UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM	10-Q/A
AMENDMENT NO.1

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

For the quarterly period ended: September 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 — 17,604,196 shares outstanding as of November 1, 2021.

EXPLANATORY NOTE

Chesapeake Utilities Corporation (“Chesapeake Utilities”) is filing this Amendment No. 1 (this “Amendment”) to its Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, originally filed with the Securities and Exchange Commission (the “SEC”) on November 3, 2021 (the “Original 10-Q”). This Amendment is being filed solely for the purpose of correcting an incorrect date in the certification by the Company’s Chief Executive Officer and Chief Financial Officer pursuant to Sections 302 and 906 of the Sarbanes-Oxley Act of 2002 filed as Exhibits 31.1, 31.2, 32.1 and 32.2 to the Original 10-Q. In accordance with the Compliance and Disclosure Interpretations published by the SEC staff, the entire periodic report for the quarter ended September 30, 2021 is included in this Amendment. Other than the corrections described above, no other statement or amount has been changed from those presented in the Original 10-Q.

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	32
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	59
ITEM 4.	CONTROLS AND PROCEDURES	60
PART II—OTHER INFORMATION		61
ITEM 1.	LEGAL PROCEEDINGS	61
ITEM 1A.	RISK FACTORS	61
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	62
ITEM 5.	OTHER INFORMATION	62
ITEM 6.	EXHIBITS	63
SIGNATURES		64

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 recently 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 wholly-owned subsidiary of Chesapeake Utilities

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

Escambia Meter 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 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 $400.0 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				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	80,396	$	82,762	$	282,503	$	259,235
Unregulated Energy and other	26,939		18,657		127,101		91,925
Total Operating Revenues	107,335		101,419		409,604		351,160
Operating Expenses
Regulated Energy cost of sales	15,294		16,271		72,785		67,490
Unregulated Energy and other cost of sales	12,072		5,640		55,578		30,250
Operations	34,075		34,959		109,886		105,516
Maintenance	4,267		3,717		12,568		11,695
Gain from settlement	—		—		—		(130)
Depreciation and amortization	15,798		18,293		46,460		42,793
Other taxes	5,716		5,133		18,039		16,028
Total Operating Expenses	87,222		84,013		315,316		273,642
Operating Income	20,113		17,406		94,288		77,518
Other income (expense), net	339		(40)		2,180		2,997
Interest charges	4,975		4,584		15,134		15,452
Income from Continuing Operations Before Income Taxes	15,477		12,782		81,334		65,063
Income Taxes on Continuing Operations	2,993		3,502		20,563		16,082
Income from Continuing Operations	12,484		9,280		60,771		48,981
Income (Loss) from Discontinued Operations, Net of Tax	(9)		(19)		(17)		165
Net Income	$	12,475	$	9,261	$	60,754	$	49,146
Weighted Average Common Shares Outstanding:
Basic	17,582,115		16,533,748		17,538,461		16,466,106
Diluted	17,659,643		16,592,842		17,610,158		16,523,200
Basic Earnings Per Share of Common Stock:
Earnings from Continuing Operations	$	0.71	$	0.56	$	3.46	$	2.97
Earnings from Discontinued Operations	—		—		—		0.01
Basic Earnings Per Share of Common Stock	$	0.71	$	0.56	$	3.46	$	2.98
Diluted Earnings Per Share of Common Stock:
Earnings from Continuing Operations	$	0.71	$	0.56	$	3.45	$	2.96
Earnings from Discontinued Operations	—		—		—		0.01
Diluted Earnings Per Share of Common Stock	$	0.71	$	0.56	$	3.45	$	2.97

    

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				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands)
Net Income	$	12,475	$	9,261	$	60,754	$	49,146
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5), $(5), $(15) and $(15), respectively	(14)		(14)		(42)		(42)
Net gain, net of tax of $28, $28, $83 and $83, respectively	78		80		234		240
Cash Flow Hedges, net of tax:
Unrealized gain on commodity contract cash flow hedges, net of tax of $688, $282, $1,945 and $935, respectively	1,803		740		5,094		2,450
Unrealized gain/(loss) on interest rate swap cash flow hedges, net of tax of $5, $10, $6 and $(4), respectively	14		27		18		(10)
Total Other Comprehensive Income, net of tax	1,881		833		5,304		2,638
Comprehensive Income	$	14,356	$	10,094	$	66,058	$	51,784

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

2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	September 30, 2021		December 31, 2020
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,688,938	$	1,577,576
Unregulated Energy	324,083		300,647
Other businesses and eliminations	35,183		30,769
Total property, plant and equipment	2,048,204		1,908,992
Less: Accumulated depreciation and amortization	(405,263)		(368,743)
Plus: Construction work in progress	56,773		60,929
Net property, plant and equipment	1,699,714		1,601,178
Current Assets
Cash and cash equivalents	5,886		3,499
Trade and other receivables	47,570		61,675
Less: Allowance for credit losses	(2,980)		(4,785)
Trade and other receivables, net	44,590		56,890
Accrued revenue	11,318		21,527
Propane inventory, at average cost	6,917		5,906
Other inventory, at average cost	6,716		5,539
Regulatory assets	12,021		10,786
Storage gas prepayments	4,663		2,455
Income taxes receivable	12,702		12,885
Prepaid expenses	15,555		13,239
Derivative assets, at fair value	12,185		3,269
Other current assets	440		436
Total current assets	132,993		136,431
Deferred Charges and Other Assets
Goodwill	38,803		38,731
Other intangible assets, net	7,298		8,292
Investments, at fair value	11,490		10,776
Operating lease right-of-use assets	9,602		11,194
Regulatory assets	107,872		113,806
Receivables and other deferred charges	14,056		12,079
Total deferred charges and other assets	189,121		194,878
Total Assets	$	2,021,828	$	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	September 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)	8,560		8,499
Additional paid-in capital	361,066		348,482
Retained earnings	378,897		342,969
Accumulated other comprehensive income (loss)	2,439		(2,865)
Deferred compensation obligation	7,186		5,679
Treasury stock	(7,186)		(5,679)
Total stockholders’ equity	750,962		697,085
Long-term debt, net of current maturities	505,459		508,499
Total capitalization	1,256,421		1,205,584
Current Liabilities
Current portion of long-term debt	16,206		13,600
Short-term borrowing	192,026		175,644
Accounts payable	53,026		60,253
Customer deposits and refunds	35,782		33,302
Accrued interest	4,783		2,905
Dividends payable	8,442		7,683
Accrued compensation	13,497		13,994
Regulatory liabilities	5,357		6,284
Derivative liabilities, at fair value	1,969		127
Other accrued liabilities	23,454		15,240
Total current liabilities	354,542		329,032
Deferred Credits and Other Liabilities
Deferred income taxes	225,448		205,388
Regulatory liabilities	143,164		142,736
Environmental liabilities	3,709		4,299
Other pension and benefit costs	28,113		30,673
Operating lease - liabilities	8,380		9,872
Deferred investment tax credits and other liabilities	2,051		4,903
Total deferred credits and other liabilities	410,865		397,871
Environmental and other commitments and contingencies (Notes 6 and 7)
Total Capitalization and Liabilities	$	2,021,828	$	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)

	Nine Months Ended
	September 30,
	2021		2020
(in thousands)
Operating Activities
Net income	$	60,754	$	49,146
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	46,460		42,793
Depreciation and accretion included in other costs	7,668		7,062
Deferred income taxes	18,059		22,184
Gain on sale of discontinued operations	—		(200)
Realized gain on commodity contracts and sale of assets	(6,255)		(4,876)
Unrealized (gain) loss on investments/commodity contracts	(949)		(432)
Employee benefits and compensation	(519)		32
Share-based compensation	4,620		3,654
Changes in assets and liabilities:
Accounts receivable and accrued revenue	22,439		10,255
Propane inventory, storage gas and other inventory	(4,396)		2,824
Regulatory assets/liabilities, net	(6,562)		(2,284)
Prepaid expenses and other current assets	(6,813)		1,135
Accounts payable and other accrued liabilities	18,325		(924)
Income taxes (payable) receivable	183		(6,809)
Customer deposits and refunds	2,480		1,572
Accrued compensation	(740)		(5,506)
Other assets and liabilities, net	(1,970)		(3,746)
Net cash provided by operating activities	152,784		115,880
Investing Activities
Property, plant and equipment expenditures	(148,213)		(123,421)
Proceeds from sale of assets	727		4,320
Acquisitions, net of cash acquired	—		(15,629)
Proceeds from the sale of discontinued operations	—		200
Environmental expenditures	(590)		(2,021)
Net cash used in investing activities	(148,076)		(136,551)
Financing Activities
Common stock dividends	(23,287)		(20,044)
Issuance of stock under the Dividend Reinvestment Plan, net of offering fees	7,069		19,731
Tax withholding payments related to net settled stock compensation	(1,478)		(977)
Change in cash overdrafts due to outstanding checks	(508)		(2,310)
Net advances (repayments) under line of credit agreements	16,392		(29,385)
Proceeds from long-term debt, net of offering fees	9,590		89,827
Repayment of long-term debt	(10,099)		(40,100)
Net cash (used in) / provided by financing activities	(2,321)		16,742
Net Increase (Decrease) in Cash and Cash Equivalents	2,387		(3,929)
Cash and Cash Equivalents—Beginning of Period	3,499		6,985
Cash and Cash Equivalents—End of Period	$	5,886	$	3,056

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 June 30, 2020	16,463,808	$	8,013	$	263,272	$	326,454	$	(4,462)	$	5,659	$	(5,659)	$	593,277
Net income	—	—		—		9,261		—		—		—		9,261
Other comprehensive gain	—	—		—		—		833		—		—		833
Dividend declared ($0.440 per share)	—	—		—		(7,358)		—		—		—		(7,358)
Dividend reinvestment plan	232,684	113		19,420		—		—		—		—		19,533
Share-based compensation and tax benefit (3)(4)	—	—		1,144		—		—		—		—		1,144
Treasury stock activities	—	—		—		—		—		(25)		25		—
Balance at September 30, 2020	16,696,492	$	8,126	$	283,836	$	328,357	$	(3,629)	$	5,634	$	(5,634)	$	616,690
Balance at December 31, 2019	16,403,776	$	7,984	$	259,253	$	300,607	$	(6,267)	$	4,543	$	(4,543)	$	561,577
Net income	—	—		—		49,146		—		—		—		49,146
Other comprehensive income	—	—		—		—		2,638		—		—		2,638
Dividend declared ($1.285 per share)	—	—		—		(21,366)		—		—		—		(21,366)
Dividend reinvestment plan	258,260	126		21,693		—		—		—		—		21,819
Share-based compensation and tax benefit (3) (4)	34,456	16		2,890		—		—		—		—		2,906
Treasury stock activities	—	—		—		—		—		1,091		(1,091)		—
Cumulative effect of the adoption of ASU 2016-13	—	—		—		(30)		—		—		—		(30)
Balance at September 30, 2020	16,696,492	$	8,126	$	283,836	$	328,357	$	(3,629)	$	5,634	$	(5,634)	$	616,690
Balance at June 30, 2021	17,567,928	$	8,550	$	357,520	$	374,936	$	558	$	7,203	$	(7,203)	$	741,564
Net income	—	—		—		12,475		—		—		—		12,475
Other comprehensive income	—	—		—		—		1,881		—		—		1,881
Dividend declared ($0.480 per share)	—	—		—		(8,514)		—		—		—		(8,514)
Dividend reinvestment plan	19,906	10		2,441		—		—		—		—		2,451
Share-based compensation and tax benefit (3) (4)	—	—		1,105		—		—		—		—		1,105
Treasury stock activities	—	—		—		—		—		(17)		17		—
Balance at September 30, 2021	17,587,834	$	8,560	$	361,066	$	378,897	$	2,439	$	7,186	$	(7,186)	$	750,962
Balance at December 31, 2020	17,461,841	$	8,499	$	348,482	$	342,969	$	(2,865)	$	5,679	$	(5,679)	$	697,085
Net income	—	—		—		60,754		—		—		—		60,754
Other comprehensive income	—	—		—		—		5,304		—		—		5,304
Dividend declared ($1.400 per share)	—	—		—		(24,826)		—		—		—		(24,826)
Dividend reinvestment plan	80,022	39		9,247		—		—		—		—		9,286
Share-based compensation and tax benefit (3) (4)	45,971	22		3,337		—		—		—		—		3,359
Treasury stock activities	—	—		—		—		—		1,507		(1,507)		—
Balance at September 30, 2021	17,587,834	$	8,560	$	361,066	$	378,897	$	2,439	$	7,186	$	(7,186)	$	750,962

(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 114,016, 105,087, 104,119, and 95,329 shares at September 30, 2021, December 31, 2020, September 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 nine months ended September 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 widely 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. The expiration of the states of emergency in our service territories has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process. 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, and 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 we serve. 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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2.    Calculation of Earnings Per Share

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Income from Continuing Operations	$	12,484	$	9,280	$	60,771	$	48,981
Income/(Loss) from Discontinued Operations	(9)		(19)		(17)		165
Net Income	$	12,475	$	9,261	$	60,754	$	49,146
Weighted average shares outstanding	17,582,115		16,533,748		17,538,461		16,466,106
Basic Earnings Per Share from Continuing Operations	$	0.71	$	0.56	$	3.46	$	2.97
Basic Earnings Per Share from Discontinued Operations	—		—		—		0.01
Basic Earnings Per Share	$	0.71	$	0.56	$	3.46	$	2.98
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic	17,582,115		16,533,748		17,538,461		16,466,106
Effect of dilutive securities—Share-based compensation	77,528		59,094		71,697		57,094
Adjusted denominator—Diluted	17,659,643		16,592,842		17,610,158		16,523,200
Diluted Earnings Per Share from Continuing Operations	$	0.71	$	0.56	$	3.45	$	2.96
Diluted Earnings Per Share from Discontinued Operations	—		—		—		0.01
Diluted Earnings Per Share	$	0.71	$	0.56	$	3.45	$	2.97

3.     Acquisitions

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: (i) expansion of our propane territory serviced in Florida and (ii) establishment of a 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 September 30, 2021, Western Natural Gas generated operating revenue and income of $0.5 million and $0.1 million, respectively. For the nine months ended September 30, 2021, Western Natural Gas generated operating revenue and income of $1.9 million and $0.4 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.

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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. Upon reaching the end of the acquisition measurement period, we recognized offsetting adjustments to the acquisition date fair values of several of the assets acquired and liabilities assumed. These adjustments did not result in a change to our previously recognized amount of goodwill. For the three months ended September 30, 2021, Elkton Gas generated operating revenue and loss of $0.9 million and less than $0.1 million, respectively. For the nine months ended September 30, 2021, Elkton Gas generated operating revenue and income of $4.7 million and $0.7 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 September 30, 2021 and 2020:

	Three months ended September 30, 2021								Three months ended September 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	$	7,849	$	—	$	—	$	7,849	$	7,243	$	—	$	—	$	7,243
Florida natural gas division	8,015		—		—		8,015		7,309		—		—		7,309
FPU electric distribution	23,121		—		—		23,121		29,051		—		—		29,051
FPU natural gas distribution	22,012		—		—		22,012		19,935		—		—		19,935
Maryland natural gas division	2,432		—		—		2,432		2,824		—		—		2,824
Sandpiper natural gas/propane operations	3,553		—		—		3,553		3,290		—		—		3,290
Elkton Gas	915		—		—		915		623		—		—		623
Total energy distribution	67,897		—		—		67,897		70,275		—		—		70,275
Energy transmission
Aspire Energy	—		5,255		—		5,255		—		3,449		—		3,449
Aspire Energy Express	47		—		—		47		—		—		—		—
Eastern Shore	18,558		—		—		18,558		18,389		—		—		18,389
Peninsula Pipeline	6,776		—		—		6,776		6,433		—		—		6,433
Total energy transmission	25,381		5,255		—		30,636		24,822		3,449		—		28,271
Energy generation
Eight Flags	—		4,583		—		4,583		—		3,882		—		3,882
Propane operations
Propane delivery operations	—		20,680		—		20,680		—		13,710		—		13,710
Energy delivery services
Marlin Gas Services	—		1,678		—		1,678		—		1,708		—		1,708
Other and eliminations
Eliminations	(12,882)		(87)		(5,302)		(18,271)		(12,335)		(35)		(4,188)		(16,558)
Other	—		—		132		132		—		—		131		131
Total other and eliminations	(12,882)		(87)		(5,170)		(18,139)		(12,335)		(35)		(4,057)		(16,427)
Total operating revenues (1)	$	80,396	$	32,109	$	(5,170)	$	107,335	$	82,762	$	22,714	$	(4,057)	$	101,419

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(1) Total operating revenues for the three months ended September 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.1 million for both Regulated and Unregulated Energy segments, respectively, and $0.2 million and $0.05 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended September 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper Energy and late fees.

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

	Nine months ended September 30, 2021								Nine months ended September 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	$	51,188	$	—	$	—	$	51,188	$	45,568	$	—	$	—	$	45,568
Florida natural gas division	25,417		—		—		25,417		23,018		—		—		23,018
FPU electric distribution	60,569		—		—		60,569		58,972		—		—		58,972
FPU natural gas distribution	72,032		—		—		72,032		64,877		—		—		64,877
Maryland natural gas division	16,122		—		—		16,122		15,941		—		—		15,941
Sandpiper natural gas/propane operations	15,438		—		—		15,438		12,440		—		—		12,440
Elkton Gas	4,745		—		—		4,745		623		—		—		623
Total energy distribution	245,511		—		—		245,511		221,439		—		—		221,439
Energy transmission
Aspire Energy	—		23,738		—		23,738		—		17,784		—		17,784
Aspire Energy Express	140		—		—		140		—		—		—		—
Eastern Shore	57,147		—		—		57,147		55,944		—		—		55,944
Peninsula Pipeline	19,853		—		—		19,853		16,618		—		—		16,618
Total energy transmission	77,140		23,738		—		100,878		72,562		17,784		—		90,346
Energy generation
Eight Flags	—		13,086		—		13,086		—		11,898		—		11,898
Propane operations
Propane delivery operations	—		99,041		—		99,041		—		69,593		—		69,593
Energy delivery services
Marlin Gas Services	—		6,019		—		6,019		—		5,266		—		5,266
Other and eliminations
Eliminations	(40,148)		(242)		(14,937)		(55,327)		(34,766)		(75)		(12,937)		(47,778)
Other			—		396		396		—		—		396		396
Total other and eliminations	(40,148)		(242)		(14,541)		(54,931)		(34,766)		(75)		(12,541)		(47,382)
Total operating revenues (1)	$	282,503	$	141,642	$	(14,541)	$	409,604	$	259,235	$	104,466	$	(12,541)	$	351,160

(1) Total operating revenues for the nine months ended September 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million and $0.3 million for our Regulated and Unregulated Energy segments, respectively, and $1.0 million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, for the nine months ended September 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper Energy 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 September 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 9/30/2021	40,683		18		5,011		874
Increase (decrease)	$	(14,917)	$	—	$	195	$	230

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 September 30, 2021 and 2020, we recognized revenue of $0.2 million. For each of the nine months ended September 30, 2021 and 2020, we recognized revenue of $0.8 million, respectively.

Remaining performance obligations

Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations, at September 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	$	9,471	$	32,796	$	25,205	$	22,975	$	22,102	$	21,023	$	179,728
Natural gas distribution operations	1,752		6,620		6,044		5,811		5,271		5,064		33,448
FPU electric distribution	163		652		652		652		275		275		550
Total revenue contracts with remaining performance obligations	$	11,386	$	40,068	$	31,901	$	29,438	$	27,648	$	26,362	$	213,726

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

See the discussion below under COVID-19 impact.

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 accelerates

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Elkton Gas' Aldyl-A pipeline replacement program as costs of the plan are recovered through a fixed charge rider which is effective for five years. Under Elkton Gas’ STRIDE plan, the Aldyl-A pipelines will be fully replaced by 2023. In July 2021, Elkton Gas reached a settlement with the Maryland PSC Staff and the Maryland Office of Public Counsel that approved Elkton Gas’ STRIDE plan. The STRIDE plan allows for recovery of the associated revenue requirement through a monthly surcharge, which was implemented effective September 4, 2021.

Florida

Hurricane Michael: In late 2019, the Florida PSC approved an interim rate increase for FPU electric division's limited proceeding, 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. In September 2020, the Florida PSC approved a settlement agreement between FPU and the Florida OPC 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 August 2019, the Florida PSC approved Peninsula Pipeline’s Transportation Service Agreement with FPU. Peninsula Pipeline is constructing 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 and system pressure as well as introducing diversity in the fuel source for natural gas to serve the increased demand in these areas. Interim services began in the fourth quarter of 2019 and 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, 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. The Transportation Service Agreement was approved by the Florida PSC in September 2021.

Escambia Meter Station: In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power & Light Company and entered into a Transportation Service Agreement with Gulf Power Company for 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 in Pensacola, Florida.

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 11.3 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. Construction commenced in June 2021 and the expected in-service date is December 2022.

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. This includes 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

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Shore’s pipeline system, for the first time, into Somerset County, Maryland. The project is now fully in service as the construction of the Somerset County, Maryland expansion was completed in the third quarter of 2021.

Capital Cost Surcharge: In June 2021, Eastern Shore submitted a filing with the FERC regarding 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 cumulative adjustment to 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 became 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 have continued through the third quarter of 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 are gradually being lifted as vaccines are widely available in the United States. The state of emergency in Florida was terminated in May followed by Delaware and Maryland in July. Despite these positive state orders and in light of the 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 and the Occupational Safety and Health Administration, with a goal of minimizing further exposure for 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 the COVID-19 pandemic, 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 has reviewed and issued guidance regarding the distribution of funds and the manner in which the utilities will allocate the funds to customers with eligible arrearages. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas received $0.3 million 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. Funds to assist with individual customer arrearages have become available through the Delaware State Housing Authority. We are working to ensure that customers know how to seek this support and then apply it to their overdue utility bills.

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 Florida OPC filed a protest to the order approving the establishment of this regulatory asset treatment, contending that the order should be reversed or modified and to request a hearing on the protest. The Company’s Florida regulated business units reached a settlement with the Florida OPC 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

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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 regulatory asset over two years and recover it 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 and the final order was issued on July 22, 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 September 30, 2021 and December 31, 2020, our total COVID-19 regulatory asset balance was $2.3 million and $1.9 million, respectively.

    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 September 30, 2021 and December 31, 2020:

	Amount (in thousands)
Operation and Regulatory Jurisdiction	September 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)	$12,626	$12,728	PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)	$3,873	$3,970	PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)	$3,670	$3,713	PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)	$8,070	$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)	$19,132	$19,257	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions	$274	$309	Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)	$5,299	$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.

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As of September 30, 2021 and December 31, 2020, we had approximately $5.4 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 September 30, 2021 and December 31, 2020, we had recovered approximately $12.7 million and $12.4 million, respectively, leaving approximately $1.3 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.

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 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 September 30, 2021, FPU was in compliance with all of the requirements of its fuel supply contracts.

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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 September 30, 2021 was $20.0 million. The aggregate amount guaranteed at September 30, 2021 was approximately $8.0 million with the guarantees expiring on various dates through September 24, 2022.

As of September 30, 2021, we have issued letters of credit totaling approximately $4.6 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 September 30, 2022. We have not drawn on these letters of credit as of September 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 is presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments:

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	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	79,892	$	82,297	$	280,987	$	257,810
Unregulated Energy	27,443		19,122		128,617		93,350
Total operating revenues, unaffiliated customers	$	107,335	$	101,419	$	409,604	$	351,160
Intersegment Revenues (1)
Regulated Energy	$	504	$	465	$	1,516	$	1,425
Unregulated Energy	4,666		3,592		13,024		11,116
Other businesses	132		131		397		396
Total intersegment revenues	$	5,302	$	4,188	$	14,937	$	12,937
Operating Income
Regulated Energy	$	23,538	$	20,482	$	79,210	$	66,376
Unregulated Energy	(2,883)		(3,092)		15,777		11,050
Other businesses and eliminations	(542)		16		(699)		92
Operating income	20,113		17,406		94,288		77,518
Other income (expense), net	339		(40)		2,180		2,997
Interest charges	4,975		4,584		15,134		15,452
Income from Continuing Operations before Income Taxes	15,477		12,782		81,334		65,063
Income Taxes on Continuing Operations	2,993		3,502		20,563		16,082
Income from Continuing Operations	12,484		9,280		60,771		48,981
Income (Loss) from Discontinued Operations, Net of Tax	(9)		(19)		(17)		165
Net Income	$	12,475	$	9,261	$	60,754	$	49,146

    

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

(in thousands)	September 30, 2021		December 31, 2020
Identifiable Assets
Regulated Energy segment	$	1,592,950	$	1,547,619
Unregulated Energy segment	381,642		347,665
Other businesses and eliminations	47,236		37,203
Total identifiable assets	$	2,021,828	$	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 nine months of 2021, we issued less than 0.1 million shares at an average price per share of $116.63 and received net proceeds of $6.6 million under the DRIP. In October 2021, we issued less than 0.1 million shares at an average price per share of $127.40 and received net proceeds of $1.8 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 September 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	—		8,121		55		8,176
Amounts reclassified from accumulated other comprehensive income (loss)	192		(3,027)		(37)		(2,872)
Net current-period other comprehensive income	192		5,094		18		5,304
As of September 30, 2021	$	(4,954)	$	7,403	$	(10)	$	2,439

(in thousands)
As of December 31, 2019	$	(4,933)	$	(1,334)	$	—	$	(6,267)
Other comprehensive income before reclassifications	—		3,594		23		3,617
Amounts reclassified from accumulated other comprehensive income/(loss)	198		(1,144)		(33)		(979)
Net prior-period other comprehensive income/(loss)	198		2,450		(10)		2,638
As of September 30, 2020	$	(4,735)	$	1,116	$	(10)	$	(3,629)

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The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and nine months ended September 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				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19	$	19	$	57	$	57
Net loss(1)	(106)		(108)		(317)		(323)
Total before income taxes	(87)		(89)		(260)		(266)
Income tax benefit	23		23		68		68
Net of tax	$	(64)	$	(66)	$	(192)	$	(198)
Gains on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	681	$	116	$	4,183	$	1,581
Income tax expense	(188)		(32)		(1,156)		(437)
Net of tax	$	493	$	84	$	3,027	$	1,144
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements	$	24	$	34	$	50	$	45
Income tax expense	(6)		(9)		(13)		(12)
Net of tax	$	18	$	25	$	37	$	33
Total reclassifications for the period	$	447	$	43	$	2,872	$	979

(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 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 nine months ended September 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 September 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 Nine Months Ended September 30,	2021		2020		2021		2020		2021		2020		2021		2020		2021		2020
(in thousands)
Interest cost	$	102	$	138	$	1,287	$	1,554	$	36	$	48	$	18	$	24	$	18	$	30
Expected return on plan assets	(120)		(126)		(2,490)		(2,235)		—		—		—		—		—		—
Amortization of prior service credit	—		—		—		—		—		—		(57)		(57)		—		—
Amortization of net (gain) loss	180		195		465		405		21		15		30		36		(6)		—
Net periodic cost (benefit)	162		207		(738)		(276)		57		63		(9)		3		12		30
Amortization of pre-merger regulatory asset	—		—		—		—		—		—		—		—		—		6
Total periodic cost (benefit)	$	162	$	207	$	(738)	$	(276)	$	57	$	63	$	(9)	$	3	$	12	$	36

In 2019, we began executing a de-risking strategy for the Chesapeake Pension Plan. In line with this strategy, we have decided to fully terminate the Chesapeake Pension Plan, which we expect to be complete in the fourth quarter of 2021 and will recognize the necessary expense associated with the termination of the Chesapeake Pension Plan at that time.

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 their respective regulatory orders, FPU and Chesapeake Utilities continue to record, as a regulatory asset, a portion of their unrecognized postretirement benefit costs related to their regulated operations. 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 income.

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

For the Three Months Ended September 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 (income)/loss (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 September 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 (income)/loss (1)	65		26		5		(7)		—		89
Recognized from regulatory asset	—		109		—		—		—		109
Total	$	65	$	135	$	5	$	(7)	$	—	$	198

For the Nine Months Ended September 30, 2021	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(57)	$	—	$	(57)
Net loss	180		465		21		30		(6)		690
Total recognized in net periodic benefit cost	180		465		21		(27)		(6)		633
Recognized from accumulated other comprehensive (income)/loss (1)	180		87		21		(27)		(1)		260
Recognized from regulatory asset	—		378		—		—		(5)		373
Total	$	180	$	465	$	21	$	(27)	$	(6)	$	633

For the Nine Months Ended September 30, 2020	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan		FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(57)	$	—	$	(57)
Net loss	195		405		15		36		—		651
Total recognized in net periodic benefit cost	195		405		15		(21)		—		594
Recognized from accumulated other comprehensive (income)/loss (1)	195		78		15		(21)		—		267
Recognized from regulatory asset	—		327		—		—		—		327
Total	$	195	$	405	$	15	$	(21)	$	—	$	594

    

(1) See Note 9, Stockholders' Equity.

During the three and nine months ended September 30, 2021, we contributed approximately $0.2 million and $0.3 million, respectively to the Chesapeake Pension Plan and approximately $0.5 million and $1.3 million, respectively, to the FPU Pension Plan. We expect to contribute approximately $2.1 million to the FPU Pension Plan during 2021, which represents the minimum annual contribution payments required. We will make all required contributions to the Chesapeake Pension Plan so that it can be terminated before the end of the year.

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 nine months ended September 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 nine ended September 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 nine months ended September 30, 2021, were $0.1 million. 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 September 30, 2021 and December 31, 2020, consisted of the following:

(in thousands)	September 30, 2021		December 31, 2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)	$	11,467	$	10,755
Investments in equity securities	23		21
Total	$	11,490	$	10,776

We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2021 and 2020, we recorded an immaterial net unrealized loss and a net unrealized gain of $0.6 million, respectively, in other income, net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2021 and 2020, we recorded net unrealized gains of approximately $1.0 million and $0.4 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 nine months ended September 30, 2021 and 2020:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2021		2020		2021		2020
(in thousands)
Awards to non-employee directors	$	201	$	188	$	581	$	545
Awards to key employees	1,105		1,144		4,039		3,109
Total compensation expense	1,306		1,332		4,620		3,654
Less: tax benefit	(339)		(348)		(1,200)		(955)
Share-based compensation amounts included in net income	$	967	$	984	$	3,420	$	2,699

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 September 30, 2021, there was approximately $0.5 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.

22

On October 15, 2021, a newly appointed member of the Board of Directors received a pro-rated retainer of 342 shares of common stock under the SICP to serve as a non-employee director through the 2022 Annual Meeting of Stockholders. The shares awarded to the non-employee director immediately vested upon issuance in October 2021, had a weighted average fair value of $129.09 per share, and will be expensed over the remaining service period ending on the date of the 2022 Annual Meeting of Stockholders.

Key Employees

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

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2020	186,878	$	87.06
Granted	68,562	$	102.73
Vested	(53,147)	$	76.31
Expired	(852)	$	74.85
Forfeited	(5,384)	$	93.39
Outstanding—September 30, 2021	196,057	$	94.15

During the nine months ended September 30, 2021, we granted awards of 68,562 shares of common stock to key employees under the SICP, including awards granted in February 2021 and to key employees appointed in officer positions. The shares granted are multi-year awards that will vest no later than 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 are comprised of 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 September 30, 2021, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $23.5 million. At September 30, 2021, there was approximately $5.6 million of unrecognized compensation cost related to these awards, which will be recognized through 2023.

Stock Options

There were no stock options outstanding or issued during the nine months ended September 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 September 30, 2021, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

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Volume of Derivative Activity

As of September 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	23.4	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 September 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 $6.2 million from accumulated other comprehensive income to earnings during the next 12-month period ended September 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 two $30.0 million interest rate swaps with a total notional amount of $60.0 million through September and December 2021 with pricing of 0.205 and 0.20 percent, respectively, 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 September 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 as follows:

(in thousands)	Balance Sheet Location	September 30, 2021		December 31, 2020
Sharp	Other Accrued Liabilities	$	6,094	$	1,505

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

	Derivative Assets
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 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	12,185		3,255
Total asset derivatives		$	12,185	$	3,269

	Derivative Liabilities
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 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	1,954		64
Interest rate swap agreements	Derivative liabilities, at fair value	15		40
Total liability derivatives		$	1,969	$	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 September 30,				For the Nine Months Ended September 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	681		116		4,183		1,581
Propane swap agreements	Other comprehensive income	2,491		1,022		7,039		3,385
Interest rate swap agreements	Interest expense	24		34		50		45
Interest rate swap agreements	Other comprehensive income (loss)	19		37		24		(14)
Total		$	3,215	$	1,209	$	11,272	$	4,997

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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 September 30, 2021 and December 31, 2020:

			Fair Value Measurements Using:
As of September 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	$	23	$	23	$	—	$	—
Investments—guaranteed income fund	2,016		—		—		2,016
Investments—mutual funds and other	9,451		9,451		—		—
Total investments	11,490		9,474		—		2,016
Derivative assets	12,185		—		12,185		—
Total assets	$	23,675	$	9,474	$	12,185	$	2,016
Liabilities:
Derivative liabilities	$	1,969	$	—	$	1,969	$	—

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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 nine months ended September 30, 2021 and 2020:

	Nine months ended September 30,
	2021		2020
(in thousands)
Beginning Balance	$	2,156	$	803
Purchases and adjustments	77		243
Transfers	—		1,579
Distribution	(241)		(514)
Investment income	24		18
Ending Balance	$	2,016	$	2,129

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

At September 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 September 30, 2021, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $522.5 million, compared to the estimated fair value of $561.9 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: 

	September 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
Equipment security note
2.46% note, due September 29, 2031	9,590		—
Less: debt issuance costs	(825)		(901)
Total long-term debt	521,665		522,099
Less: current maturities	(16,206)		(13,600)
Total long-term debt, net of current maturities	$	505,459	$	508,499

    

Notes Purchase Agreement

On August 25, 2021, we entered into a Note Purchase Agreement (“Note Agreement”) with multiple lenders to issue $50.0 million in uncollateralized senior notes. Under the Note Agreement, we will issue the senior notes on January 25, 2022 at a rate of 2.49 percent for a 15-year term. These senior notes, when issued, will have similar covenants and default provisions as the existing senior notes, and will have an annual principal payment beginning in the sixth year after the issuance. The proceeds received from the issuances of the senior notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.

Equipment Security Note

On September 24, 2021, we entered into an Equipment Financing Agreement with Banc of America Leasing & Capital, LLC to issue $9.6 million in sustainable financing to finance the purchase of equipment by our subsidiary, Marlin Gas Services. The equipment security note bears a 2.46 percent interest rate and has a term of ten years. Under the terms of the agreement, we granted a security interest in the equipment to the lender, to serve as collateral.

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 September 30, 2021:

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(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 September 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 September 30, 2021 and December 31, 2020, we had $192.0 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 0.82 percent and 1.28 percent. Included in the September 30, 2021 balance, is $70.0 million in short-term debt for which we have entered into interest rate swap agreements.

In August 2021, we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the facility consist of a $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three (3) one-year extension options, which can be authorized by our Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the facility and to the extent that an individual loan under the revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 September 30, 2021, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026 both are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of 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 a total indebtedness to total capitalization ratio. As of September 30, 2021, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of September 30, 2021, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

Our total available credit under the Revolver at September 30, 2021 was $203.4 million. As of September 30, 2021, we had issued $4.6 million in letters of credit to various counterparties under the syndicated Revolvers. 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 two $30.0 million interest rate swaps with a notional amount of $60.0 million through September and December 2021 at a pricing of 0.205 and 0.20 percent, respectively. 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.

17.    Leases

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    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 September 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 September 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				Nine Months Ended
		September 30,				September 30,
( in thousands)	Classification	2021		2020		2021		2020
Operating lease cost (1)	Operations expense	$	515	$	627	$	1,553	$	1,882

(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 September 30, 2021 and December 31, 2020:

(in thousands)	Balance sheet classification	September 30, 2021		December 31, 2020
Assets
Operating lease assets	Operating lease right-of-use assets	$	9,602	$	11,194
Liabilities
Current
Operating lease liabilities	Other accrued liabilities	$	1,725	$	1,747
Noncurrent
Operating lease liabilities	Operating lease - liabilities	8,380		9,872
Total lease liabilities		$	10,105	$	11,619

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

	September 30, 2021		December 31, 2020
Weighted-average remaining lease term (in years)
Operating leases	8.54		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 September 30, 2021 and 2020:

	Nine Months Ended
	September 30,
(in thousands)	2021		2020
Operating cash flows from operating leases	$	1,399	$	1,435

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

(in thousands)	Operating  Leases (1)
Remainder of 2021	$	597
2022	1,845
2023	1,762
2024	1,607
2025	1,387
2026	951
Thereafter	3,596
Total lease payments	$	11,745
Less: Interest	(1,640)
Present value of lease liabilities	$	10,105

    (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 Nine Months Ended September 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 U.S. Centers for Disease Control and Prevention ("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 have continued throughout 2021. We are considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the safety procedures intended to limit the spread of the virus. At this time, restrictions continue to be lifted as vaccines have become widely 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. The expiration of the states of emergency in our service territories has concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process. 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, and the Occupational Safety and Health Administration, in order to protect our employees, customers and the communities we serve.

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 which will include, but not be limited to, several of the areas described below.

Advancing Environmental Initiatives

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 to replace 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 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 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 extension from Eastern Shore's Del-Mar Energy Pathway Project, which was recently completed, brings natural gas to our distribution system in Somerset County, Maryland for the first time. As part of this project, our services enable 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.

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. In October 2021, we completed construction of the Noble Road Landfill Renewable Natural Gas pipeline project. This is our first RNG transportation project and, when combined with our previously announced projects, will expand our ability to utilize RNG in our services territories. 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 utilize sustainable financing capacity at attractive pricing. Just recently, we secured $9.6 million in sustainability linked financing from Bank of America to fund capital investments in energy delivery solutions provided by our subsidiary, Marlin Gas Services.

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. During the third quarter, we were recognized as a Top Workplace in Delaware for the 10th consecutive year. This follows recognition as a Top Workplace nationally earlier in the year. These recognitions are a testament to our employees’ commitment to excellence.

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. During the third quarter, we were very excited to hire William Hughston as Vice President and Chief Human Resources Officer. Mr. Hughston brings tremendous EDI experience to the team, including drawing from his vast experience including his previous role as Chief Diversity Officer. Additionally, in October 2021, we announced the addition of our third female Director to our Board of Directors, Lisa Bisaccia. Ms. Bisaccia's addition continues our steady progress of gender and ethnic diversity that represents the communities we serve. Our Board of Directors includes, three 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. Thus far in 2021, four of our business units have been recognized with awards from the American Gas Association for their commitment to safety.

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.

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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 review 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 just this year were also recognized as Best for Corporate Governance Among North American Utilities by Ethical Boardroom magazine. To learn more about our corporate governance practices and transparency, stakeholder 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' news releases and historical quarterly earnings conference calls for additional discussions on ESG and our sustainability practices.

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Operational Highlights

Our net income for the three months ended September 30, 2021 was $12.5 million, or $0.71 per share, compared to $9.3 million, or $0.56 per share, for the same quarter of 2020. Operating income for the three months ended September 30, 2021 increased by $2.7 million, or 15.6 percent, over the same period in 2020. During the third quarter of 2020, we settled the Hurricane Michael limited proceeding which resulted in $1.9 million in operating income being recognized that related to the first and second quarters of 2020. Excluding the absence of this timing difference, operating income increased $4.6 million compared to the third quarter of 2020. Higher performance in the third quarter of 2021 was generated from continued pipeline expansion projects, contributions from the 2020 acquisitions of Elkton Gas and Western Natural Gas, higher margins from consumption returning toward pre-pandemic levels, natural gas distribution growth, increased propane margins, and margin growth from increased investment in the Florida GRIP program. We recorded 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 expenses. These expense increases were largely offset by $3.0 million of lower pandemic related costs and the establishment of regulatory assets for COVID-19 expenses.

	Three Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands except per share)
Gross Margin
Regulated Energy segment	$	65,102	$	66,491	$	(1,389)
Unregulated Energy segment	14,897		13,068		1,829
Other businesses and eliminations	(28)		(51)		23
Total Gross Margin	$	79,971	$	79,508	$	463
Operating Income
Regulated Energy segment	$	23,538	$	20,482	$	3,056
Unregulated Energy segment	(2,883)		(3,092)		209
Other businesses and eliminations	(542)		16		(558)
Total Operating Income	20,113		17,406		2,707
Other income (expense), net	339		(40)		379
Interest charges	4,975		4,584		391
Income from Continuing Operations Before Income Taxes	15,477		12,782		2,695
Income Taxes on Continuing Operations	2,993		3,502		(509)
Income from Continuing operations	12,484		9,280		3,204
Income (Loss) from Discontinued Operations, net of tax	(9)		(19)		10
Net Income	$	12,475	$	9,261	$	3,214
Basic Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	0.71	$	0.56	$	0.15
Earnings from Discontinued Operations	—		—		—
Basic Earnings Per Share of Common Stock	$	0.71	$	0.56	$	0.15
Diluted Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	0.71	$	0.56	$	0.15
Earnings from Discontinued Operations	—		—		—
Diluted Earnings Per Share of Common Stock	$	0.71	$	0.56	$	0.15

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

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Third Quarter of 2020 Reported Results from Continuing Operations	$	12,782	$	9,280	$	0.56
Adjusting for Unusual Items:
Absence of timing of Hurricane Michael Settlement (first and second quarter 2020 impacts recorded in the third quarter of 2020)	(1,933)		(1,444)		(0.08)
Regulatory deferral of COVID-19 expenses per PSCs orders	2,437		1,821		0.10
Favorable income tax impact associated the CARES Act recognized during the third quarter of 2021	—		922		0.05
	504		1,299		0.07
Increased (Decreased) Gross Margins:
Increased retail propane margins and fees	994		743		0.04
Margin contributions from 2020 and 2021 acquisitions*	855		638		0.04
Eastern Shore and Peninsula Pipeline service expansions*	795		594		0.03
Improved margin from electric operations	653		488		0.03
Natural gas growth (excluding service expansions)	620		463		0.03
Increased customer consumption - primarily due to a return toward pre-pandemic conditions	536		400		0.02
Florida GRIP*	475		355		0.02
	4,928		3,681		0.21
(Increased) Decreased Operating Expenses (Excluding Cost of Sales):
Depreciation, amortization and property tax costs due to new capital investments	(1,715)		(1,281)		(0.07)
Payroll, benefits and other employee-related expenses	(1,317)		(984)		(0.06)
Operating expenses for Elkton Gas and Western Natural Gas acquisitions	(531)		(397)		(0.02)
Net reduction in expenses associated with the COVID-19 pandemic	608		454		0.03
	(2,955)		(2,208)		(0.12)
Other income tax effects	—		269		0.02
Net other changes	218		163		—
Change in shares outstanding due to 2020 and 2021 equity offerings	—		—		(0.03)
	218		432		(0.01)
Third Quarter of 2021 Reported Results from Continuing Operations	$	15,477	$	12,484	$	0.71

*See the Major Projects and Initiatives table.

Our net income for the nine months ended September 30, 2021 was $60.8 million, or $3.45 per share, compared to $49.1 million, or $2.97 per share, for the same period of 2020. Operating income for the nine months ended September 30, 2021 increased by $16.8 million, or 21.6 percent, over the same period in 2020. The growth in 2021 reflects increased consumption driven primarily by colder weather compared to the same period of 2020, expansion projects and acquisitions completed in 2020. Further contributing to the improved performance in the first nine months of 2021 was organic growth, consumption returning to pre-pandemic levels, increased propane margins, increased margins from investment in the Florida GRIP program, and the impact of the Hurricane Michael regulatory proceeding settlement. These 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 toward pre-pandemic operating levels, including payroll, benefits and other employee-related expenses and outside services costs. The operating expense increases were partially offset by $2.3 million decrease in pandemic related costs compared to 2020 and the establishment of regulatory assets for COVID-19 expenses as approved by the PSCs.

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	Nine Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands except per share)
Gross Margin
Regulated Energy segment	$	209,718	$	191,745	$	17,973
Unregulated Energy segment	71,625		61,883		9,742
Other businesses and eliminations	(102)		(210)		108
Total Gross Margin	$	281,241	$	253,418	$	27,823
Operating Income
Regulated Energy segment	$	79,210	$	66,376	$	12,834
Unregulated Energy segment	15,777		11,050		4,727
Other businesses and eliminations	(699)		92		(791)
Total Operating Income	94,288		77,518		16,770
Other income, net	2,180		2,997		(817)
Interest charges	15,134		15,452		(318)
Income from Continuing Operations Before Income Taxes	81,334		65,063		16,271
Income Taxes on Continuing Operations	20,563		16,082		4,481
Income from Continuing operations	60,771		48,981		11,790
Income (Loss) from Discontinued Operations	(17)		165		(182)
Net Income	$	60,754	$	49,146	$	11,608
Basic Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	3.46	$	2.97	$	0.49
Earnings from Discontinued Operations	—		0.01		(0.01)
Basic Earnings Per Share of Common Stock	$	3.46	$	2.98	$	0.48
Diluted Earnings Per Share of Common Stock
Earnings from Continuing Operations	$	3.45	$	2.96	$	0.49
Earnings from Discontinued Operations	—		0.01		(0.01)
Diluted Earnings Per Share of Common Stock	$	3.45	$	2.97	$	0.48

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

(in thousands, except per share data)	Pre-tax Income		Net Income		Earnings Per Share
Nine Months Ended September 30, 2020 Reported Results from Continuing Operations	$	65,063	$	48,981	$	2.96
Adjusting for Unusual Items:
Regulatory deferral of COVID-19 expenses per PSCs orders	3,312		2,437		0.14
Gains from sales of assets	(1,563)		(1,150)		(0.07)
Net impact of CARES Act items recognized during the second quarter of 2020 and third quarter of 2021	—		(748)		(0.06)
	1,749		539		0.01
Increased (Decreased) Gross Margins:
Increased customer consumption - primarily weather related	6,485		4,772		0.27
Eastern Shore and Peninsula Pipeline service expansions*	6,037		4,442		0.25
Margin contributions from 2020 and 2021 acquisitions*	3,936		2,896		0.16
Increased propane margins and fees	2,712		1,995		0.11
Increased customer consumption - primarily due to a return toward pre-pandemic conditions	2,280		1,677		0.10
Natural gas growth (excluding service expansions)	2,237		1,646		0.09
Florida GRIP*	1,408		1,036		0.06
Improved margin from electric operations	931		685		0.04
Aspire Energy improved margin including natural gas liquid processing	897		660		0.04
Sandpiper infrastructure rider associated with conversions	624		459		0.04
	27,547		20,268		1.16
(Increased) Decreased Operating Expenses (Excluding Cost of Sales):
Depreciation, amortization and property tax costs due to new capital investments	(5,802)		(4,269)		(0.24)
Payroll, benefits and other employee-related expenses due to growth	(4,679)		(3,443)		(0.20)
Operating expenses for Elkton Gas and Western Natural Gas acquisitions	(2,499)		(1,839)		(0.10)
Net increase in operating expenses associated with a return toward pre-pandemic conditions	(969)		(713)		(0.04)
Insurance expense (non-health)	(420)		(309)		(0.02)
	(14,369)		(10,573)		(0.60)
Other income tax effects	—		554		0.03
Net other changes	1,344		1,002		0.07
Change in shares outstanding due to 2020 and 2021 equity offerings	—		—		(0.18)
	1,344		1,556		(0.08)
Nine Months Ended September 30, 2021 Reported Results from Continuing Operations	$	81,334	$	60,771	$	3.45

*See the Major Projects and Initiatives table.

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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				Nine Months Ended				Year Ended		Estimate for
	September 30,				September 30,				December 31,		Fiscal
in thousands	2021		2020		2021		2020		2020		2021		2022
Pipeline Expansions:
Western Palm Beach County, Florida Expansion (1)	$	1,175	$	1,020	$	3,515	$	2,988	$	4,167	$	4,811	$	5,227
Del-Mar Energy Pathway (1) (2)	1,049		924		2,854		1,565		2,462		4,578		6,708
Callahan Intrastate Pipeline (2) (3)	1,893		1,378		5,673		1,452		2,926		7,564		7,564
Guernsey Power Station	47		—		141		—		—		404		1,486
Winter Haven Expansion	—		—		—		—		—		—		658
Beachside Pipeline Expansion	—		—		—		—		—		—		—
Total Pipeline Expansions	4,164		3,322		12,183		6,005		9,555		17,357		21,643
CNG Transportation	1,598		1,592		5,383		5,047		7,231		7,300		8,500
RNG Transportation	—		—		—		—		—		86		1,000
Acquisitions:
Elkton Gas	590		357		2,648		357		1,344		3,900		4,113
Western Natural Gas	372		—		1,312		—		389		2,066		2,251
Escambia Meter Station	250		—		333		—		—		583		1,000
Total Acquisitions	1,212		357		4,293		357		1,733		6,549		7,364
Regulatory Initiatives:
Florida GRIP	4,306		3,831		12,543		11,135		15,178		16,950		18,797
Hurricane Michael Regulatory Proceeding	3,264		8,261		8,984		8,261		10,864		11,014		11,014
Capital Cost Surcharge Programs	433		129		690		389		523		1,186		1,985
Elkton STRIDE Plan	—		—		—		—		—		45		299
Total Regulatory Initiatives	8,003		12,221		22,217		19,785		26,565		29,195		32,095
Total	$	14,977	$	17,492	$	44,076	$	31,194	$	45,084	$	60,487	$	70,602

(1) Includes gross margin generated from interim services.

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

(3) Prior quarter amounts have been revised to conform to the current period presentation.

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 $0.5 million for the three and nine months ended September 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 recently completed this project. The new facilities: (i) ensure an additional 14,300 Dekatherms per day ("Dts/d") of firm service to four customers, (ii) provide additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (iii) represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Construction of the project began in January 2020. Including interim services, this project generated additional gross margin of $0.1 million and $1.3 million for the three and nine months ended September 30, 2021, respectively. The estimated annual gross margin from this project, including initial natural gas distribution service in Somerset County, Maryland, is approximately $4.6 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 nine months ended September 30, 2021, the project generated $0.5 million and $4.2 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 nine months ended September 30, 2021, we recognized approximately $0.1 million, slightly lower than originally estimated as a result of a construction delay in the project. The project is expected to be in service in the fourth quarter of 2021, and produce gross margin of approximately $0.4 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 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 $0.7 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. Marlin Gas Services generated additional gross margin of $0.3 million on a year-to-date basis. We estimate that Marlin Gas Services will generate annual gross margin of approximately $7.3 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

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advanced, patented technology to treat landfill gas by removing carbon dioxide and other components to purify the gas and produce pipeline quality RNG. In October 2021, we announced that Aspire Energy had completed construction of its Noble Road Landfill RNG pipeline project, a 33.1-mile pipeline, which will transport RNG generated from the landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In conjunction with this expansion, Aspire Energy also upgraded an existing compressor station and installed two new metering and regulation sites. 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 $0.1 million in 2021 in incremental margin from these RNG transportation projects . 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 nine months ended September 30, 2021, we generated $0.2 million and $2.3 million, respectively, in additional gross margin from Elkton Gas and estimate that this acquisition will generate gross margin of approximately $3.9 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 $1.3 million in additional gross margin for the three and nine months ended September 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 grow to $2.3 million of gross margin in 2022, with additional opportunities for growth in the future.

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 $0.3 million in additional gross margin in the third quarter of 2021 and we estimate that this acquisition will generate gross margin of approximately $0.6 million in 2021 and grow to $1.0 million of gross margin in 2022.

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Regulatory Initiatives

Florida GRIP

Florida GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic recovery, through rates, of costs associated with the replacement of mains and services. Since the program's inception in August 2012, we have invested $183.6 million of capital expenditures to replace 337 miles of qualifying distribution mains, including $17.7 million of new pipes during the first nine months of 2021. We expect to generate annual gross margin of approximately $17.0 million in 2021, and $18.8 million in 2022.

Hurricane Michael

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 the Hurricane Michael regulatory proceeding for the three and nine months ended September 30, 2021:

	For the Three Months Ended September 30,				For the Nine Months Ended September 30,
(in thousands)	2021		2020 (1)		2021		2020
Gross Margin	$	3,264	$	8,261	$	8,984	$	8,261
Depreciation	(305)		(883)		(913)		(883)
Amortization of regulatory assets	2,079		6,238		6,237		6,238
Operating income	1,490		2,906		3,660		2,906
Amortization of liability associated with interest expense	(293)		(1,132)		(930)		(1,132)
Pre-tax income	1,783		4,038		4,590		4,038
Income tax expense	451		1,106		1,213		1,106
Net income	$	1,332	$	2,932	$	3,377	$	2,932

(1) Amounts reflected for the quarter ended September 30, 2020 include the cumulative effect of the Hurricane Michael settlement dating back to January 1, 2020.

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

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In March 2021, Elkton Gas filed a 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 the Maryland Office of the Peoples Counsel. The STRIDE plan is expected to go into service in the fourth quarter of 2021 and is expected to generate $0.3 million of additional gross margin 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. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allowed 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 third quarter. For the nine-month period, weather conditions accounted for $6.5 million of increased gross margin compared to the same period in 2020, primarily due to a 7.2 percent increase in HDDs and a return to pre-pandemic conditions that resulted in increased customer consumption. Assuming normal temperatures, as detailed below, gross margin would have been higher by $1.3 million. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 2021 and 2020.

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2021	2020	Variance	2021	2020	Variance
Delmarva Peninsula
Actual HDD	9	43	(34)	2,595	2,416	179
10-Year Average HDD ("Normal")	47	48	(1)	2,736	2,797	(61)
Variance from Normal	(38)	(5)		(141)	(381)
Florida
Actual HDD	1	2	(1)	573	412	161
10-Year Average HDD ("Normal")	1	—	1	550	613	(63)
Variance from Normal	—	2		23	(201)
Ohio
Actual HDD	41	86	(45)	3,489	3,383	106
10-Year Average HDD ("Normal")	78	79	(1)	3,660	3,691	(31)
Variance from Normal	(37)	7		(171)	(308)
Florida
Actual CDD	1,330	1,365	(35)	2,340	2,637	(297)
10-Year Average CDD ("Normal")	1,402	1,416	(14)	2,563	2,559	4
Variance from Normal	(72)	(51)		(223)	78

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 $0.6 million and $2.2 million of additional margin for the three and nine months ended September 30, 2021, respectively. The average number of residential customers served on the

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Delmarva Peninsula increased by 4.0 percent and 4.1 percent for the three and nine months ended September 30, 2021, while Florida customers increased by and 4.7 percent and 5.0 percent, for the three and nine months ended September 30, 2021, respectively. A larger 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 our distribution infrastructure continues to build out. We anticipate continued customer growth, as new communities continue to build out due to population growth, additional infrastructure is added to support the growth. The details for the three and nine months ended September 30, 2021 are provided in the following table:

	Three Months Ended				Nine Months Ended
	September 30, 2021				September 30, 2021
(in thousands)	Delmarva Peninsula		Florida		Delmarva Peninsula		Florida
Customer Growth:
Residential	$	226	$	208	$	1,049	$	788
Commercial and industrial	84		102		183		217
Total Customer Growth	$	310	$	310	$	1,232	$	1,005

Regulated Energy Segment

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

	Three Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	80,396	$	82,762	$	(2,366)
Cost of sales	15,294		16,271		(977)
Gross margin	65,102		66,491		(1,389)
Operations & maintenance	24,477		26,364		(1,887)
Depreciation & amortization	12,296		15,314		(3,018)
Other taxes	4,791		4,331		460
Total operating expenses	41,564		46,009		(4,445)
Operating income	$	23,538	$	20,482	$	3,056

Operating income for the Regulated Energy segment for the third quarter of 2021 was $23.5 million, an increase of $3.1 million, or 14.9 percent, over the same period in 2020. During the third quarter of 2020, we settled the Hurricane Michael limited proceeding, which resulted in $1.9 million in operating income being recognized that related to the first and second quarters of 2020. Excluding this timing difference, operating income increased $5.0 million compared to the third quarter of 2020. Higher operating income reflects continued pipeline expansions by Eastern Shore and Peninsula Pipeline, increased consumption from a return toward pre-pandemic consumption levels, organic growth in our natural gas distribution businesses, and operating results from the Elkton Gas and Escambia Meter Station acquisitions completed in 2020 and 2021, as well as lower expenses. Operating expenses decreased by $3.0 million compared to the prior year quarter due to a lower level of overall pandemic related costs compared to 2020 and the establishment of regulatory assets for COVID-19 expenses as authorized by the PSCs.

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

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(in thousands)
Margin impact from the Hurricane Michael regulatory proceeding settlement (includes the absence of first and second quarter 2020 impact recorded in the third quarter of 2020)	$	(5,507)
Eastern Shore and Peninsula Pipeline service expansions	795
Improved margin from electric operations	653
Natural gas growth (excluding service expansions)	620
Margin contribution from 2020 and 2021 acquisitions	483
Florida GRIP	475
Increased customer consumption - primarily due to a return toward pre-pandemic conditions	314
Eastern Shore capital surcharge	304
Other variances	474
Quarter-over-quarter decrease in gross margin	$	(1,389)

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

Margin Impact from Hurricane Michael Regulatory Proceeding Settlement

We saw a decrease in gross margin of $5.5 million as a result of the settlement of the Hurricane Michael regulatory proceeding which included the absence of interim rates from the first and second quarter of 2020 that were first reflected in the third quarter of 2020. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.

Eastern Shore and Peninsula Pipeline Service Expansions

We generated additional gross margin of $0.7 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $0.1 million from Eastern Shore's Del-Mar Energy Pathway project.

Improved Margin from Electric Operations

Our electric operations generated additional gross margin of $0.7 million due to increased consumption and growth.

Natural Gas Distribution Customer Growth

We generated additional gross margin of $0.6 million from natural gas customer growth. Gross margin increased by $0.3 million in Florida and $0.3 million on the Delmarva Peninsula for the three months ended September 30, 2021, as compared to the same period in 2020, due primarily to residential customer growth of 4.0 percent and 4.7 percent on the Delmarva Peninsula and in Florida, respectively.

Acquisitions

Gross margin increased by $0.5 million due to margin contributed from Elkton Gas and the Escambia Meter Station which were completed in July 2020 and June 2021, respectively.

Florida GRIP

Continued investment in the Florida GRIP generated additional gross margin of $0.5 million in third quarter of 2021 compared to the same period in 2020.

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

The absence of unfavorable COVID-19 impacts, resulted in a return towards pre-pandemic consumption, positively impacting gross margin by $0.3 million for the three months ended September 30, 2021 compared to the same period in 2020.

Eastern Shore Capital Surcharge

Eastern Shore's capital surcharge resulted in $0.3 million of additional margin for the three months ended September 30, 2021. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.

Operating Expenses

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

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(in thousands)
Absence of Hurricane Michael Depreciation and Amortization cumulative adjustment (first and second quarter 2020)	$	(3,574)
Regulatory deferral of COVID-19 expenses per PSCs orders	(2,437)
Net reduction in expenses associated with the COVID-19 pandemic	(546)
Depreciation, asset removal and property tax costs due to new capital investments	1,181
Payroll, benefits and other employee-related expenses due to growth	612
Operating expenses from the Elkton Gas acquisition	204
Other variances	115
Quarter-over-quarter decrease in operating expenses	$	(4,445)

For the Nine Months Ended September 30, 2021, compared to the nine months ended September 30, 2020:

	Nine Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	282,503	$	259,235	$	23,268
Cost of sales	72,785		67,490		5,295
Gross margin	209,718		191,745		17,973
Operations & maintenance	79,363		78,062		1,301
Depreciation & amortization	36,156		33,979		2,177
Other taxes	14,989		13,328		1,661
Total operating expenses	130,508		125,369		5,139
Operating income	$	79,210	$	66,376	$	12,834

Operating income for the Regulated Energy segment for the first nine months of 2021 was $79.2 million, an increase of $12.8 million, or 19.3 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 and Escambia Meter Station acquisitions completed in 2020 and 2021, and increased consumption from a return toward pre-pandemic consumption levels. Further contributing to the operating income growth was margin from organic growth in our natural gas distribution businesses and increased consumption driven primarily by colder weather compared to the same period of 2020. These 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, expenses associated with Elkton Gas, and higher other operating expenses. The operating expense increases were partially offset by $2.5 million associated with a reduction in pandemic related costs compared to 2020 and the establishment of regulatory assets for COVID-19 expenses as approved by the PSCs.

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

(in thousands)
Eastern Shore and Peninsula Pipeline service expansions	$	6,037
Margin contribution from 2020 and 2021 acquisitions	2,624
Natural gas growth (excluding service expansions)	2,237
Increased customer consumption - primarily due to a return toward pre-pandemic conditions	2,112
Increased customer consumption - primarily weather related	1,510
Florida GRIP	1,408
Improved margin from electric operations	931
Sandpiper Energy infrastructure rider associated with conversions	624
Other variances	490
Period-over-period increase in gross margin	$	17,973

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

Eastern Shore and Peninsula Pipeline Service Expansions

We generated additional gross margin of $4.7 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $1.3 million from Eastern Shore's Del-Mar Energy Pathway project.

Acquisitions

Gross margin increased by $2.6 million due to margin contributed from Elkton Gas and the Escambia Meter Station which were completed in July 2020 and June 2021, respectively.

Natural Gas Distribution Customer Growth

We generated additional gross margin of $2.2 million from natural gas customer growth. Gross margin increased by $1.0 million in Florida and $1.2 million on the Delmarva Peninsula for the nine months ended September 30, 2021, as compared to the same period in 2020, due primarily to residential customer growth of 4.1 percent and 5.0 percent on the Delmarva Peninsula and in Florida, respectively.

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

The absence of unfavorable COVID-19 impacts during the first nine months of 2021, resulted in a return to pre-pandemic consumption, positively impacting gross margin by $2.1 million compared to the same period in 2020.

Increased Customer Consumption - primarily weather related

Gross margin increased by $1.5 million for the for the nine months ended September 30, 2021, compared to the same period in 2020, primarily due to a 7 percent increase in HDDs on the Delmarva Peninsula and a 39 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 $1.4 million for the nine months ended September 30, 2021 compared to the same period in 2020.

Improved Margin from Electric Operations

Our electric operations generated additional gross margin of $0.9 million due to increased consumption and growth.

Sandpiper Energy Infrastructure Rider Associated with Conversions

We generated additional margin of $0.6 million associated with the conversion of Sandpiper Energy''s propane customers to natural gas customers for the nine months ended September 30, 2021 compared to the same period in 2020.

Operating Expenses

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

(in thousands)
Depreciation, asset removal and property tax costs due to new capital investments	$	4,563
Payroll, benefits and other employee-related expenses due to growth	2,601
Operating expenses from the Elkton Gas acquisition	1,238
Net increase in operating expenses associated with a return toward pre-pandemic conditions	853
Regulatory deferral of COVID-19 expenses per PSCs orders	(3,312)
Other variances	(804)
Period-over-period increase in operating expenses	$	5,139

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Unregulated Energy Segment

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

	Three Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	32,110	$	22,714	$	9,396
Cost of sales	17,213		9,646		7,567
Gross margin	14,897		13,068		1,829
Operations & maintenance	13,382		12,412		970
Depreciation & amortization	3,491		2,968		523
Other taxes	907		780		127
Total operating expenses	17,780		16,160		1,620
Operating loss	$	(2,883)	$	(3,092)	$	209

Operating results for the Unregulated Energy segment for the third quarter of 2021 increased by $0.2 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 third quarter are not indicative of the results for the entire year.

Higher operating results during the third quarter were driven by increased propane margins, contributions from the acquisition of Western Natural Gas and margin improvement from Aspire Energy as well as increased consumption in the propane businesses as volumes continue returning toward pre-pandemic levels. Increased operating results were partially offset by higher operating expenses, depreciation, amortization and property taxes related to recent capital investments, and expenses associated with Western Natural Gas.

Gross Margin

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

(in thousands)
Propane Operations
Increased retail propane margins and service fee	$	751
Western Natural Gas acquisition (completed in October 2020)	372
Increased wholesale propane margins	243
Increased customer consumption - primarily due to a return toward pre-pandemic conditions	222
Increased customer consumption - primarily weather related	122
Aspire Energy
Increased margin including improvements from natural gas liquid processing	320
Other variances	(201)
Quarter-over-quarter increase in gross margin	$	1,829

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

Propane Operations

•Increased Retail Propane Margins and Service Fee - Gross margin increased by $0.8 million for the three months ended September 30, 2021, due to lower propane inventory costs and favorable market conditions as well as resuming assessment of our customary service fees which had been suspended as a result of the COVID-19 pandemic during the same period in the prior year. These market conditions, which include market pricing and 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 $0.4 million due to the margin generated from Western Natural Gas,

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which was acquired by Sharp in October 2020.

•Increased Wholesale Propane Margins - Gross margin increased by $0.2 million during the third quarter of 2021 over the same period in 2020, due to lower propane inventory costs and favorable market conditions. These conditions tend to fluctuate based on changes in demand, supply and other energy commodity prices.

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

•Increased Customer Consumption - primarily weather related - Gross margin increase by $0.1 million due to growth and favorable pricing during the third quarter of 2021.

Aspire Energy

•Gross margin increased by $0.3 million during the third 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)
Depreciation, amortization and property tax costs due to new capital investments	$	595
Payroll, benefits and other employee-related expenses due to growth	427
Operating expenses from the Western Natural Gas acquisition	273
Net increase in operating expenses associated with a return toward pre-pandemic conditions	123
Other variances	202
Quarter-over-quarter increase in operating expenses	$	1,620

For the nine months ended September 30, 2021, compared to the nine months ended September 30, 2020:

	Nine Months Ended
	September 30,				Increase
	2021		2020		(decrease)
(in thousands)
Revenue	$	141,642	$	104,466	$	37,176
Cost of sales	70,017		42,583		27,434
Gross margin	71,625		61,883		9,742
Operations & maintenance	42,560		39,408		3,152
Depreciation & amortization	10,271		8,774		1,497
Other taxes	3,017		2,651		366
Total operating expenses	55,848		50,833		5,015
Operating income	$	15,777	$	11,050	$	4,727

Operating income for the Unregulated Energy segment for the nine months ended September 30, 2021 was $15.8 million, an increase of $4.7 million or 42.8 percent, over the same period in 2020. Higher operating income resulted from increased consumption driven primarily by colder weather compared to the same period in 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, increased payroll and benefits costs, new expenses associated with Western Natural Gas and higher other operating expenses.

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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	$	3,823
Increased retail propane margins and service fees	2,403
Western Natural Gas acquisition (completed in October 2020)	1,312
Increased wholesale propane margins per gallon	309
Marlin Gas Services
Increased demand for CNG services	337
Aspire Energy
Increased customer consumption - primarily weather related	1,152
Improved margin including natural gas liquid processing	897
Other variances	(491)
Period-over-period increase in gross margin	$	9,742

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 $3.8 million, as weather on the Delmarva Peninsula was 7 percent colder for the nine months ended September 30, 2021 compared to the same period in 2020.

•Increased Retail Propane Margins and Service Fees - Gross margin increased by $2.4 million, due to lower propane inventory costs and favorable market conditions as well as resuming the assessment of our customary service fees which had been suspended as a result of the COVID-19 pandemic during the same period in the prior year. 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 $1.3 million due to the margin generated from Western Natural Gas, which was acquired by Sharp in October 2020.

•Increased Wholesale Propane Margins - Gross margin increased by $0.3 million during the third quarter of 2021 over the same period in 2020, due to lower propane inventory costs and favorable market conditions. These conditions tend to fluctuate based on changes in demand, supply and other energy commodity prices.

Marlin Gas Services

•Gross margin increased by $0.3 million for the nine months ended September 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 $1.2 million due to higher consumption of gas as weather in Ohio was approximately 3 percent colder for the nine months ended September 30, 2021 over the same period in 2020.

•Improved Margin including natural gas liquid processing - Gross margin increased by $0.9 million, including improvements from natural gas liquid processing, for the nine months ended September 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	$	1,650
Payroll, benefits and other employee-related expenses due to growth	1,170
Operating expenses from the Western Natural Gas acquisition	880
Net increase in operating expenses associated with a return toward pre-pandemic conditions	406
Insurance expense (non-health)	404
Other variances	505
Period-over-period increase in operating expenses	$	5,015

OTHER EXPENSE, NET

For the quarter ended September 30, 2021 compared to the quarter ended September 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 $0.4 million in the third quarter of 2021, compared to the same period in 2020.

For the nine months ended September 30, 2021 compared to the nine months ended September 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 $0.8 million in the first nine 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.

INTEREST CHARGES

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

Interest charges for the three months ended September 30, 2021 increased by $0.4 million, compared to the same period in 2020, attributable primarily to a $0.8 million increase 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 increased charges was a decrease of $0.3 million in lower interest expense from lower levels of outstanding borrowings under our revolving credit facilities and the restructuring of our revolving credit facilities, and a decrease of $0.2 million in interest expense as a result of several long-term debt placements in 2020.

For the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020

Interest charges for the nine months ended September 30, 2021 decreased by $0.3 million, compared to the same period in 2020, attributable primarily to a decrease of $1.5 million in lower interest expense from lower levels of outstanding borrowings under our revolving credit facilities and the restructuring of our revolving credit facilities. Partially offsetting the interest savings was an increase of $0.6 million in interest expense as a result of several long-term debt placements in 2020, $0.4 million due to lower capitalized interest associated with growth projects, and $0.2 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.

INCOME TAXES

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

Income tax expense was $3.0 million for the quarter ended September 30, 2021, compared to $3.5 million for the quarter ended September 30, 2020. Our effective income tax rate was 19.3 percent and 27.4 percent, for the three months ended September 30, 2021 and 2020, respectively. During the third quarter 2021, we recognized a $0.9 million reduction in tax expense associated certain provisions of the CARES Act which allowed us to carryback net operating losses into prior year periods where the federal income tax rate was higher.. Excluding this impact of the CARES Act, our effective tax rate for the three months ended September 30, 2021 was 25.3 percent.

For the nine months ended September 30, 2021 compared to the nine months ended September 30, 2020

Income tax expense was $20.6 million for the nine months ended September 30, 2021, compared to $16.1 million for the nine months ended September 30, 2020. Our effective income tax rate was 25.3 percent and 24.7 percent, for the nine months ended September 30, 2021 and 2020, respectively.

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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 $151.4 million for the nine months ended September 30, 2021. In the table below, we have provided an updated range of our forecasted capital expenditures for 2021:

	2021
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	76,000	$	79,000
Natural gas transmission	58,000		63,000
Electric distribution	8,000		8,000
Total Regulated Energy	142,000		150,000
Unregulated Energy:
Propane distribution	11,000		12,000
Energy transmission	16,000		20,000
Other unregulated energy	13,000		15,000
Total Unregulated Energy	40,000		47,000
Other:
Corporate and other businesses	3,000		3,000
Total Other	3,000		3,000
Total 2021 Forecasted Capital Expenditures	$	185,000	$	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 September 30, 2021 and December 31, 2020:

	September 30, 2021				December 31, 2020
(in thousands)
Long-term debt, net of current maturities	$	505,459	40	%	$	508,499	42	%
Stockholders’ equity	750,962		60	%	697,085		58	%
Total capitalization, excluding short-term debt	$	1,256,421	100	%	$	1,205,584	100	%
	September 30, 2021				December 31, 2020
(in thousands)
Short-term debt	$	192,026	13	%	$	175,644	13	%
Long-term debt, including current maturities	521,665		36	%	522,099		37	%
Stockholders’ equity	750,962		51	%	697,085		50	%
Total capitalization, including short-term debt	$	1,464,653	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 51 percent as of September 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 nine months of 2021, we issued less than 0.1 million shares at an average price per share of $116.63 and received net proceeds of $6.6 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 September 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 September 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 $400.0 million of short-term debt, as required. At September 30, 2021 and December 31, 2020, we had $192.0 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 0.82 percent and 1.28 percent. Included in the September 30, 2021 balance, is $70.0 million in short-term debt for which we have entered into interest rate swap agreements.

In August 2021 we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the facility consist of one $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three (3) one-year extension options, which can be authorized by the Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the facility and to the extent that an individual loan under the revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 September 30, 2021, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026; both tranches are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of 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 September 30, 2021, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of September 30, 2021, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

Our total available credit under the Revolver at September 30, 2021 was $203.4 million. As of September 30, 2021, we had issued $4.6 million in letters of credit to various counterparties under the syndicated Revolvers. 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, the Company entered into two $30.0 million interest rate swaps with a total notional amount of $60.0 million through September and December 2021 with pricing of 0.205 and 0.20 percent, respectively. 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.

Long-Term Debt

On August 25, 2021, we entered into a Note Agreement with multiple lenders to issue $50.0 million in uncollateralized senior notes. Under the Note Agreement, we will issue the senior notes on January 25, 2022 at a rate of 2.49 percent for a 15-year term. These senior notes, when issued, will have similar covenants and default provisions as the existing senior notes, and will have an annual principal payment beginning in the sixth year after the issuance. The proceeds received from the issuances of the senior notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures. In addition, on September 24, 2021, we entered into an Equipment Financing Agreement with Banc of America Leasing & Capital, LLC to issue $9.6 million in sustainability linked financing for the purchase of equipment by our subsidiary, Marlin Gas Services. The equipment security note bears a 2.46 percent interest rate and has a term of ten years. Under the terms of the agreement, we granted a security interest in the equipment to the lender, to serve as collateral.

Cash Flows

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

	Nine Months Ended
	September 30,
(in thousands)	2021		2020
Net cash provided by (used in):
Operating activities	$	152,784	$	115,880
Investing activities	(148,076)		(136,551)
Financing activities	(2,321)		16,742
Net increase (decrease) in cash and cash equivalents	2,387		(3,929)
Cash and cash equivalents—beginning of period	3,499		6,985
Cash and cash equivalents—end of period	$	5,886	$	3,056

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 nine months ended September 30, 2021 and 2020, net cash provided by operating activities was $152.8 million and $115.9 million, respectively, resulting in an increase in cash flows of $36.9 million. Significant operating activities generating the cash flows change were as follows:

•Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities increased cash flows by $31.4 million;

•Net income, adjusted for non-cash adjustments and reconciling activities, increased cash flows by $10.5 million, due primarily to higher net income, and higher depreciation and amortization;

•Net cash flows from income taxes receivable increased by $7.0 million;

•Changes in net prepaid expenses and other current assets, customer deposits and refunds, accrued compensation and other net assets and liabilities, decreased cash flows by $0.5 million;

•Changes in net regulatory assets and liabilities decreased cash flows by $4.3 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 $7.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $148.1 million and $136.6 million during the nine months ended September 30, 2021 and 2020, respectively, resulting in a decrease in cash flows of $11.5 million. Cash paid for capital expenditures was $148.2 million for the first nine months of 2021, compared to $123.4 million for the same period in 2020, resulting in decreased cash flows of $24.8 million. The decrease was offset by an increase in cash flows due to the absence of acquisitions that occurred in the third quarter of 2020.

Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $2.3 million during the nine months ended September 30, 2021 compared to $16.7 million of net cash provided by financing activities over the same period in 2020, resulting in a decrease in cash flows of $19.0 million. The increase in net cash used in financing activities resulted primarily from the following:

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•Long-term debt repayments of $10.1 million;

•Cash dividends of $23.3 million paid during the nine months ended September 30, 2021, compared to $20.0 million for the nine months ended September 30, 2020; and

•Cash flows of $7.1 million as a result of issuing shares of our common stock under the DRIP program.

These increases in cash used were partially offset by increased cash provided by short-term debt of $16.4 million.

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 September 30, 2021 was $20.0 million. The aggregate amount guaranteed at September 30, 2021 was $8.0 million, with the guarantees expiring on various dates through September 24, 2022.

As of September 30, 2021, we have issued letters of credit totaling approximately $4.6 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 September 30, 2022. We have not drawn upon these letters of credit as of September 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 September 30, 2021:

	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)	$	30,597	$	37,437	$	—	$	—	$	68,034
Total	$	30,597	$	37,437	$	—	$	—	$	68,034

(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. We regularly are 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.

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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 (i) issue new debt instruments or (ii) 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 September 30, 2021:

(in thousands)	Balance at December 31, 2020		Increase (Decrease) in Fair Market Value		Less Amounts Settled		Balance at September 30, 2021
Sharp	$	3,182	$	11,232	$	(4,183)	$	10,231
Total	$	3,182	$	11,232	$	(4,183)	$	10,231

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

The following is a summary of fair market value of financial derivatives as of September 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	$	2,986	$	4,402	$	2,066	$	777	$	—	$	10,231
Total	$	2,986	$	4,402	$	2,066	$	777	$	—	$	10,231

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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 September 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 September 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 September 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.

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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.

Mandatory COVID-19 vaccination of employees or testing of employees could impact our workforce and have a material adverse effect on our business and results of operations.

On September 9, 2021, President Biden announced a proposed new rule requiring all employers with at least 100 employees to require that their employees be fully vaccinated or tested weekly. The U.S. Department of Labor’s Occupational Safety and Health Administration (“OSHA”) is currently drafting an emergency regulation (the “OSHA Regulation”) to carry out this mandate, which is expected to take effect in the coming weeks. At this time, it is unclear, among other things, if the OSHA Regulation will apply to all employees or only to certain employees, or how compliance will be documented.

In addition, on September 9, 2021, President Biden issued an executive order (the “Executive Order”) requiring all employers with U.S. Government contracts to ensure that their U.S.-based employees, contractors, and subcontractors, that work on or in support of U.S. Government contracts, are fully vaccinated by December 8, 2021.

At this time, it is not possible to predict with certainty the nature and extent to which we will be subject to the OSHA Regulation or Executive Order, or impact that the OSHA Regulation or Executive Order will have on us or on our workforce. Additional vaccine mandates may be announced in other jurisdictions in which we operate, or by governmental agencies with which we provide services. Implementation of these requirements by us may result in employee attrition, including attrition of critically skilled labor, absenteeism within our skilled labor force, challenges securing future labor needs, inefficiencies connected to employee turnover, and costs associated with implementation and on-going compliance, which could have a material adverse effect on our business, financial condition and results of operations.

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

	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)
July 1, 2021 through July 31, 2021(1)	474	$	119.98	—	—
August 1, 2021 through August 31, 2021	—	—		—	—
September 1, 2021 through September 30, 2021	—	—		—	—
Total	474	$	119.98	—	—

(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

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Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2020. During the quarter ended September 30, 2021, 474 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.

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Item 6.     Exhibits

10.1*	Amended and Restated Credit Agreement, dated August 12, 2021, by and between PNC Bank, National Association
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

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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: November 5, 2021

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