forth in the following tables:

	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Three Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	34	$	46	$	429	$	518	$	12	$	16	$	6	$	8	$	6	$	10
Expected return on plan assets	(40)		(42)		(830)		(745)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(19)		(19)		—		—
Amortization of net (gain) loss	60		65		155		135		7		5		10		12		(2)		—
Net periodic cost (benefit)	54		69		(246)		(92)		19		21		(3)		1		4		10
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		2
Total periodic cost (benefit)	$	54	$	69	$	(246)	$	(92)	$	19	$	21	$	(3)	$	1	$	4	$	12

	Chesapeake Pension Plan				FPU Pension Plan				Chesapeake SERP				Chesapeake Postretirement Plan				FPU Medical Plan
For the Six Months Ended June 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	68	$	92	$	858	$	1,036	$	24	$	32	$	12	$	16	$	12	$	20
Expected return on plan assets	(80)		(84)		(1,660)		(1,490)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(38)		(38)		—		—
Amortization of net (gain) loss	120		130		310		270		14		10		18		24		(4)		—
Net periodic cost (benefit)	108		138		(492)		(184)		38		42		(8)		2		8		20
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		4
Total periodic cost (benefit)	$	108	$	138	$	(492)	$	(184)	$	38	$	42	$	(8)	$	2	$	8	$	24

Amounts Included in Regulatory asset and AOCI [Table Text Block]

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2021 and 2020: 

For the Three Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	60		155		7		10		(2)		230
Total recognized in net periodic benefit cost	60		155		7		(9)		(2)		211
Recognized from accumulated other comprehensive loss/(gain) (1)	60		29		7		(9)		—		87
Recognized from regulatory asset	—		126		—		—		(2)		124
Total	$	60	$	155	$	7	$	(9)	$	(2)	$	211

For the Three Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19)	$	—	$	(19)
Net loss	65		135		5		12		—		217
Total recognized in net periodic benefit cost	65		135		5		(7)		—		198
Recognized from accumulated other comprehensive loss/(gain) (1)	65		26		5		(7)		—		89
Recognized from regulatory asset	—		109		—		—		—		109
Total	$	65	$	135	$	5	$	(7)	$	—	$	198

For the Six Months Ended June 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	120		310		14		18		(4)		458
Total recognized in net periodic benefit cost	120		310		14		(20)		(4)		420
Recognized from accumulated other comprehensive loss/(gain) (1)	120		58		14		(20)		(1)		171
Recognized from regulatory asset	—		252		—		—		(3)		249
Total	$	120	$	310	$	14	$	(20)	$	(4)	$	420

For the Six Months Ended June 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(38)	$	—	$	(38)
Net loss	130		270		10		24		—		434
Total recognized in net periodic benefit cost	130		270		10		(14)		—		396
Recognized from accumulated other comprehensive loss/(gain) (1)	130		52		10		(14)		—		178
Recognized from regulatory asset	—		218		—		—		—		218
Total	$	130	$	270	$	10	$	(14)	$	—	$	396

    

(1) See Note 9, Stockholders' Equity

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Investments (Tables)

6 Months Ended

Jun. 30, 2021

Investments, Debt and Equity Securities [Abstract]

Investments schedule [Table Text Block]

The investment balances at June 30, 2021 and December 31, 2020, consisted of the following:

(in thousands)	June 30, 2021		December 31, 2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	11,723	$	10,755
Investments in equity securities	22		21
Total	$	11,745	$	10,776

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2021

Shares awarded to non-employee directors [Line Items]

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2021 and 2020:

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2021		2020		2021		2020
(in thousands)
Awards to non-employee directors	$	192	$	181	$	380	$	357
Awards to key employees	1,247		1,085		2,935		1,965
Total compensation expense	1,439		1,266		3,315		2,322
Less: tax benefit	(384)		(331)		(885)		(607)
Share-based compensation amounts included in net income	$	1,055	$	935	$	2,430	$	1,715

Award to key employees [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2021: 

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2020	186,878	$	87.06
Granted	66,612	$	102.73
Vested	(53,147)	$	76.31
Expired	(852)	$	74.85
Forfeited	(5,384)	$	93.39
Outstanding—June 30, 2021	194,107	$	94.61

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments [Table Text Block]

As of June 30, 2021, the volume of our commodity derivative contracts were as follows:

Business unit	Commodity	Contract Type	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
Sharp	Propane (gallons)	Purchases	23.3	Cash flows hedges	June 2024
Sharp	Propane (gallons)	Sales	5.0	Cash flows hedges	March 2022

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

(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Sharp	Other Current Liabilities	$	4,808	$	1,505

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

June 30, 2021 and December 31, 2020, are as follows: 

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	$	—	$	14
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative assets, at fair value	8,056		3,255
Total asset derivatives		$	8,056	$	3,269

	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2021		December 31, 2020
Derivatives designated as fair value hedges
Propane put options	Derivative liabilities, at fair value	$	—	$	23
Derivatives designated as cash flow hedges
Propane swap agreements	Derivative liabilities, at fair value	317		64
Interest rate swap agreements	Derivative liabilities, at fair value	34		40
Total liability derivatives		$	351	$	127

Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,				For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2021		2020		2021		2020
Derivatives designated as fair value hedges
Propane put options	Cost of sales	$	—	$	—	$	(24)	$	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	455		238		3,502		1,465
Propane swap agreements	Other comprehensive income	4,319		2,354		4,548		2,363
Interest rate swap agreements	Interest expense	22		11		26		11
Interest rate swap agreements	Other comprehensive income (loss)	8		(51)		5		(51)
Total		$	4,804	$	2,552	$	8,057	$	3,788

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Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2021

Fair Value Disclosures [Abstract]

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis

The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2021 and December 31, 2020:

			Fair Value Measurements Using:
As of June 30, 2021	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	2,191		—		—		2,191
Investments—mutual funds and other	9,532		9,532		—		—
Total investments	11,745		9,554		—		2,191
Derivative assets	8,056		—		8,056		—
Total assets	$	19,801	$	9,554	$	8,056	$	2,191
Liabilities:
Derivative liabilities	$	351	$	—	$	351	$	—

			Fair Value Measurements Using:
As of December 31, 2020	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	2,156		—		—		2,156
Investments—mutual funds and other	8,599		8,599		—		—
Total investments	10,776		8,620		—		2,156
Derivative assets	3,269		—		3,269		—
Total assets	$	14,045	$	8,620	$	3,269	$	2,156
Liabilities:
Derivative liabilities	$	127	$	—	$	127	$	—

Summary of Changes in Fair Value of Investments

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2021 and 2020:

	Six months ended June 30,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	70		226
Transfers	—		1,345
Distribution	(51)		(50)
Investment income	16		10
Ending Balance	$	2,191	$	2,334

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2021

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below: 

	June 30,		December 31,
(in thousands)	2021		2020
Uncollateralized senior notes:
5.93% note, due October 31, 2023	$	7,500	$	9,000
5.68% note, due June 30, 2026	14,500		17,400
6.43% note, due May 2, 2028	4,900		5,600
3.73% note, due December 16, 2028	16,000		16,000
3.88% note, due May 15, 2029	40,000		45,000
3.25% note, due April 30, 2032	70,000		70,000
3.48% note, due May 31, 2038	50,000		50,000
3.58% note, due November 30, 2038	50,000		50,000
3.98% note, due August 20, 2039	100,000		100,000
2.98% note, due December 20, 2034	70,000		70,000
3.00% note, due July 15, 2035	50,000		50,000
2.96% note, due August 15, 2035	40,000		40,000
Less: debt issuance costs	(850)		(901)
Total long-term debt	512,050		522,099
Less: current maturities	(13,600)		(13,600)
Total long-term debt, net of current maturities	$	498,450	$	508,499

    

.

Schedule of Line of Credit Facilities [Line Items]

Schedule of Line of Credit Facilities [Table Text Block]

(in thousands)	Total Borrowing Capacity		Less: Amount of Debt Issued		Less: Unfunded Commitments		Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)	$	370,000	$	(220,000)	$	—	$	150,000
MetLife Shelf Agreement (1)	150,000		—		—		150,000
NYL Shelf Agreement (1)	150,000		(140,000)		—		10,000
Total Shelf Agreements as of June 30, 2021	$	670,000	$	(360,000)	$	—	$	310,000

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Leases Leases (Tables)

6 Months Ended

Jun. 30, 2021

Lease Disclosure [Abstract]

Lease, Cost [Table Text Block]

		Three Months Ended				Six Months Ended
		June 30,				June 30,
( in thousands)	Classification	2021		2020		2021		2020
Operating lease cost (1)	Operations expense	$	515	$	629	$	1,038	$	1,255

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

Schedule of Leases Reported on Consolidated Statement of Financial Position [Table Text Block]

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheet at June 30, 2021 and December 31, 2020:

(in thousands)	Balance sheet classification	June 30, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	10,020	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,732	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,719		9,872
Total lease liabilities		$	10,451	$	11,619

Leases, Weighted Average Remaining Lease Term [Table Text Block]

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2021 and December 31, 2020:

	June 30, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.65		8.70
Weighted-average discount rate
Operating leases	3.8	%	3.8	%

Lease, Cash Flow [Table Text Block]

The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2021 and 2020:

	Six Months Ended
	June 30,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	936	$	1,034

Schedule of Maturities of Leases [Table Text Block]

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2021 and for each of the next five years and thereafter:

(in thousands)	Operating  Leases (1)
Remainder of 2021	$	1,060
2022	1,845
2023	1,762
2024	1,607
2025	1,387
2026	951
Thereafter	3,596
Total lease payments	$	12,208
Less: Interest	1,757
Present value of lease liabilities	$	10,451

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

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Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Per Basic Share	$ 0.79	$ 0.65	$ 2.76	$ 2.42
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	$ 0	$ 0.02	$ 0	$ 0.01
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	$ 13,815	$ 10,661	$ 48,287	$ 39,702
Calculation of Basic Earnings Per Share:
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886
Weighted shares outstanding (shares)	17,546,346	16,448,490	17,516,273	16,431,724
Basic Earnings Per Share (in dollars per share)	$ 0.79	$ 0.67	$ 2.76	$ 2.43
Reconciliation of Numerator:
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	17,546,346	16,448,490	17,516,273	16,431,724
Effect of dilutive securities:
Share-based compensation (shares)	70,150	55,113	68,733	56,083
Adjusted denominator-Diluted (shares)	17,616,496	16,503,603	17,585,006	16,487,807
Income (Loss) from Continuing Operations, Per Diluted Share	$ 0.78	$ 0.64	$ 2.75	$ 2.41
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0	0.02	0	0.01
Diluted Earnings Per Share (in dollars per share)	$ 0.78	$ 0.66	$ 2.75	$ 2.42
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	$ (2)	$ 295	$ (8)	$ 184
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	13,815	10,661	48,287	39,702
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax	(2)	295	(8)	184
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886
Basic (shares)	17,546,346	16,448,490	17,516,273	16,431,724
Income (Loss) from Continuing Operations, Per Basic Share	$ 0.79	$ 0.65	$ 2.76	$ 2.42
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Basic Share	0	0.02	0	0.01
Basic (in dollars per share)	$ 0.79	$ 0.67	$ 2.76	$ 2.43
Share-based compensation (shares)	70,150	55,113	68,733	56,083
Diluted (shares)	17,616,496	16,503,603	17,585,006	16,487,807
Income (Loss) from Continuing Operations, Per Diluted Share	$ 0.78	$ 0.64	$ 2.75	$ 2.41
Discontinued Operation, Income (Loss) from Discontinued Operation, Net of Tax, Per Diluted Share	0	0.02	0	0.01
Diluted (in dollars per share)	$ 0.78	$ 0.66	$ 2.75	$ 2.42
Retained Earnings [Member]
Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	$ 13,815	$ 10,661	$ 48,287	$ 39,702
Calculation of Basic Earnings Per Share:
Net Income	13,813	10,956	48,279	39,886
Reconciliation of Numerator:
Net Income	13,813	10,956	48,279	39,886
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent	13,815	10,661	48,287	39,702
Net Income	$ 13,813	$ 10,956	$ 48,279	$ 39,886

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Acquisitions and Divestitures (Details) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($) Dekatherm	Jun. 30, 2020 USD ($)
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	$ 111,082	$ 97,051	$ 302,268	$ 249,741
Operating Income (Loss)	22,578	17,977	74,175	60,111
Unregulated Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Income (Loss)	(445)	281	18,660	14,142
Regulated Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Operating Income (Loss)	22,808	$ 18,006	55,673	$ 45,894
Elkton Gas [Member] | Regulated Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	15,900		15,900
Revenues	500		3,100
Operating Income (Loss)	300		$ 900
Number of customers acquired through acquisition			7,000
Business Combination, Consideration Transferred			$ 15,600
Business Combination, Working Capital	600		600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	600		600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	2,600		2,600
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	4,300		4,300
Business Combination Recognized Identifiable Assets Acquired And Liabilities Assumed Regulatory Liabilities			2,600
Western Natural Gas [Member] | Unregulated Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment	3,500		3,500
Revenues	600		1,400
Operating Income (Loss)	100		300
Business Combination, Consideration Transferred			6,700
Business Combination, Working Capital	300		300
Business Combination, Contingent Consideration, Liability	300		300
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	1,800		1,800
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets	$ 1,400		1,400
Escambia Meter | Regulated Energy [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Business Combination, Consideration Transferred			$ 7,500
Additional Firm Natural Gas Transportation Deliverability | Dekatherm			530,000

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Revenue Recognition Disegragation of Revenue (Details) - USD ($)	3 Months Ended				6 Months Ended
	Jun. 30, 2021		Jun. 30, 2020		Jun. 30, 2021		Jun. 30, 2020
Disaggregation of Revenue [Line Items]
Revenues	$ 111,082,000		$ 97,051,000		$ 302,268,000		$ 249,741,000
Revenue from Contract with Customer, Excluding Assessed Tax	111,082,000	[1]	97,051,000	[1]	302,268,000	[2]	249,741,000	[2]
Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	80,910,000	[1]	73,518,000	[1]	202,107,000	[2]	176,473,000	[2]
Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34,773,000	[1]	27,740,000	[1]	109,531,000	[2]	81,752,000	[2]
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(4,601,000)		(4,207,000)		(9,370,000)		(8,484,000)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(4,601,000)	[1]	(4,207,000)	[1]	(9,370,000)	[2]	(8,484,000)	[2]
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(17,834,000)		(15,368,000)		(36,794,000)		(30,953,000)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(13,168,000)		(11,145,000)		(27,268,000)		(22,430,000)
Other [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenues	100,000		100,000		(200,000)		800,000
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenues	90,000.00		40,000.00		200,000		100,000
Revenue from Contract with Customer, Excluding Assessed Tax	(65,000)		(16,000)		(156,000)		(39,000)
Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	68,804,000		61,025,000		177,616,000		151,162,000
Energy Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	68,804,000		61,025,000		177,616,000		151,162,000
Energy Distribution [Member] | Delaware natural gas division [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	10,068,000		11,758,000		43,340,000		38,325,000
Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	10,068,000		11,758,000		43,340,000		38,325,000
Energy Distribution [Member] | Central Florida Gas Division [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	8,446,000		7,231,000		17,402,000		15,708,000
Energy Distribution [Member] | Central Florida Gas Division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	8,446,000		7,231,000		17,402,000		15,708,000
Energy Distribution [Member] | FPU Electric Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,898,000		15,701,000		37,449,000		29,920,000
Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,898,000		15,701,000		37,449,000		29,920,000
Energy Distribution [Member] | Florida Public Utilities Company [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	23,159,000		19,498,000		50,020,000		44,942,000
Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	23,159,000		19,498,000		50,020,000		44,942,000
Energy Distribution [Member] | Maryland Natural Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3,224,000		3,979,000		13,690,000		13,117,000
Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3,224,000		3,979,000		13,690,000		13,117,000
Energy Distribution [Member] | Sandpiper [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3,814,000		2,858,000		11,885,000		9,150,000
Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	3,814,000		2,858,000		11,885,000		9,150,000
Energy Distribution [Member] | Elkton Gas [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,195,000				3,830,000
Energy Distribution [Member] | Elkton Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,195,000				3,830,000
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	30,852,000		28,192,000		70,243,000		62,076,000
Energy Transmission [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	25,274,000		23,638,000		51,759,000		47,741,000
Energy Transmission [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,578,000		4,554,000		18,484,000		14,335,000
Energy Transmission [Member] | Aspire [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,578,000		4,554,000		18,484,000		14,335,000
Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,578,000		4,554,000		18,484,000		14,335,000
Energy Transmission [Member] | Eastern Shore Gas Company [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,617,000		18,277,000		38,589,000		37,556,000
Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,617,000		18,277,000		38,589,000		37,556,000
Energy Transmission [Member] | Peninsula Pipeline [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6,610,000		5,361,000		13,077,000		10,185,000
Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6,610,000		5,361,000		13,077,000		10,185,000
Energy Transmission [Member] | Aspire Energy Express | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	47,000				93,000
Energy Generation [Member] | Eight Flags [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4,173,000		3,694,000		8,502,000		8,017,000
Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4,173,000		3,694,000		8,502,000		8,017,000
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	23,098,000		17,260,000		78,361,000		55,882,000
Propane Delivery [Member] | Florida Propane | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	23,098,000		17,260,000		78,361,000		55,882,000
Energy Services [Member] | Marlin Gas Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,989,000				4,340,000
Energy Services [Member] | Marlin Gas Services [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,989,000		2,248,000		4,340,000		3,557,000
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(17,967,000)		(15,501,000)		(37,059,000)		(31,218,000)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(13,168,000)		(11,145,000)		(27,268,000)		(22,430,000)
Eliminations [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(65,000)		(16,000)		(156,000)		(39,000)
Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(4,734,000)		(4,340,000)		(9,635,000)		(8,749,000)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	133,000		133,000		265,000		265,000
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0				0		0
Other [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 133,000		$ 133,000		$ 265,000		$ 265,000

[1] (1) Total operating revenues for the three months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.1 million and $0.09 million for our Regulated and Unregulated Energy segments, respectively, and $0.1 million and $0.04 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

[2] (1) Total operating revenues for the six months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, and $0.8 million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.

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Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 37,341	$ 37,341	$ 55,600
Contract with Customer, Asset, Net, Current	18	18	18
Contract with Customer, Asset, Net, Noncurrent	5,179	5,179	4,816
Customer deposits and refunds	342	342	$ 644
Increase (Decrease) in Receivables		(18,259)
Increase (Decrease) in Other Current Assets		0
Increase (Decrease) in Other Noncurrent Assets		363
Increase (Decrease) in Other Current Liabilities		(302)
Contract with Customer, Liability, Revenue Recognized	$ 200	$ 600

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Revenue Recognition Remaining Performance Obligations (Details) $ in Thousands	Jun. 30, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue from Contract with Customer [Abstract]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 489
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	652
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	652
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	652
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	275
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	275
FPU Electric Distribution [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	550
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	3,005
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	6,501
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	6,039
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,807
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,266
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	5,062
Natural gas distribution operations [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	33,448
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	18,561
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	31,914
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	24,570
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	22,402
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	21,550
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	20,494
Eastern Shore and Peninsula Pipeline [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	176,316
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	22,055
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	39,067
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	31,261
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	28,861
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	27,091
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	25,831
Total for Segments [Member] | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 210,314

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Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2021 USD ($) Dekatherm customer mi	Dec. 31, 2020 USD ($)
Rates and Other Regulatory Activities [Line Items]
Regulatory Asset - Storm Cost Recovery	$ 45,800
Surcharge - Storm Cost Recovery	7,700
Incremental Revenue - Storm Cost Recovery	3,300
COVID-19 Settlement Amount	2,100
COVID-19 Regulatory Asset	$ 1,600
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Extent of Customers Losing Service	100.00%
Hurricane Dorrian [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liability, Amortization Period	30 years
Regulatory Liability, Amortization Period, Revised	10 years
Asset Recovery Damaged Property Costs, Noncurrent	$ 1,200
Delaware natural gas division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	12,660	$ 12,728
Maryland Division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	3,905	3,970
Sandpiper [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	3,684	3,713
Central Florida Gas Division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	8,108	8,184
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	19,149	19,257
Fort Meade and Indiantown Divisions [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	303	309
FPU electric division [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	6,569	6,694
Eastern Shore Gas Company [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	34,190	34,190
Elkton Gas [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	$ 1,124	$ 1,124
Del-Mar Pathway Project [Member] | Eastern Shore Gas Company [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Mainline Pipeline Miles | mi	13
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	14,300
number of customers | customer	4
Number of Pipeline Miles | mi	6
Beachside Expansion | Peninsula Pipeline Company [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Mainline Pipeline Miles | mi	11.33
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	10,176
Winter Haven Expansion | Peninsula Pipeline Company [Member]
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	6,800
Regulated Energy [Member] | Escambia Meter
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm	530,000

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Environmental Commitments and Contingencies - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2021 USD ($) site	Dec. 31, 2020 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 3,904,000	$ 4,299,000
West Palm Beach Florida [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	3,300,000
West Palm Beach Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	14,200,000
Winter Haven Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	400,000
Seaford [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	300,000
Seaford [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	900,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	5,600,000	5,900,000
Approval of recovery of environmental costs	14,000,000.0
Environmental costs recovered	12,600,000	12,400,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 1,400,000	$ 1,600,000

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Other Commitments and Contingencies - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($)
Other Commitments [Line Items]
Debt Service Coverage Ratio	1.25
Debt Service Coverage Ratio Measurement Period	12
Maximum Days To Make Default Good	5 days
Ratio based on average number of prior quarters	6
Ratios based on average of the prior quarters	1 year 6 months
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	0.65
Number Of Years For Power Purchase Agreement	20 years
Contract Duration	20 years
Aggregate guaranteed amount	$ 20.0
Guarantor Obligations, Current Carrying Value	8.0
Draws on letters of credit	$ 4.8
Florida Natural Gas Distribution and Eight Flags [Member]
Other Commitments [Line Items]
Number of Years for Asset Management Agreement	10 years
Delmarva [Member]
Other Commitments [Line Items]
Number of Years for Asset Management Agreement	3 years

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Segment Information - Schedule of Segment Reporting Information by Segment (Detail) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Jun. 30, 2021 USD ($)	Jun. 30, 2020 USD ($)	Dec. 31, 2020 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments				2
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 111,082	$ 97,051	$ 302,268	$ 249,741
Operating Income
Total operating income		22,578	17,977	74,175	60,111
Other expense, net		1,456	(279)	1,841	3,039
Interest		5,054	5,054	10,159	10,868
Income Before Income Taxes		18,980	12,644	65,857	52,282
Income Taxes on Continuing Operations		5,165	1,983	17,570	12,580
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent		13,815	10,661	48,287	39,702
Net Income		13,813	10,956	48,279	39,886
Identifiable Assets
Total identifiable assets		1,972,340		1,972,340		$ 1,932,487
Discontinued Operation, Income (Loss) from Discontinued Operation During Phase-out Period, Net of Tax		(2)	295	(8)	184
Regulated Energy [Member]
Operating Income
Total operating income		22,808	18,006	55,673	45,894
Identifiable Assets
Total identifiable assets		1,568,136		1,568,136		1,547,619
Unregulated Energy [Member]
Operating Income
Total operating income		(445)	281	18,660	14,142
Identifiable Assets
Total identifiable assets		359,971		359,971		347,665
Other [Member]
Identifiable Assets
Total identifiable assets		44,233		44,233		$ 37,203
Other and eliminations [Member]
Operating Income
Total operating income		215	(310)	(158)	75
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		111,082	97,051	302,268	249,741
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		80,374	73,044	201,095	175,512
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		30,708	24,007	101,173	74,229
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	4,734	4,340	9,635	8,749
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	536	474	1,012	961
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	4,065	3,733	8,358	7,523
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	133	133	265	265
Retained Earnings [Member]
Operating Income
Income (Loss) from Continuing Operations, Net of Tax, Attributable to Parent		13,815	10,661	48,287	39,702
Net Income		$ 13,813	$ 10,956	$ 48,279	$ 39,886

[1] All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ / shares in Units, shares in Millions	3 Months Ended				6 Months Ended
	Jun. 30, 2021	Mar. 31, 2021	Dec. 31, 2020	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		$ (2,865,000)			$ (2,865,000)	$ (6,267,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax					5,848,000	2,741,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax					(2,425,000)	(936,000)
Net current-period other comprehensive income (loss)	$ 3,196,000			$ 1,732,000	3,423,000	1,805,000
Ending balance	558,000		$ (2,865,000)	(4,462,000)	$ 558,000	(4,462,000)
Stock Issued During Period, Shares, Dividend Reinvestment Plan			0.3		0.1
Stock Issued During Period, Value, Dividend Reinvestment Plan			$ 86.12		$ 113.51
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan			$ 22,000,000.0		$ 4,500,000
Common Stock Shares Issued At The Market			0.7
Shares Issued Price Per Share - At The Market			$ 82.93
Proceeds From Issuance Of Common Stock - At The Market		61,000,000.0
Stock Issued During Period, Shares, Dividend Reinvestment Plan			0.3		0.1
Stock Issued During Period, Value, Dividend Reinvestment Plan			$ 86.12		$ 113.51
Proceeds from Issuance of Common Stock, Dividend Reinvestment Plan			22,000,000.0		4,500,000
Fees on Equity Issuance - At The Market		1,500,000
Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Proceeds from Stock Plans			75,000,000.0
Proceeds from Stock Plans			75,000,000.0
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		(5,146,000)			(5,146,000)	(4,933,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax					0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax					128,000	132,000
Net current-period other comprehensive income (loss)					128,000	132,000
Ending balance	(5,018,000)		(5,146,000)	(4,801,000)	(5,018,000)	(4,801,000)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		2,309,000			2,309,000	(1,334,000)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax					5,825,000	2,770,000
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax					(2,534,000)	(1,060,000)
Net current-period other comprehensive income (loss)					3,291,000	1,710,000
Ending balance	5,600,000		2,309,000	376,000	5,600,000	376,000
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Beginning balance		$ (28,000)			(28,000)	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax					23,000	(29,000)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax					(19,000)	(8,000)
Net current-period other comprehensive income (loss)					4,000	(37,000)
Ending balance	$ (24,000)		$ (28,000)	$ (37,000)	$ (24,000)	$ (37,000)

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Amortization of pension and postretirement items:
Tax benefit		$ (5,165)	$ (1,983)	$ (17,570)	$ (12,580)
Derivative, Gain (Loss) on Derivative, Net		4,804	2,552	8,057	3,788
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		281	114	2,425	936
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	[1]	19	19	38	38
Net loss	[1]	(106)	(108)	(209)	(215)
Total before tax		(87)	(89)	(171)	(177)
Tax benefit		23	23	43	45
Net of tax		(64)	(66)	(128)	(132)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Tax benefit		(126)	(66)	(968)	(405)
Net of tax		329	172	2,534	1,060
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements			11		11
Tax benefit		(6)	(3)	(7)	(3)
Net of tax		16	8	19	8
Propane Swap Agreement [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	[2]	455	238	3,502	1,465
Interest Rate Swap [Member] | Derivatives designated as hedging instrument [Member] | Interest Expense [Member]
Amortization of pension and postretirement items:
Derivative, Gain (Loss) on Derivative, Net		$ 22	$ 11	$ 26	$ 11

[1] These amounts are included in the computation of net periodic costs (benefits). See Note 10, Employee Benefit Plans, for additional details.

[2] These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments, for additional details.

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Employee Benefit Plans (Detail) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended
		Jun. 30, 2021		Jun. 30, 2020		Jun. 30, 2021	Jun. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)		$ (19)		$ (38)	$ (38)
Defined Benefit Plan Actuarial Gain Loss, Net Settlement				198			396
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		230		217		458	434
Defined Benefit Plan Amounts Recognized Gain (Loss)		211		198		420	396
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]	87		89		171	178
Defined Benefit Plan Amounts Recognized From Regulatory Asset		124		109		249	218
Defined Benefit Plan, Expected Future Benefit Payment, Remainder of Fiscal Year		700				700
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer		100
Interest cost		34		46		68	92
Expected return on plan assets		(40)		(42)		(80)	(84)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		60		65		120	130
Net periodic cost (benefit)		54	[1]	69	[1]	108	138
Total periodic cost		54		69		108	138
Defined Benefit Plan Amounts Recognized Gain (Loss)		60		65		120	130
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]	60		65		120	130
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		300				300
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer		500
Interest cost		429		518		858	1,036
Expected return on plan assets		(830)		(745)		(1,660)	(1,490)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		155		135		310	270
Net periodic cost (benefit)		(246)	[1]	(92)	[1]	(492)	(184)
Amortization of pre-merger regulatory asset		0		0		0	0
Total periodic cost		(246)		(92)		(492)	(184)
Defined Benefit Plan Amounts Recognized Gain (Loss)		155		135		310	270
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]	29		26		58	52
Defined Benefit Plan Amounts Recognized From Regulatory Asset		126		109		252	218
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		2,100				2,100
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer						100
Interest cost		12		16		24	32
Defined Benefit Plan Actuarial Gain Loss, Net Settlement				5			10
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		7		5		14	10
Net periodic cost (benefit)		19	[1]	21	[1]	38	42
Total periodic cost		19		21		38	42
Defined Benefit Plan Amounts Recognized Gain (Loss)		7		5		14	10
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]	7		5		14	10
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		200				200
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Plan Assets, Contributions by Employer						200
Interest cost		6		8		12	16
Amortization of prior service cost		(19)		(19)		(38)	(38)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		10		12		18	24
Net periodic cost (benefit)		(3)	[1]	1	[1]	(8)	2
Total periodic cost		(3)		1		(8)	2
Defined Benefit Plan Amounts Recognized Gain (Loss)		(9)		(7)		(20)	(14)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]	(9)		(7)		(20)	(14)
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		200				200
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		6		10		12	20
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(2)				(4)
Net periodic cost (benefit)		4	[1]	10	[1]	8	20
Amortization of pre-merger regulatory asset		0		2		0	4
Total periodic cost		4		$ 12		8	$ 24
Defined Benefit Plan Amounts Recognized Gain (Loss)		(2)				(4)
Other Comprehensive (Income) Loss, Defined Benefit Plan, after Reclassification Adjustment, before Tax	[1]					(1)
Defined Benefit Plan Amounts Recognized From Regulatory Asset		(2)				(3)
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		$ 100				$ 100

[1] See Note 9, Stockholders' Equity.

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Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)	$ (19)	$ (38)	$ (38)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		230	217	458	434
Defined Benefit Plan Amounts Recognized Gain (Loss)		211	198	420	396
Recognized from accumulated other comprehensive loss	[1]	87	89	171	178
Recognized from regulatory asset		124	109	249	218
Defined Benefit Plan Actuarial Gain Loss, Net Settlement			198		396
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan		500
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		2,100		2,100
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		155	135	310	270
Defined Benefit Plan Amounts Recognized Gain (Loss)		155	135	310	270
Recognized from accumulated other comprehensive loss	[1]	29	26	58	52
Recognized from regulatory asset		126	109	252	218
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan		100
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		300		300
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		60	65	120	130
Defined Benefit Plan Amounts Recognized Gain (Loss)		60	65	120	130
Recognized from accumulated other comprehensive loss	[1]	60	65	120	130
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan				100
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		200		200
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		7	5	14	10
Defined Benefit Plan Amounts Recognized Gain (Loss)		7	5	14	10
Recognized from accumulated other comprehensive loss	[1]	7	5	14	10
Defined Benefit Plan Actuarial Gain Loss, Net Settlement			5		10
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan				200
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		200		200
Amortization of prior service cost		(19)	(19)	(38)	(38)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		10	12	18	24
Defined Benefit Plan Amounts Recognized Gain (Loss)		(9)	(7)	(20)	(14)
Recognized from accumulated other comprehensive loss	[1]	(9)	$ (7)	(20)	$ (14)
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year		100		100
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(2)		(4)
Defined Benefit Plan Amounts Recognized Gain (Loss)		(2)		(4)
Recognized from accumulated other comprehensive loss	[1]			(1)
Recognized from regulatory asset		$ (2)		$ (3)

[1] See Note 9, Stockholders' Equity.

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Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (19)	$ (19)	$ (38)	$ (38)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		230	217	458	434
Recognized from accumulated other comprehensive loss	[1]	87	89	171	178
Recognized from regulatory asset		124	109	249	218
Defined Benefit Plan Actuarial Gain Loss, Net Settlement			198		396
Total recognized in net periodic benefit cost		211	198	420	396
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		60	65	120	130
Recognized from accumulated other comprehensive loss	[1]	60	65	120	130
Total recognized in net periodic benefit cost		60	65	120	130
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		155	135	310	270
Recognized from accumulated other comprehensive loss	[1]	29	26	58	52
Recognized from regulatory asset		126	109	252	218
Total recognized in net periodic benefit cost		155	135	310	270
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		7	5	14	10
Recognized from accumulated other comprehensive loss	[1]	7	5	14	10
Defined Benefit Plan Actuarial Gain Loss, Net Settlement			5		10
Total recognized in net periodic benefit cost		7	5	14	10
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(19)	(19)	(38)	(38)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		10	12	18	24
Recognized from accumulated other comprehensive loss	[1]	(9)	(7)	(20)	(14)
Total recognized in net periodic benefit cost		(9)	$ (7)	(20)	$ (14)
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(2)		(4)
Recognized from accumulated other comprehensive loss	[1]			(1)
Recognized from regulatory asset		(2)		(3)
Total recognized in net periodic benefit cost		$ (2)		$ (4)

[1] See Note 9, Stockholders' Equity.

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Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Investments schedule [Line Items]
Investments, at fair value	$ 11,745	$ 10,776
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	11,723	10,755
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 22	$ 21

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Investments - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Investments, Debt and Equity Securities [Abstract]
Unrealized gain (loss), net of other expenses	$ 600,000	$ 1,400,000	$ 1,000,000.0	$ (100,000)

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Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1,439	$ 1,266	$ 3,315	$ 2,322
Less: tax benefit	(384)	(331)	(885)	(607)
Share-Based Compensation amounts included in net income	1,055	935	$ 2,430	1,715
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			683
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			$ 117.11
Total compensation expense	$ 192	181	$ 380	357
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	194,107		194,107		186,878
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			66,612
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			53,147
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period			(852)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 94.61		$ 94.61		$ 87.06
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value			102.73
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			76.31
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expirations Weighted Average Grant Date Fair Value			$ 74.85
Total compensation expense	$ 1,247	$ 1,085	$ 2,935	$ 1,965

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Share-Based Compensation - Summary of Stock Activity under the SICP (Detail) - $ / shares	3 Months Ended	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021
Award to key employees [Member]
Number of Shares
Outstanding - December 31, 2020 (shares)		186,878
Granted awards (shares)		66,612
Vested (shares)		(53,147)
Expired (shares)		852
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(5,384)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 93.39
Outstanding - June 30, 2021 (shares)	194,107	194,107
Weighted Average Fair Value
Outstanding - December 31, 2020 (in dollars per share)		$ 87.06
Granted (in dollars per share)		102.73
Vested (in dollars per share)		76.31
Expired (in dollars per share)		74.85
Outstanding - June 30, 2021 (in dollars per share)	$ 94.61	$ 94.61
Awards to non-employee directors [Member]
Number of Shares
Granted awards (shares)		683
Weighted Average Fair Value
Granted (in dollars per share)		$ 117.11

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Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2021	Jun. 30, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		14,020	10,319
Payment, Tax Withholding, Share-based Payment Arrangement		$ 1,478	$ 977
Unrecognized compensation cost	$ 6,100	$ 6,100
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 117.11
Granted awards (shares)		683
Unrecognized compensation expense related to the awards to non-employee directors	700	$ 700
Total [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)		6,830
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period		(852)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value		$ 102.73
Granted awards (shares)		66,612
Vesting period		3 years
Payment, Tax Withholding, Share-based Payment Arrangement		$ 1,500
Intrinsic value of the SICP awards	$ 23,400	$ 23,400
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	(5,384)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 93.39
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		14,020

XML

Derivative Instruments Volume of Derivative Activity (Details) - Sharp Energy Inc [Member] gal in Millions, $ in Millions	6 Months Ended
	Jun. 30, 2021 USD ($) gal
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 5.4
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimate of Time to Transfer	12 months
Swap Purchases
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	23.3
Swap Sales
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	5.0

XML

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended
	Feb. 28, 2021	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020
Derivative [Line Items]
Energy Marketing Contracts Assets, Current		$ 8,056	$ 8,056	$ 3,269
Energy Marketing Contract Liabilities, Current		(351)	(351)	(127)
Notional Amount of Nonderivative Instruments	$ 40,000	100,000		60,000
Interest Rate Swap [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			100
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current		8,056	8,056	3,255
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Interest Rate Swap [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		(34)	(34)	(40)
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current		(317)	(317)	(64)
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months			$ 5,400
Derivative Instruments, Gain (Loss) Reclassification from Accumulated OCI to Income, Estimate of Time to Transfer			12 months
Other Payables to Broker-Dealers and Clearing Organizations		$ 4,808	$ 4,808	$ 1,505
Interest Rate Swap Rate, High Range [Member]
Derivative [Line Items]
Fixed Swap Rate		0.17%	0.17%	0.205%
Interest Rate Swap Rate, Low Range [Member]
Derivative [Line Items]
Fixed Swap Rate				0.20%

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 8,056	$ 3,269
Energy Marketing Contract Liabilities, Current	351	127
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	8,056	3,255
Mark To Market Energy Assets [Member] | Put Option [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		14
Energy Marketing Contract Liabilities, Current		23
Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	317	64
Mark-to-market energy liabilities [Member] | Interest Rate Swap [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 34	$ 40

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 4,804	$ 2,552	$ 8,057	$ 3,788
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	455	238	3,502	1,465
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Put Or Call Option
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0		(24)
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	4,319	2,354	4,548	2,363
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	8	(51)	5	(51)
Interest Expense [Member] | Derivatives designated as hedging instrument [Member] | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 22	$ 11	$ 26	$ 11

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Assets:
Investments	$ 11,745	$ 10,776
Energy Marketing Contracts Assets, Current	8,056	3,269
Liabilities:
Energy Marketing Contract Liabilities, Current	351	127
Equity Securities [Member]
Assets:
Investments	22	21
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	9,554	8,620
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	22	21
Quoted Prices in Active Markets (Level 1) [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments	9,532	8,599
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member]
Assets:
Investments	9,554	8,620
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	8,056	3,269
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	2,191	2,156
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	2,191	2,156
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member]
Assets:
Investments	2,191	2,156
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	19,801	14,045
Liabilities:
Energy Marketing Contract Liabilities, Current		127
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	22	21
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	2,191	2,156
Recurring [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments		8,599
Recurring [Member] | Total Investments [Member]
Assets:
Investments	$ 11,745	10,776
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets		$ 3,269

XML

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020	Dec. 31, 2020
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	$ 11,745		$ 10,776
Derivative assets, at fair value	8,056		3,269
Energy Marketing Contract Liabilities, Current	351		127
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	(51)	$ (50)
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	2,156	803
Purchases and adjustments	70	226
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Transfers out of Level 3	0	1,345
Investment Income	16	10
Ending Balance	2,191	$ 2,334
Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Assets, Fair Value Disclosure	9,554		8,620
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Assets, Fair Value Disclosure	8,056		3,269
Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Assets, Fair Value Disclosure	2,191		2,156
Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Assets, Fair Value Disclosure	19,801		14,045
Energy Marketing Contract Liabilities, Current			127
Equity Securities [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	22		21
Equity Securities [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	22		21
Equity Securities [Member] | Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	22		21
Investments in guaranteed income fund [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	2,191		2,156
Investments in guaranteed income fund [Member] | Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	2,191		2,156
Investments - Mutual funds and other [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	9,532		8,599
Investments - Mutual funds and other [Member] | Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value			8,599
Total Investments [Member] | Quoted Prices in Active Markets (Level 1) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	9,554		8,620
Total Investments [Member] | Significant Unobservable Inputs (Level 3) [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	2,191		2,156
Total Investments [Member] | Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Investments, at fair value	$ 11,745		10,776
Mark To Market Energy Assets Including Put Option [Member] | Recurring [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Derivative Asset			$ 3,269

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2021	Dec. 31, 2020
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 512.9	$ 523.0
Fair value of long-term debt	$ 541.5	$ 548.5

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Jun. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Total long-term debt		$ (512,900)	$ (523,000)
Debt Instrument, Unused Borrowing Capacity, Amount		310,000
Total Long-term debt		512,050	522,099
Less: current maturities		(13,600)	(13,600)
Less: debt issuance costs		850	901
Total long-term debt, net of current maturities		498,450	508,499
Aggregated Unfunded Commitments [Member]
Debt Instrument [Line Items]
Total long-term debt		0
New York Life [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	$ (140,000)
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		9.08%
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		5.50%
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (7,500)	(9,000)
Debt Instrument, Interest Rate, Stated Percentage		5.93%
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (14,500)	(17,400)
Debt Instrument, Interest Rate, Stated Percentage		5.68%
6.43% note, due May 2, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (4,900)	(5,600)
Debt Instrument, Interest Rate, Stated Percentage		6.43%
3.73% note, due December 16, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (16,000)	(16,000)
Debt Instrument, Interest Rate, Stated Percentage		3.73%
3.88% note, due May 15, 2029 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (40,000)	(45,000)
Debt Instrument, Interest Rate, Stated Percentage		3.88%
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (70,000)	(70,000)
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Total long-term debt		(50,000)	(50,000)
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt		$ (50,000)	(50,000)
Debt Instrument, Interest Rate, Stated Percentage		3.58%
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Debt Instrument [Line Items]
Total long-term debt		$ (50,000)	(50,000)
Debt Instrument, Interest Rate, Stated Percentage		3.00%
Uncollateralized Senior Note Due August Two Thousand Thirty Five
Debt Instrument [Line Items]
Total long-term debt		$ (40,000)	(40,000)
Debt Instrument, Interest Rate, Stated Percentage		2.96%
Uncollateralized Senior Note Due November Two Thousand Thirty Nine
Debt Instrument [Line Items]
Total long-term debt		$ (100,000)	$ (100,000)
Aggregate Shelf Agreements [Member]
Debt Instrument [Line Items]
Total long-term debt		(360,000)
Aggregate Shelf Agreements [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount		670,000
Prudential [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	(220,000)
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	150,000
Prudential [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	[1]	370,000
MetLife [Member]
Debt Instrument [Line Items]
Debt Instrument, Face Amount	[1]	150,000
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	$ 150,000

[1] (1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively.

XML

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	6 Months Ended
	Jun. 30, 2021
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Jun. 01, 2022
Debt Instrument, Interest Rate, Stated Percentage	9.08%
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Oct. 12, 2020
Debt Instrument, Interest Rate, Stated Percentage	5.50%
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Oct. 31, 2023
Debt Instrument, Interest Rate, Stated Percentage	5.93%
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Jun. 30, 2026
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	May 02, 2028
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Dec. 16, 2028
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	May 15, 2029
Debt Instrument, Interest Rate, Stated Percentage	3.88%
3.25% due April 30, 2032 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Apr. 30, 2032
Debt Instrument, Interest Rate, Stated Percentage	3.25%
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	May 31, 2038
Debt Instrument, Interest Rate, Stated Percentage	3.48%
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Nov. 30, 2038
Debt Instrument, Interest Rate, Stated Percentage	3.58%
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Aug. 20, 2039
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member]
Debt Instrument [Line Items]
Debt instrument, maturity date	Dec. 20, 2034
Debt Instrument, Interest Rate, Stated Percentage	2.98%
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Debt Instrument [Line Items]
Debt instrument, maturity date	Jul. 15, 2035
Debt Instrument, Interest Rate, Stated Percentage	3.00%
Uncollateralized Senior Note Due August Two Thousand Thirty Five
Debt Instrument [Line Items]
Debt instrument, maturity date	Aug. 15, 2035
Debt Instrument, Interest Rate, Stated Percentage	2.96%

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands		6 Months Ended
		Jun. 30, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Document Period End Date		Jun. 30, 2021
Long-term debt including current maturities		$ 512,900	$ 523,000
Debt Instrument, Unused Borrowing Capacity, Amount		$ 310,000
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage		2.98%
Term Note Due January Two Thousand Twenty [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		$ 70,000	70,000
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		50,000	50,000
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		70,000	$ 70,000
New York Life [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	[1]	140,000
Aggregated Unfunded Commitments [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		0
Aggregate Shelf Agreements [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		360,000
MetLife [Member]
Debt Instrument [Line Items]
Senior notes	[1]	150,000
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	150,000
Prudential [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	[1]	220,000
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	150,000
New York Life [Member]
Debt Instrument [Line Items]
Debt Instrument, Unused Borrowing Capacity, Amount	[1]	10,000
Maximum [Member] | Aggregate Shelf Agreements [Member]
Debt Instrument [Line Items]
Senior notes		670,000
Maximum [Member] | Prudential [Member]
Debt Instrument [Line Items]
Senior notes	[1]	370,000
Maximum [Member] | New York Life [Member]
Debt Instrument [Line Items]
Senior notes	[1]	$ 150,000

[1] (1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively.

XML

Short-Term Borrowings (Details) - USD ($)	1 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended
	Feb. 28, 2021	Jun. 30, 2021	Jun. 30, 2021	Dec. 31, 2020	Dec. 31, 2021
Short-term Debt [Line Items]
Line of Credit Facility, Commitment Fee Percentage			15.00%
Ratio of Indebtedness to Net Capital		0.65	0.65
Debt Instrument, Description of Variable Rate Basis			100.00%
Notional Amount of Nonderivative Instruments	$ 40,000,000	$ 100,000,000.0		$ 60,000,000
Line of Credit Facility, Maximum Borrowing Capacity		375,000,000.0	$ 375,000,000.0
Line of Credit Facility, Remaining Borrowing Capacity					$ 200,900,000
Short-term borrowing		$ 169,294,000	$ 169,294,000	$ 175,644,000
Short-term Debt, Weighted Average Interest Rate, at Point in Time		1.11%	1.11%	1.28%
Draws on letters of credit			$ 4,800,000
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 0.75 percent
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			Lender's base rate, plus 0.75 percent
Committed Line of Credit Facility Five [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			Lender's base rate, plus 0.85 percent
Committed Line of Credit Facility Four [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 1.125 percent
Committed Line of Credit Facility Six [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 1.75 percent
Committed Line of Credit Facility Seven [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 1.75 percent
Committed Line of Credit Facility Eight [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 1.75 percent
Committed Line of Credit Facility Nine [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 1.75 percent
Committed Line of Credit Facility One [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis			LIBOR rate, plus 0.75 percent
Revolving Credit Facility
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity		$ 400,000,000.0	$ 400,000,000.0
Interest Rate Swap Rate, Low Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate				0.20%
Interest Rate Swap Rate, High Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate		0.17%	0.17%	0.205%

XML

Leases (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Lease Disclosure [Abstract]
Operating Lease, Right-of-Use Asset	$ 10,020	$ 11,194
Operating Lease, Liability, Current	1,732	1,747
Operating Lease, Liability, Noncurrent	8,719	9,872
Total Operating and Finance Lease Liabilities	$ 10,451	$ 11,619

XML

Leases Leases - Lease Cost Additional Information (Details) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2021	Jun. 30, 2020	Jun. 30, 2021	Jun. 30, 2020
Lease, Cost [Abstract]
Operating Lease, Cost	[1]	$ 515	$ 629	$ 1,038	$ 1,255

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

XML

Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification Additional Information (Details) - USD ($) $ in Thousands	Jun. 30, 2021	Dec. 31, 2020
Leases - Right of Use Asset and Lease Liability Balance Sheet Classification [Abstract]
Operating Lease, Right-of-Use Asset	$ 10,020	$ 11,194
Operating Lease, Liability, Current	1,732	1,747
Operating Lease, Liability, Noncurrent	8,719	9,872
Total Operating and Finance Lease Liabilities	$ 10,451	$ 11,619

XML

Leases Leases - Weighted Average Remaining Lease Term Additional Information (Details)	Jun. 30, 2021	Dec. 31, 2020
Leases - Weighted Average Remaining Lease term Additional Information [Abstract]
Operating Lease, Weighted Average Discount Rate, Percent	3.80%	3.80%
Operating Lease, Weighted Average Remaining Lease Term	8 years 7 months 24 days	8 years 8 months 12 days

XML

Leases Leases - Cash Flow Additional Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2021	Jun. 30, 2020
Leases - Cash Flow Additional Information [Abstract]
Operating Cash Flow from Operating Leases	$ 936	$ 1,034

XML

Leases Leases - Schedule of Future Maturities Additional Information (Details) $ in Thousands	Jun. 30, 2021 USD ($)
Leases - Schedule of Future Maturities Additional Information [Abstract]
Lessee, Operating Lease, Liability, Payments, Remainder of Fiscal Year	$ 1,060	[1]
Lessee, Operating Lease, Liability, to be Paid, Year One	1,845	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Two	1,762	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Three	1,607	[1]
Lessee, Operating Lease, Liability, Payments, Due	12,208	[1]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	1,757
Operating Lease, Liability	10,451	[1]
Lessee Future Operating Lease Option Payments	2,100
Lessee, Operating Lease, Liability, Payments, Due Year Four	1,387	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Five	951	[1]
Lessee, Operating Lease, Liability, to be Paid, after Year Five	$ 3,596	[1]

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