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CPK Chesapeake Utilities

Filed: 4 May 21, 4:54pm
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM10-Q
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: March 31, 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 classTrading Symbol(s)Name of each exchange on which registered
Common Stock - par value per share $0.4867CPKNew 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 — 17,532,046 shares outstanding as of April 30, 2021.


Table of Contents
 



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
Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, its divisions and subsidiaries, as appropriate in the context of the disclosure
CHP: Combined Heat and Power Plant
Company: Chesapeake Utilities Corporation, its divisions and subsidiaries, as appropriate in the context of the disclosure
COVID-19: An infectious disease caused by a newly discovered coronavirus
CNG: Compressed natural gas
Degree-day: A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above (CDD) or below (HDD) 65 degrees Fahrenheit
Delmarva Peninsula: A peninsula on the east coast of the U.S. occupied by Delaware and portions of Maryland and Virginia
DRIP: Dividend Reinvestment and Direct Stock Purchase Plan
Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value
Dts/d: Dekatherms per day
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned subsidiary of Chesapeake Utilities
Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC

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

FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission
FGT: Florida Gas Transmission Company
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities
GAAP: Generally Accepted Accounting Principles
GRIP: Gas Reliability Infrastructure Program
Gross Margin: a non-GAAP measure defined as operating revenues less the cost of sales. The Company's cost of sales includes purchased fuel cost for natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities and excludes depreciation, amortization and accretion
Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU
HDD: Heating Degree-Day
LNG: Liquefied Natural Gas
Marlin Gas Services: Marlin Gas Services, LLC, a wholly-owned subsidiary of Chesapeake Utilities


MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we have previously issued Senior Notes and which is a party to the current MetLife Shelf Agreement, as amended
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
NYL: New York Life Investors LLC, an institutional debt investment management firm, with which Chesapeake Utilities entered into a Shelf Agreement and issued Shelf Notes
Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake Utilities
PESCO: Peninsula Energy Services Company, Inc., an inactive wholly-owned subsidiary of Chesapeake Utilities
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which Chesapeake Utilities entered into a previous Shelf Agreement, which has been subsequently amended, and issued Shelf Notes
PSC: Public Service Commission, which is the state agency that regulates utility rates and/or services in certain of our jurisdictions
Revolver: Our $375 million unsecured revolving credit facility with certain lenders
RNG: Renewable natural gas
Sandpiper Energy: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities
SEC: Securities and Exchange Commission
Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
Sharp: Sharp Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities
Shelf Agreement: An agreement entered into by Chesapeake Utilities and a counterparty pursuant to which Chesapeake Utilities may request that the counterparty purchase our unsecured senior debt with a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance
Shelf Notes: Unsecured senior promissory notes issuable under the Shelf Agreement executed with various counterparties
SICP: 2013 Stock and Incentive Compensation Plan
TCJA: Tax Cuts and Jobs Act enacted on December 22, 2017
TETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline
Uncollateralized Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
U.S.: The United States of America
Western Natural Gas: Western Natural Gas Company


PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
Three Months Ended
March 31,
20212020
(in thousands, except shares and per share data)  
Operating Revenues
Regulated Energy$121,197 $102,955 
Unregulated Energy and other69,990 49,735 
Total Operating Revenues191,187 152,690 
Operating Expenses
Regulated Energy cost of sales43,043 34,832 
Unregulated Energy and other cost of sales31,254 18,038 
Operations39,437 35,951 
Maintenance4,042 3,836 
Depreciation and amortization15,365 12,252 
Other taxes6,449 5,647 
Total Operating Expenses139,590 110,556 
Operating Income51,597 42,134 
Other income, net385 3,319 
Interest charges5,105 5,814 
Income from Continuing Operations Before Income Taxes46,877 39,639 
Income Taxes on Continuing Operations12,405 10,598 
Income from Continuing Operations34,472 29,041 
Loss from Discontinued Operations, Net of Tax(6)(111)
Net Income$34,466 $28,930 
Weighted Average Common Shares Outstanding:
Basic17,485,866 16,414,773 
Diluted17,553,167 16,471,827 
Basic Earnings Per Share of Common Stock:
Earnings from Continuing Operations$1.97 $1.77 
Loss from Discontinued Operations0 (0.01)
Basic Earnings Per Share of Common Stock$1.97 $1.76 
Diluted Earnings Per Share of Common Stock:
Earnings from Continuing Operations$1.96 $1.77 
Loss from Discontinued Operations0 (0.01)
Diluted Earnings Per Share of Common Stock$1.96 $1.76 
The accompanying notes are an integral part of these financial statements.



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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
Three Months Ended
March 31,
20212020
(in thousands)
Net Income$34,466 $28,930 
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5) and $(5), respectively(14)(14)
Net gain, net of tax of $27 and $28, respectively77 80 
Cash Flow Hedges, net of tax:
Unrealized gain on commodity contract cash flow hedges, net of tax of $63 and $2, respectively166 
Unrealized loss on interest rate swap cash flow hedges, net of tax of $(1)(2)— 
Total Other Comprehensive Income, net of tax227 73 
Comprehensive Income$34,693 $29,003 
The accompanying notes are an integral part of these financial statements.


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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
AssetsMarch 31,
2021
December 31,
2020
(in thousands, except shares and per share data)  
Property, Plant and Equipment
Regulated Energy$1,595,744 $1,577,576 
Unregulated Energy306,291 300,647 
Other businesses and eliminations34,439 30,769 
Total property, plant and equipment1,936,474 1,908,992 
Less: Accumulated depreciation and amortization(380,839)(368,743)
Plus: Construction work in progress80,061 60,929 
Net property, plant and equipment1,635,696 1,601,178 
Current Assets
Cash and cash equivalents5,575 3,499 
Trade and other receivables62,309 61,675 
Less: Allowance for credit losses(4,243)(4,785)
Trade and other receivables, net58,066 56,890 
Accrued revenue20,835 21,527 
Propane inventory, at average cost6,229 5,906 
Other inventory, at average cost5,884 5,539 
Regulatory assets9,145 10,786 
Storage gas prepayments417 2,455 
Income taxes receivable6,792 12,885 
Prepaid expenses11,512 13,239 
Derivative assets, at fair value3,462 3,269 
Other current assets635 436 
Total current assets128,552 136,431 
Deferred Charges and Other Assets
Goodwill38,731 38,731 
Other intangible assets, net7,958 8,292 
Investments, at fair value10,883 10,776 
Operating lease right-of-use assets10,510 11,194 
Regulatory assets111,566 113,806 
       Receivables and other deferred charges10,054 12,079 
Total deferred charges and other assets189,702 194,878 
Total Assets$1,953,950 $1,932,487 
 
The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and LiabilitiesMarch 31,
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$0 $
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)8,528 8,499 
Additional paid-in capital350,875 348,482 
Retained earnings369,623 342,969 
Accumulated other comprehensive loss(2,638)(2,865)
Deferred compensation obligation6,992 5,679 
Treasury stock(6,992)(5,679)
Total stockholders’ equity726,388 697,085 
Long-term debt, net of current maturities508,525 508,499 
Total capitalization1,234,913 1,205,584 
Current Liabilities
Current portion of long-term debt13,600 13,600 
Short-term borrowing156,123 175,644 
Accounts payable58,167 60,253 
Customer deposits and refunds32,455 33,302 
Accrued interest4,837 2,905 
Dividends payable7,709 7,683 
Accrued compensation8,990 13,994 
Regulatory liabilities19,677 6,284 
Derivative liabilities, at fair value84 127 
Other accrued liabilities14,360 15,240 
Total current liabilities316,002 329,032 
Deferred Credits and Other Liabilities
Deferred income taxes211,801 205,388 
Regulatory liabilities143,291 142,736 
Environmental liabilities4,052 4,299 
Other pension and benefit costs29,856 30,673 
Operating lease - liabilities9,125 9,872 
Deferred investment tax credits and other liabilities4,910 4,903 
Total deferred credits and other liabilities403,035 397,871 
Environmental and other commitments and contingencies (Notes 6 and 7)00
Total Capitalization and Liabilities$1,953,950 $1,932,487 
The accompanying notes are an integral part of these financial statements.


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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended
March 31,
20212020
(in thousands)  
Operating Activities
Net income$34,466 $28,930 
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization15,365 12,252 
Depreciation and accretion included in other costs2,568 2,361 
Deferred income taxes6,334 5,738 
Realized gain on commodity contracts and sale of assets(3,514)(4,458)
Unrealized (gain) loss on investments/commodity contracts(389)1,511 
Employee benefits and compensation(173)11 
Share-based compensation1,876 1,056 
Changes in assets and liabilities:
Accounts receivable and accrued revenue(484)8,139 
Propane inventory, storage gas and other inventory1,371 3,921 
Regulatory assets/liabilities, net14,123 7,309 
Prepaid expenses and other current assets4,171 3,359 
Accounts payable and other accrued liabilities766 (4,243)
Income taxes (payable) receivable6,093 4,820 
Customer deposits and refunds(847)(1,817)
Accrued compensation(5,105)(8,766)
Other assets and liabilities, net3,761 (1,315)
Net cash provided by operating activities80,382 58,808 
Investing Activities
Property, plant and equipment expenditures(51,994)(35,182)
Proceeds from sale of assets394 4,106 
Environmental expenditures(247)(422)
Net cash used in investing activities(51,847)(31,498)
Financing Activities
Common stock dividends(7,513)(6,483)
Issuance of stock under the Dividend Reinvestment Plan, net of offering fees2,053 192 
Tax withholding payments related to net settled stock compensation(1,478)(977)
Change in cash overdrafts due to outstanding checks7 (1,747)
Net repayments under line of credit agreements(19,528)8,715 
Proceeds from issuance of long-term debt, net of offering fees0 (13)
Repayment of long-term debt0 (30,000)
Net cash used in financing activities(26,459)(30,313)
Net Increase (Decrease) in Cash and Cash Equivalents2,076 (3,003)
Cash and Cash Equivalents—Beginning of Period3,499 6,985 
Cash and Cash Equivalents—End of Period$5,575 $3,982 
The accompanying notes are an integral part of these financial statements.

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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
Loss
Deferred
Compensation
Treasury
Stock
Total
Balance at December 31, 201916,403,776 $7,984 $259,253 $300,607 $(6,267)$4,543 $(4,543)$561,577 
Net income— — — 28,930 — — — 28,930 
Other comprehensive gain— — — — 73 — — 73 
Dividend declared ($0.4050 per share)— — — (6,703)— — — (6,703)
Dividend reinvestment plan3,743 352 — — — — 354 
Share-based compensation and tax benefit (3)(4)
25,586 12 (84)— — — — (72)
Treasury stock activities— — — — — 925 (925)— 
Cumulative effect of the adoption of ASU 2016-13— — — (30)— — — (30)
Balance at March 31, 202016,433,105 $7,998 $259,521 $322,804 $(6,194)$5,468 $(5,468)$584,129 
Balance at December 31, 202017,461,841 $8,499 $348,482 $342,969 $(2,865)$5,679 $(5,679)$697,085 
Net income— — — 34,466 — — — 34,466 
Other comprehensive income— — — — 227 — — 227 
Dividend declared ($0.440 per share)— — — (7,812)— — — (7,812)
Dividend reinvestment plan20,511 10 2,204 — — — — 2,214 
Share-based compensation and tax benefit (3) (4)
39,141 19 189 — — — — 208 
Treasury stock activities— — — — — 1,313 (1,313)
Balance at March 31, 202117,521,493 $8,528 $350,875 $369,623 $(2,638)$6,992 $(6,992)$726,388 
 
(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 116,751, 105,087, 104,871, and 95,329 shares at March 31, 2021, December 31, 2020, March 31, 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 three months ended March 31, 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.

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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. At this time, restrictions continue to lift as vaccines have become more available in the United States. Regardless, Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects despite any social distancing restrictions that are in place. Despite the early changes in restrictions, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, and state and local requirements in order to protect our employees, customers and the communities. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19.

FASB Statements and Other Authoritative Pronouncements

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





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2.    Calculation of Earnings Per Share
Three Months Ended
March 31,
20212020
(in thousands, except shares and per share data)  
Calculation of Basic Earnings Per Share:
Income from Continuing Operations$34,472 $29,041 
Loss from Discontinued Operations(6)(111)
Net Income$34,466 $28,930 
Weighted average shares outstanding17,485,866 16,414,773 
Basic Earnings Per Share from Continuing Operations$1.97 $1.77 
Basic Loss Per Share from Discontinued Operations0 (0.01)
Basic Earnings Per Share$1.97 $1.76 
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted shares outstanding—Basic17,485,866 16,414,773 
Effect of dilutive securities—Share-based compensation67,301 57,054 
Adjusted denominator—Diluted17,553,167 16,471,827 
Diluted Earnings Per Share from Continuing Operations$1.96 $1.77 
Diluted Loss Per Share from Discontinued Operations0 (0.01)
Diluted Earnings Per Share$1.96 $1.76 
 

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 it: (i) expands our propane territory serviced in Florida and (ii) includes an established customer base with additional opportunities for future growth.
In connection with this acquisition, we recorded $3.5 million in property plant and equipment, $1.4 million in intangible assets associated with customer relationships and non-compete agreements and $1.8 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021. For the three months ended March 31, 2021, Western Natural Gas generated operating revenue and income of $0.8 million and $0.2 million, respectively.
Acquisition of Elkton Gas
In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland for approximately, $15.6 million, net of cash acquired. Additionally, the purchase price included $0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland.
In connection with this acquisition, we recorded $15.9 million in property, plant and equipment, $0.6 million in accounts receivable, $2.6 million in other liabilities, $2.6 million in regulatory liabilities and $4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based

8

on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021. For the three months ended March 31, 2021, Elkton Gas generated operating revenue and income of $2.6 million and $0.6 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 March 31, 2021 and 2020:
Three months ended March 31, 2021Three Months Ended March 31, 2020
(in thousands)Regulated EnergyUnregulated EnergyOther and EliminationsTotalRegulated EnergyUnregulated EnergyOther and EliminationsTotal
Energy distribution
Delaware natural gas division$33,272 $ $ $33,272 $26,567 $— $— $26,567 
Florida natural gas division8,956   8,956 8,477 — — 8,477 
FPU electric distribution18,551   18,551 14,219 — — 14,219 
FPU natural gas distribution26,861   26,861 25,444 — — 25,444 
Maryland natural gas division10,466   10,466 9,138 — — 9,138 
Sandpiper natural gas/propane operations8,071   8,071 6,292 — — 6,292 
Elkton Gas2,635   2,635 — — — — 
Total energy distribution108,812   108,812 90,137 — — 90,137 
Energy transmission
Aspire Energy 12,905  12,905 — 9,781 — 9,781 
Aspire Energy Express47   47 — — — — 
Eastern Shore19,972   19,972 19,279 — — 19,279 
Peninsula Pipeline6,467   6,467 4,824 — — 4,824 
Total energy transmission26,486 12,905  39,391 24,103 9,781 — 33,884 
Energy generation
Eight Flags 4,329  4,329 — 4,323 — 4,323 
Propane operations
Propane delivery operations 55,264  55,264 — 38,623 — 38,623 
Energy delivery services
Marlin Gas Services 2,352  2,352 — 1,309 — 1,309 
Other and eliminations
Eliminations(14,101)(91)(4,901)(19,093)(11,285)(24)(4,409)(15,718)
Other 0 132 132 — 132 132 
Total other and eliminations(14,101)(91)(4,769)(18,961)(11,285)(24)(4,277)(15,586)
Total operating revenues (1)
$121,197 $74,759 $(4,769)$191,187 $102,955 $54,012 $(4,277)$152,690 
(1) Total operating revenues for the three months ended March 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $(0.3) million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, and $0.7 million and $0.1 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended March 31, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.



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Contract balances
The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of March 31, 2021 and December 31, 2020 were as follows:
Trade ReceivablesContract Assets (Current)Contract Assets (Non-current)Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2020$55,600 $18 $4,816 $644 
Balance at 3/31/202156,577 18 5,034 433 
Increase (decrease)$977 $$218 $(211)
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 each of the three months ended March 31, 2021 and 2020, we recognized revenue of $0.4 million.

Remaining performance obligations
Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations, at March 31, 2021, are expected to be recognized as follows:
(in thousands)2021202220232024202520262027 and thereafter
Eastern Shore and Peninsula Pipeline$26,814 $30,415 $23,129 $20,970 $20,117 $19,387 $156,500 
Natural gas distribution operations4,239 6,521 6,064 5,835 5,299 5,071 33,465 
FPU electric distribution489 652 652 652 275 275 550 
Total revenue contracts with remaining performance obligations$31,542 $37,588 $29,845 $27,457 $25,691 $24,733 $190,515 


5.     Rates and Other Regulatory Activities

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

Delaware

There were no material regulatory activities during the first quarter of 2021.

Maryland

Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed with the Maryland PSC a strategic infrastructure development and enhancement plan. The STRIDE plan proposes to increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan through a

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proposed 5-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. The procedural schedule for the case is underway, with hearings scheduled for June 2021.

Florida

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

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

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

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

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

Eastern Shore

Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to 4 customers. Facilities to be constructed include 6 miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021.

COVID-19 Impact

We are monitoring the global outbreak of COVID-19 and taking steps to mitigate the potential risks posed by its spread. At this time, we have begun to see some early indications of these restrictions lifting. We provide an “essential

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service” to our customers, which means that it is paramount that we keep our employees who operate our business safe and informed. We have taken and are continuously monitoring and updating precautions and protocols to ensure the safety of our employees and customers. As an “essential business” we are allowed to continue operational activity and construction projects with appropriate safety precautions, personal protective equipment and social distancing restrictions in place. We are working with our suppliers to understand the potential impacts to our supply chain; if material negative impacts are identified, we will work to mitigate them. This is a continuously evolving situation, and has led to extended disruption of economic activity in our markets. We will continue to monitor developments affecting our employees, customers, suppliers and shareholders, and will take additional precautions as warranted to comply with the CDC, state and local requirements and recommendations to protect our employees, customers and the communities we serve.

In response to the COVID-19 pandemic and related restrictions, we implemented our pandemic response plan, which includes having all employees who can work remotely do so in order to promote social distancing and providing personal protective equipment to field employees to reduce the spread of COVID-19. 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.

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

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. At the present time, the state of emergency has not ended. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs.

In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish regulatory asset to record incremental expenses incurred due to COVID-19. This regulatory asset will allow us to seek recovery of these costs in our next base rate proceeding. On November 16, 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset, contending that the order should be a reversed or modified and to request a hearing on the protest. The hearing date has been scheduled for June 16, 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 businesses as currently authorized by the Delaware and Maryland PSCs and as initially authorized by the Florida PSC.





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

Amount (in thousands)
Operation and Regulatory JurisdictionMarch 31, 2021December 31, 2020Status
Eastern Shore (FERC)$34,190$34,190Will be addressed in Eastern Shore's next rate case filing.
Delaware Division (Delaware PSC)$12,694$12,728PSC approved amortization of ADIT in January 2019.
Maryland Division (Maryland PSC)$3,938$3,970PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)$3,699$3,713PSC approved amortization of ADIT in May 2018.
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)$8,146$8,184PSC 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)$19,166$19,257Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown Divisions$306$309Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Electric (Florida PSC)$6,631$6,694In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)$1,124$1,124PSC 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, 7 former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida.
As of March 31, 2021 and December 31, 2020, we had approximately $5.7 million and $5.9 million, respectively, in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of March 31, 2021 and December 31, 2020, we had recovered approximately $12.5 million and $12.4 million, respectively, leaving approximately $1.5 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.



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The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP site:
MGP Site (Jurisdiction)StatusEstimated Clean-Up Costs
West Palm Beach (Florida)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 2021.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.
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. Remediation is ongoing for the Winter Haven, Florida and the Seaford, Delaware MGP sites and the estimated clean-up costs are between $0.2 million to $0.9 million for both sites.


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 on March 31, 2023.
FPU natural gas distribution operations and Eight Flags have entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements are for a 10-year term that commenced in November 2020 and expire in October 2030.
Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency.
FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior 6 quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2021, FPU was in compliance with all of the requirements of its fuel supply contracts.
Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to our electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.

Corporate Guarantees
The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of March 31, 2021 was $20.0 million. The aggregate amount guaranteed at March 31, 2021 was approximately $8.3 million with the guarantees expiring on various dates through March 30, 2022.

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As of March 31, 2021, we have issued letters of credit totaling approximately $4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn on these letters of credit as of March 31, 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 2 reportable segments:
Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions subsidiary. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services. Effective in the third quarter of 2019, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations.

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

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Three Months Ended
March 31,
20212020
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy$120,721 $102,469 
Unregulated Energy70,466 50,221 
Total operating revenues, unaffiliated customers$191,187 $152,690 
Intersegment Revenues (1)
Regulated Energy$476 $486 
Unregulated Energy4,293 3,791 
Other businesses132 132 
Total intersegment revenues$4,901 $4,409 
Operating Income
Regulated Energy$32,864 $27,888 
Unregulated Energy19,105 13,862 
Other businesses and eliminations(372)384 
Operating income51,597 42,134 
Other income, net385 3,319 
Interest charges5,105 5,814 
Income from Continuing Operations before Income Taxes46,877 39,639 
Income Taxes on Continuing Operations12,405 10,598 
Income from Continuing Operations34,472 29,041 
Loss from Discontinued Operations, Net of Tax(6)(111)
Net Income$34,466 $28,930 
(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.


(in thousands)March 31, 2021December 31, 2020
Identifiable Assets
Regulated Energy segment$1,559,260 $1,547,619 
Unregulated Energy segment352,271 347,665 
Other businesses and eliminations42,419 37,203 
Total identifiable assets$1,953,950 $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 quarter of 2021, we issued less than 0.1 million shares at an average price per share of $109.05 and received net proceeds of $1.9 million under the DRIP. In April of 2021, we issued less than 0.1 million shares at an average price per share of $115.35 and received net proceeds of $1.0 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 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 loss. The following tables present the changes in the balance of accumulated other comprehensive loss as of March 31, 2021 and 2020. All amounts in the following tables are presented net of tax.

Defined BenefitCommodityInterest Rate
Pension andContractsSwap
PostretirementCash FlowCash Flow
Plan ItemsHedgesHedgesTotal
(in thousands)
As of December 31, 2020$(5,146)$2,309 $(28)$(2,865)
Other comprehensive income before reclassifications0 2,371 1 2,372 
Amounts reclassified from accumulated other comprehensive income (loss)63 (2,205)(3)(2,145)
Net current-period other comprehensive income (loss)63 166 (2)227 
As of March 31, 2021$(5,083)$2,475 $(30)$(2,638)
(in thousands)
As of December 31, 2019$(4,933)$(1,334)$— $(6,267)
Other comprehensive income before reclassifications— 895 — 895 
Amounts reclassified from accumulated other comprehensive income/(loss)66 (888)— (822)
Net prior-period other comprehensive income66 — 73 
As of March 31, 2020$(4,867)$(1,327)$— $(6,194)


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The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three months ended March 31, 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
March 31,
20212020
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)
$19 $19 
Net loss(1)
(104)(108)
Total before income taxes(85)(89)
Income tax benefit22 23 
Net of tax$(63)$(66)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)
$3,047 $1,227 
Income tax expense(842)(339)
Net of tax$2,205 $888 
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements$4 $— 
Income tax expense(1)
Net of tax$3 $
Total reclassifications for the period$2,145 $822 
(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 is included in other expense, net gains and losses on propane swap agreements, natural gas swaps, and natural gas futures contracts are included in cost of sales, the realized gain or loss on interest rate swap agreements is recognized as a component of interest charges in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.


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10.    Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2021 and 2020 are set forth in the following tables:
Chesapeake
Pension Plan
FPU
Pension Plan
Chesapeake SERPChesapeake
Postretirement
Plan
FPU
Medical
Plan
For the Three Months Ended March 31,2021202020212020202120202021202020212020
(in thousands)          
Interest cost$34 $46 $429 $518 $12 $16 $6 $$6 $10 
Expected return on plan assets(40)(42)(830)(745) —  —  — 
Amortization of prior service credit —  —  — (19)(19) — 
Amortization of net (gain) loss60 65 155 135 7 8 12 (2)— 
Net periodic cost (benefit)54 69 (246)(92)19 21 (5)4 10 
Amortization of pre-merger regulatory asset — 0  —  — 0 
Total periodic cost (benefit)$54 $69 $(246)$(92)$19 $21 $(5)$$4 $12 

We expect to record $0.7 million in pension and post-retirement benefit for 2021. The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.
The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three ended March 31, 2021 and 2020: 
For the Three Months Ended March 31, 2021Chesapeake
Pension
Plan
FPU
Pension
Plan
Chesapeake SERPChesapeake
Postretirement
Plan
FPU
Medical
Plan
Total
(in thousands)
Prior service credit$ $ $ $(19)$ $(19)
Net loss60 155 7 8 (2)228 
Total recognized in net periodic benefit cost60 155 7 (11)(2)209 
Recognized from accumulated other comprehensive loss/(gain) (1)
60 29 7 (11) 85 
Recognized from regulatory asset 126   (2)124 
Total$60 $155 $7 $(11)$(2)$209 
    
For the Three Months Ended March 31, 2020Chesapeake
Pension
Plan
FPU
Pension
Plan
Chesapeake SERPChesapeake
Postretirement
Plan
FPU
Medical
Plan
Total
(in thousands)
Prior service credit$— $— $— $(19)$— $(19)
Net loss65 135 12 — 217 
Total recognized in net periodic benefit cost65 135 (7)— 198 
Recognized from accumulated other comprehensive loss/(gain) (1)
65 26 (7)— 89 
Recognized from regulatory asset— 109 — — — 109 
Total$65 $135 $$(7)$— $198 
    (1) See Note 9, Stockholders' Equity.

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During the three months ended March 31, 2021, we contributed approximately $0.1 million to the Chesapeake Pension Plan and approximately $0.4 million to the FPU Pension Plan. We expect to contribute approximately $0.3 million and $2.1 million, respectively, to the Chesapeake Pension Plan and FPU Pension Plans during 2021, which represents the minimum annual contribution payments required.
The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2021 were immaterial. 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 months ended March 31, 2021 were $0.2 million. 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 months ended March 31, 2021, were immaterial. We estimate that approximately $0.1 million will be paid for such benefits under the FPU Medical Plan in 2021.

11.    Investments
The investment balances at March 31, 2021 and December 31, 2020, consisted of the following:
    
(in thousands)March 31,
2021
December 31,
2020
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)$10,860 $10,755 
Investments in equity securities23 21 
Total$10,883 $10,776 
We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2021 and 2020, we recorded a net unrealized gain of approximately $0.4 million and a net unrealized loss of approximately $1.5 million, respectively, in other income, 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 months ended March 31, 2021 and 2020:
    
Three Months Ended
March 31,
20212020
(in thousands)  
Awards to non-employee directors$188 $176 
Awards to key employees1,688 880 
Total compensation expense1,876 1,056 
Less: tax benefit(496)(275)
Share-based compensation amounts included in net income$1,380 $781 
    



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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 2020, after the most recent election of directors, each of our non-employee directors received an annual retainer of 887 shares of common stock under the SICP for service as a director through the 2021 Annual Meeting of Stockholders; accordingly, 8,870 shares, with a weighted average fair value of $84.47 per share, were issued and vested in 2020. At March 31, 2021, there was approximately $0.1 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending on the date of the 2021 Annual Meeting of Stockholders.
Key Employees
The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2021: 
Number of SharesWeighted Average
Fair Value
Outstanding—December 31, 2020186,878 $87.06 
Granted66,425 $102.73 
Vested(53,147)$76.31 
Expired(852)$74.85 
Forfeited(5,384)$93.39 
Outstanding—March 31, 2021193,920 $94.61 
In February 2021, we granted awards of 66,425 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted.
In March 2021, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in February 2021 for the performance period ended December 31, 2020, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 14,020 shares, based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $1.5 million.
At March 31, 2021, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $22.5 million. At March 31, 2021, there was approximately $7.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense for the remainder of 2021 through 2023.
Stock Options
There were no stock options outstanding or issued during the three months ended March 31, 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 March 31, 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 March 31, 2021, the volume of our commodity derivative contracts were as follows:

Business unitCommodityQuantity hedged (in millions)DesignationLongest Expiration date of hedge
SharpPropane (gallons)18.2Cash flows hedgesMarch 2024

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in March 2021 through March 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 $3.2 million from accumulated other comprehensive income (loss) to earnings during the next 12-month period ended March 31, 2022.

Interest Rate Swap Activities

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

We designated and accounted for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges. We expect to reclassify less than $0.1 million from accumulated other comprehensive income (loss) to earnings during the next 12-month period ended March 31, 2022.

Broker Margin

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

(in thousands)Balance Sheet LocationMarch 31, 2021December 31, 2020
SharpOther Current Liabilities$1,060 $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 March 31, 2021 and December 31, 2020, are as follows: 
 Derivative Assets
  Fair Value As Of
(in thousands)Balance Sheet LocationMarch 31, 2021December 31, 2020
Derivatives designated as fair value hedges
Propane put optionsDerivative assets, at fair value$ $14 
Derivatives designated as cash flow hedges
Propane swap agreementsDerivative assets, at fair value3,462 3,255 
Total asset derivatives$3,462 $3,269 
 
 Derivative Liabilities
  Fair Value As Of
(in thousands)Balance Sheet LocationMarch 31, 2021December 31, 2020
Derivatives designated as fair value hedges
Propane put optionsDerivative liabilities, at fair value$ $23 
Derivatives designated as cash flow hedges
Propane swap agreementsDerivative liabilities, at fair value42 64 
Interest rate swap agreementsDerivative liabilities, at fair value42 40 
Total liability derivatives$84 $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 GainFor the Three Months Ended March 31,
(in thousands)(Loss) on Derivatives20212020
Derivatives designated as fair value hedges
Propane put optionsCost of sales$(24)$ 
Derivatives designated as cash flow hedges
Propane swap agreementsCost of sales3,047 1,227 
Propane swap agreementsOther comprehensive income (loss)229 
Interest rate swap agreementsInterest expense4 
Interest rate swap agreementsOther comprehensive income (loss)(3)
Total$3,253 $1,236 



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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 HierarchyDescription of Fair Value LevelFair Value Technique Utilized
Level 1Unadjusted 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 2Quoted 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 3Prices 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 March 31, 2021 and December 31, 2020:
 Fair Value Measurements Using:
As of March 31, 2021Fair ValueQuoted 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 fund2,148   2,148 
Investments—mutual funds and other8,712 8,712   
Total investments10,883 8,735  2,148 
Derivative assets3,462  3,462  
Total assets$14,345 $8,735 $3,462 $2,148 
Liabilities:
Derivative liabilities$84 $ $84 $ 
 

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 Fair Value Measurements Using:
As of December 31, 2020Fair ValueQuoted 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 fund2,156 — — 2,156 
Investments—mutual funds and other8,599 8,599 — — 
Total investments10,776 8,620 — 2,156 
Derivative assets3,269 — 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 three months ended March 31, 2021 and 2020:
     
Three months ended March 31,
20212020
(in thousands) 
Beginning Balance$2,156 $803 
Purchases and adjustments22 
Transfers0 57 
Distribution(38)(38)
Investment income8 
Ending Balance$2,148 $835 

Investment income from the Level 3 investments is reflected in other expense, (net) in the condensed consolidated statements of income.
At March 31, 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 March 31, 2021, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $523.0 million, compared to the estimated fair value of $537.7 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: 
March 31,December 31,
(in thousands)20212020
Uncollateralized senior notes:
5.93% note, due October 31, 2023$9,000 $9,000 
5.68% note, due June 30, 202617,400 17,400 
6.43% note, due May 2, 20285,600 5,600 
3.73% note, due December 16, 202816,000 16,000 
3.88% note, due May 15, 202945,000 45,000 
3.25% note, due April 30, 203270,000 70,000 
3.48% note, due May 31, 203850,000 50,000 
3.58% note, due November 30, 203850,000 50,000 
3.98% note, due August 20, 2039100,000 100,000 
       2.98% note, due December 20, 203470,000 70,000 
3.00% note, due July 15, 203550,000 50,000 
2.96% note, due August 15, 203540,000 40,000 
Less: debt issuance costs(875)(901)
Total long-term debt522,125 522,099 
Less: current maturities(13,600)(13,600)
Total long-term debt, net of current maturities$508,525 $508,499 
.
    Shelf Agreements
We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at March 31, 2021:
(in thousands)Total Borrowing CapacityLess: Amount of Debt IssuedLess: Unfunded CommitmentsRemaining 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 March 31, 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
At March 31, 2021 and December 31, 2020, we had $156.1 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent. Included in the March 31, 2021 balance, is $100.0 million in short-term debt for which we have entered into interest rate swap agreements.

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

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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 March 31, 2021, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon total indebtedness to total capitalization ratio. As of March 31, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the Revolver at March 31, 2021 was $214.1 million. As of March 31, 2021, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. Although the letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties, the letters of credit reduce the available borrowings under our syndicated Revolver.
In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.

We are authorized by our Board of Directors to borrow up to $375.0 million of short-term debt, as required.

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

Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at March 31, 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 which preclude our ability to pay dividends, obtain financing or enter into additional leases. As of March 31, 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
March 31,
( in thousands)Classification20212020
Operating lease cost (1)
Operations expense$523 $626 
(1) Includes short-term leases and variable lease costs, which are immaterial.


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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 March 31, 2021 and December 31, 2020:
(in thousands)Balance sheet classificationMarch 31, 2021December 31, 2020
Assets 
Operating lease assetsOperating lease right-of-use assets$10,510 $11,194 
Liabilities
Current
Operating lease liabilitiesOther accrued liabilities$1,724 $1,747 
Noncurrent
Operating lease liabilitiesOperating lease - liabilities9,125 9,872 
Total lease liabilities $10,849 $11,619 


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

March 31, 2021December 31, 2020
Weighted-average remaining lease term (in years)
 
Operating leases8.778.70
Weighted-average discount rate
Operating leases3.8 %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 March 31, 2021 and 2020:

Three Months Ended
March 31,
(in thousands)20212020
Operating cash flows from operating leases$471 $527 

The following table presents the future undiscounted maturities of our operating and financing leases at March 31, 2021 and for each of the next five years and thereafter:
(in thousands)
Operating 
Leases (1)
Remainder of 2021$1,531 
20221,854 
20231,770 
20241,615 
20251,400 
2026966 
Thereafter3,621 
Total lease payments$12,757 
Less: Interest1,908 
Present value of lease liabilities$10,849 
    (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;
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;
the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and

29

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, and new products and services as well as increased opportunities for collaboration and efficiencies across the organization.
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 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 months Ended March 31, 2021
Overview

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

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. At this time, restrictions continue to lift as vaccines have become more available in the United States. Regardless, Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects despite any social distancing restrictions that are in place. In response to the COVID-19 pandemic and related restrictions, we implemented our pandemic response plan, which includes having all employees who can work remotely do so in order to promote social distancing and providing personal protective equipment to field employees to reduce the spread of COVID-19.

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. In the fourth quarter of 2020, we began recording regulatory assets, as currently authorized by the Delaware and Maryland PSCs and as initially provided for by the Florida PSC, associated with the incremental expenses incurred by our natural gas and electric distribution businesses as a result of the pandemic. Despite the early changes in restrictions, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, and state and local requirements in order to protect our employees, customers and the communities. Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19

Operational Highlights

Our income from continuing operations for the three months ended March 31, 2021 was $34.5 million, or $1.96 per share, compared to $29.0 million, or $1.77 per share, for the same quarter of 2020. Operating income for the three months ended March 31, 2021 increased by $9.5 million, or 22.5 percent, over the same period in 2020. Higher earnings for the first quarter of 2021 reflected a return to more normal weather compared to weather in the first quarter of 2020 that was 20.4 percent warmer than normal. Our earnings also increased from pipeline expansion projects, favorable regulatory initiatives and contributions from the 2020 acquisitions of Elkton Gas and Western Natural Gas. Increased retail propane margins per gallon, organic growth in the natural gas distribution operations and increased margin from Marlin Gas Services, also generated additional earnings.

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Three Months Ended
March 31,Increase
20212020(decrease)
(in thousands except per share)   
Gross Margin
  Regulated Energy segment$78,154 $68,123 $10,031 
  Unregulated Energy segment38,776 31,782 6,994 
Other businesses and eliminations(40)(85)45 
Total Gross Margin$116,890 $99,820 $17,070 
Operating Income
Regulated Energy segment$32,864 $27,888 $4,976 
Unregulated Energy segment19,105 13,862 5,243 
Other businesses and eliminations(372)384 (756)
Total Operating Income51,597 42,134 9,463 
Other expense, net385 3,319 (2,934)
Interest charges5,105 5,814 (709)
Income from Continuing Operations Before Income Taxes46,877 39,639 7,238 
Income Taxes on Continuing Operations12,405 10,598 1,807 
Income from Continuing operations34,472 29,041 5,431 
Loss from Discontinued Operations(6)(111)105 
Net Income$34,466 $28,930 $5,536 
Basic Earnings Per Share of Common Stock
Earnings from Continuing Operations$1.97 $1.77 $0.20 
Loss from Discontinued Operations (0.01)0.01 
Basic Earnings Per Share of Common Stock$1.97 $1.76 $0.21 
Diluted Earnings Per Share of Common Stock
Earnings from Continuing Operations$1.96 $1.77 $0.19 
Loss from Discontinued Operations (0.01)0.01 
Diluted Earnings Per Share of Common Stock$1.96 $1.76 $0.20 

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Key variances in continuing operations, between the first quarter of 2021 and the first quarter of 2020, included: 
(in thousands, except per share data)Pre-tax
Income
Net
Income
Earnings
Per Share
First Quarter of 2020 Reported Results from Continuing Operations$39,639 $29,041 $1.77 
Adjusting for Unusual Items:
Gain from sales of assets in the first quarter of 2020(3,162)(2,317)(0.14)
Increased (Decreased) Gross Margins:
Increased customer consumption - primarily weather related6,430 4,728 0.26 
Eastern Shore and Peninsula Pipeline service expansions*2,749 2,022 0.11 
Hurricane Michael Settlement margin impact *2,575 1,894 0.11 
Margin contributions from Elkton Gas and Western Natural Gas*1,862 1,369 0.08 
Increased retail propane margins per gallon1,340 986 0.06 
Natural gas growth (excluding service expansions)939 691 0.04 
Increased gross margin from demand for Marlin Gas Services *731 537 0.03 
Florida GRIP*370 272 0.02 
16,996 12,499 0.71 
 (Increased) Decreased Operating Expenses (Excluding Cost of Sales):
Payroll, Benefits and other employee-related expenses due to growth(1,995)(1,467)(0.08)
Hurricane Michael settlement agreement - depreciation and amortization impact(1,776)(1,306)(0.07)
Depreciation, amortization and property tax costs due to new capital investments(1,733)(1,274)(0.07)
Facilities, maintenance and outside services costs(1,130)(831)(0.05)
Operating expenses for Elkton Gas and Western Natural Gas acquisitions(1,029)(757)(0.04)
(7,663)(5,635)(0.31)
Interest charges (1)
709 521 0.03 
Net other changes358 363 0.02 
Change in shares outstanding due to 2020 and 2021 equity offerings— — (0.12)
1,067 884 (0.07)
First Quarter of 2021 Reported Results from Continuing Operations$46,877 $34,472 $1.96 
*See the Major Projects and Initiatives table.
(1) Interest charges includes amortization of a regulatory liability of $0.3 million related to the Hurricane Michael regulatory proceeding settlement.


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Summary of Key Factors
Recently Completed and Ongoing Major Projects and Initiatives
We constantly pursue and develop additional projects and initiatives to serve existing and new customers, and to further grow our businesses and earnings, with the intention to increase shareholder value. The following summary represents 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 EndedYear EndedEstimate for
March 31,December 31,Fiscal
in thousands20212020202020212022
Pipeline Expansions:
Western Palm Beach County, Florida Expansion (1)
$1,167 $1,000 $4,167 $4,984 $5,227 
Del-Mar Energy Pathway (1) (2)
884 189 2,462 4,134 6,708 
Callahan Intrastate Pipeline (2)
1,887 — 3,851 7,564 7,598 
Guernsey Power Station47 — — 514 1,486 
Total Pipeline Expansions3,985 1,189 10,480 17,196 21,019 
CNG Transportation2,077 1,347 7,231 7,900 8,500 
RNG Transportation — — 150 1,000 
Acquisitions:
Elkton Gas1,312 — 1,344 3,992 4,200 
    Western Natural Gas550 — 389 1,800 1,854 
Total Acquisitions1,862 — 1,733 5,792 6,054 
Regulatory Initiatives:
Florida GRIP4,065 3,695 15,178 16,739 17,712 
Hurricane Michael regulatory proceeding2,575 — 10,864 11,014 11,014 
Capital Cost Surcharge Programs136 133 523 1,350 2,350 
Total Regulatory Initiatives6,776 3,828 26,565 29,103 31,076 
Total$14,700 $6,364 $46,009 $60,141 $67,649 

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

Detailed Discussion of Major Projects and Initiatives

Pipeline Expansions

West Palm Beach County, Florida Expansion
Peninsula Pipeline is constructing four transmission lines to bring additional natural gas to our distribution system in West Palm Beach, Florida. The first phase of this project was placed into service in December 2018 and generated incremental gross margin of $0.2 million for the three months ended March 31, 2021 compared to 2020. We expect to complete the remainder of the project in phases through the third quarter of 2021, and estimate that the project will generate annual gross margin of $5.0 million in 2021 and $5.2 million in 2022.

Del-Mar Energy Pathway
In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. Eastern Shore anticipates that this project will be fully in-service by the beginning of the fourth quarter of 2021. The new facilities will: (i) ensure an additional 14,300 Dts/d of firm service to four customers, (ii) provide additional natural gas transmission pipeline

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infrastructure in eastern Sussex County, Delaware, and (iii) represent the first extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Construction of the project began in January 2020, and interim services in advance of this project generated additional gross margin of $0.7 million for the three months ended March 31, 2021. The estimated annual gross margin from this project including natural gas distribution service in Somerset County, Maryland, is approximately $4.1 million in 2021 and $6.7 million annually thereafter.

Callahan Intrastate Pipeline
Peninsula Pipeline completed the construction of a jointly owned intrastate transmission pipeline with Seacoast Gas Transmission in Nassau County, Florida in June 2020. The 26-mile pipeline serves growing demand for energy in both Nassau and Duval Counties. For the three months ended March 31, 2021, the project generated $1.9 million 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 three months ended March 31, 2021, we received approximately $47,000 related to the construction delay of the in-service date of the project. The project is expected to be in service in the fourth quarter of 2021, and produce gross margin of approximately $0.5 million in 2021 and $1.5 million in 2022 and beyond.

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. For the three months ended March 31, 2021, Marlin Gas Services generated additional gross margin of $0.7 million. We estimate that Marlin Gas Services will generate annual gross margin of approximately $7.9 million in 2021 and $8.5 million in 2022, with the potential for additional growth in future years. Marlin Gas Services continues to actively expand the territories it serves, as well as leverage its patented technology to serve other markets, including pursuing liquefied natural gas transportation opportunities and renewable natural gas 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 advanced, patented technology to treat landfill gas by removing carbon dioxide and other components to purify the gas and produce pipeline quality RNG. Aspire Energy will utilize its existing natural gas gathering assets to inject the RNG from this project to its system for distribution to end use customers. Once flowing, the RNG volume will represent nearly 10 percent of Aspire Energy’s gas gathering volumes.

Bioenergy DevCo
In June 2020, our Delmarva natural gas operations and Bioenergy DevCo (“BDC”), a developer of anaerobic digestion facilities that create renewable energy and healthy soil products from organic material, entered into an agreement related to a project to extract renewable natural gas 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.
The renewable natural gas resource created from organic material at BDC's anaerobic digestion facilities in Delaware, will be processed for use by our Delmarva natural gas operations. Marlin Gas Services will transport the sustainable fuel from the BDC facility to an Eastern Shore interconnection, where it will be introduced to the distribution 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 renewable natural gas to our operations. As part of this partnership, we will transport the renewable natural gas produced at CleanBay's planned Westover, Maryland bio-refinery, to our natural gas infrastructure in the Delmarva Peninsula

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region. Eastern Shore and Marlin Gas Services, will transport the renewable natural gas from CleanBay to our Delmarva natural gas distribution system where it is ultimately delivered to the Delmarva natural gas distribution end use customers.
At the present time, we expect to generate $0.2 million in 2021 in incremental margin from these renewable natural gas transportation projects beginning in 2021. Timing of incremental margin from RNG transportation projects is dependent upon the construction schedules of each project. As we continue to finalize contract terms and complete the necessary permitting associated with each of these projects, additional information will be provided regarding incremental margin at a future time.

Acquisitions

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 $0.6 million in additional gross margin from Western Natural Gas in 2020 and we estimate that this acquisition will generate gross margin of approximately $1.8 million in 2021 with additional opportunities for growth.

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. We generated $1.3 million in additional gross margin from Elkton Gas and estimate that this acquisition will generate gross margin of approximately $4.0 million in 2021 and $4.2 million in 2022.

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 $173.9 million of capital expenditures to replace 333 miles of qualifying distribution mains, including $8.0 million of new pipes during the first three months of 2021. We expect to generate annual gross margin of approximately $16.7 million in 2021, and $17.7 million in 2022.

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

In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested, to 10 years, and included costs related to Hurricane Dorian of approximately $1.2 million in this filing.

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

In September 2020, the Florida PSC approved a settlement agreement between FPU and the Office of the Public Counsel regarding final cost recovery and rates associated with Hurricane Michael. Previously, in late 2019, the Florida PSC approved an interim rate increase, subject to refund, effective January 1, 2020, associated with the restoration effort following Hurricane Michael. We fully reserved these interim rates, pending a final resolution and settlement of the limited proceeding. The settlement agreement allowed us to: (a) refund the over-collection of interim rates through the fuel clause; (b) record regulatory assets for storm costs in the amount of $45.8 million including interest which will be amortized over six years; (c) recover these storm costs through a surcharge for a total of $7.7 million annually; and (d) collect an annual increase in revenue of $3.3 million to recover capital costs associated with new plant investments and a regulatory asset for the cost of removal and undepreciated plant. The new base rates and storm surcharge were effective on November 1, 2020. The following table summarizes the impact of Hurricane Michael regulatory proceeding for the three months ended March 31, 2021:

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Three Months Ended
(in thousands)March 31, 2021
Gross Margin$2,575 
Depreciation(303)
Amortization of regulatory assets2,079 
Operating income799 
Amortization of liability associated with interest expense(327)
Pre-tax income1,126 
Income tax expense298 
Net income$828 
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 $1.4 million in 2021 and $2.4 million in 2022 from relocation projects and is dependent upon the completion of capital projects and timing of filings.
Other major factors influencing gross margin
Weather and Consumption
Weather conditions accounted for a $6.4 million increase in gross margin during the first quarter of 2021, compared to the same period in 2020, primarily due to a 13.8 percent increase in HDDs in the Delmarva Peninsula and Ohio that resulted in increased customer consumption. Compared to normal temperatures, as detailed below, gross margin was higher by $1.3 million. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") the three months ended March 31, 2021 and 2020.
Three Months Ended
March 31,
20212020Variance
Delmarva Peninsula
Actual HDD2,186 1,859 327 
10-Year Average HDD ("Normal")2,280 2,349 (69)
Variance from Normal(94)(490)
Florida
Actual HDD503 369 134 
10-Year Average HDD ("Normal")506 570 (64)
Variance from Normal(3)(201)
Ohio
Actual HDD2,772 2,496 276 
10-Year Average HDD ("Normal")2,959 3,019 (60)
Variance from Normal(187)(523)
Florida
Actual CDD184 323 (139)
10-Year Average CDD ("Normal")195 168 27 
Variance from Normal(11)155 


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 $0.9 million of additional margin for the three months ended March 31, 2021. The average number of residential customers served on the Delmarva Peninsula and in Florida increased

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by 4.5 percent and 5.0 percent, respectively, during the first quarter of 2021. 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 the Company's distribution infrastructure continues to build out. In addition, as new communities continue to build out due to population growth and infrastructure is added to support the growth, there is also increased load from new commercial and industrial customers. The details for the three months ended March 31, 2021 are provided in the following table:
Three Months Ended
March 31, 2021
(in thousands)Delmarva PeninsulaFlorida
Customer Growth:
Residential$490 $307 
Commercial and industrial70 72 
Total Customer Growth$560 $379 



Regulated Energy Segment

For the quarter ended March 31, 2021, compared to the quarter ended March 31, 2020:
Three Months Ended
March 31,Increase
20212020(decrease)
(in thousands)  
Revenue$121,197 $102,955 $18,242 
Cost of sales43,043 34,832 8,211 
Gross margin78,154 68,123 10,031 
Operations & maintenance28,006 26,241 1,765 
Depreciation & amortization12,030 9,319 2,711 
Other taxes5,254 4,675 579 
Total operating expenses45,290 40,235 5,055 
Operating income$32,864 $27,888 $4,976 
Operating income for the Regulated Energy segment for the first quarter of 2021 was $32.9 million, an increase of $5.0 million or 17.8 percent for the three months ended March 31, 2021 over the same period in 2020. Higher operating income reflects increased consumption driven primarily by colder weather compared to the first quarter of 2020, continued pipeline expansions by Eastern Shore and Peninsula Pipeline, contributions from the Hurricane Michael regulatory proceeding settlement, organic growth in the Company's natural gas distribution businesses and operating results from the Elkton Gas acquisition completed in the third quarter of 2020. These increases were offset by higher depreciation, amortization and property taxes, including amortization of the regulatory asset associated with the Hurricane Michael regulatory proceeding settlement, new expenses associated with Elkton Gas, and higher other operating expenses.

Items contributing to the quarter-over-quarter increase in gross margin are listed in the following table:
(in thousands)
Eastern Shore and Peninsula Pipeline service expansions$2,749 
Margin contribution from Hurricane Michael regulatory proceeding settlement2,575 
Increased customer consumption - primarily weather related1,641 
Margin contribution from the Elkton Gas acquisition (completed in July 2020)1,312 
Natural gas growth (excluding service expansions)939 
Florida GRIP370 
Other variances445 
Quarter-over-quarter increase in gross margin$10,031 

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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 $2.1 million from Peninsula Pipeline's Western Palm Beach County and Callahan projects and $0.7 million from Eastern Shore's Del-Mar Energy Pathway project.

Margin Contribution from Hurricane Michael Regulatory Proceeding Settlement
We generated $2.6 million in additional gross margin as a result of the settlement of the Hurricane Michael regulatory proceeding. Refer to Note 5, Rates and Other Regulatory Activities, in the condensed consolidated financial statements for additional information.

Increased Customer Consumption - Primarily Weather Related
Gross margin increased by $1.6 million for the for the three months ended March 31, 2021, compared to the same period in 2020, primarily due to an 18 percent increase in HDDs on the Delmarva Peninsula and a 36 percent increase in HDDs in Florida that resulted in increased customer consumption of energy.

Elkton Gas
Gross margin increased by $1.3 million due to margin contributed from Elkton Gas which was acquired in July 2020.
Natural Gas Distribution Customer Growth
We generated additional gross margin of $0.9 million from natural gas customer growth. Gross margin increased by $0.4 million in Florida and $0.5 million on the Delmarva Peninsula for the three months ended March 31, 2021, as compared to the same period in 2020, due primarily to residential customer growth of 4.5 percent and 5.0 percent on the Delmarva Peninsula and in Florida, respectively.

Florida GRIP
Continued investment in the Florida GRIP generated additional gross margin of $0.4 million in first quarter of 2021 compared to the same period in 2020.

Operating Expenses
Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table:
(in thousands)
Hurricane Michael regulatory proceeding settlement - depreciation and amortization impact$1,776 
Depreciation, asset removal and property tax costs due to new capital investments1,390 
Facilities and maintenance costs and outside services885 
Payroll, benefits and other employee-related expenses due to growth802 
Operating expenses from the Elkton Gas acquisition524 
Other variances(322)
Quarter-over-quarter increase in operating expenses$5,055 



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Unregulated Energy Segment

For the quarter ended March 31, 2021, compared to the quarter ended March 31, 2020:
 
Three Months Ended
March 31,Increase
20212020(decrease)
(in thousands)   
Revenue$74,759 $54,011 $20,748 
Cost of sales35,983 22,229 13,754 
Gross margin38,776 31,782 6,994 
Operations & maintenance15,162 14,034 1,128 
Depreciation & amortization3,323 2,918 405 
Other taxes1,186 968 218 
Total operating expenses19,671 17,920 1,751 
Operating income$19,105 $13,862 $5,243 

Operating income for the Unregulated Energy segment for the first quarter of 2021 was $19.1 million, an increase of $5.2 million or 37.8 percent, over the same period in 2020. Higher operating income reflects increased consumption driven primarily by colder weather compared to the first quarter of 2020, higher retail propane margins per gallon, contribution from the acquisition of the Western Natural Gas propane assets and increased demand for Marlin Gas Services' CNG transportation services. These increases were partially offset by higher depreciation, amortization and property taxes related to recent capital investments and new expenses associated with Western Natural Gas and higher other operating expenses.
Gross Margin
Items contributing to the quarter-over-quarter increase in gross margin are listed in the following table:
(in thousands)Margin Impact
Propane Operations
Increased customer consumption - primarily weather related$3,847 
Increased retail propane margins per gallon driven by favorable supply costs1,340 
Western Natural Gas acquisition (completed in October 2020)550 
Marlin Gas Services
Increased demand for CNG services731 
Aspire Energy
Increased customer consumption - primarily weather related942 
Other variances(416)
Quarter-over-quarter increase in gross margin$6,994 
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 18 percent colder during the first quarter of 2021 compared to the same period in 2020.
Increased Retail Propane Margins - Gross margin increased by $1.3 million, due to lower propane inventory costs and favorable market conditions. These market conditions, which include competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices.
Western Natural Gas - Gross margin increased by $0.6 million due to the margin generated from Western Natural Gas, which was acquired by Sharp in October 2020.
Marlin Gas Services

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Gross margin increased by $0.7 million during the first quarter of 2021, as compared to the same period in the prior year due to higher demand for CNG hold services.
Aspire Energy
Increased Customer Consumption Primarily Weather Related - Gross margin increased by $0.9 million due to higher consumption of gas as weather in Ohio was approximately 11 percent colder during the first quarter of 2021 over the same period in 2020.

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$529 
Payroll, benefits and other employee-related expenses due to growth506 
Operating expenses from the Western Natural Gas acquisition338 
Facilities and maintenance costs251 
Other variances127 
Quarter-over-quarter increase in operating expenses$1,751 


OTHER EXPENSE, NET
For the quarter ended March 31, 2021 compared to the quarter ended March 31, 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 $2.9 million in the first quarter 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.

INTEREST CHARGES
For the quarter ended March 31, 2021 compared to the quarter ended March 31, 2020
Interest charges for the quarter ended March 31, 2021 decreased by $0.7 million, compared to the same period in 2020, attributable primarily to a decrease of $0.7 million in lower interest expense from lower levels outstanding under our revolving credit facilities, and $0.3 million of an amortization credit/reduction in interest expense associated with a regulatory liability that was established in connection with the Hurricane Michael regulatory proceeding settlement. Partially offsetting the interest savings was an increase of $0.2 million in interest expense as a result of several long-term debt placements in 2020.

INCOME TAXES
For the quarter ended March 31, 2021 compared to the quarter ended March 31, 2020
Income tax expense was $12.4 million for the quarter ended March 31, 2021, compared to $10.6 million for the quarter ended March 31, 2021. Our effective income tax rate was 26.5 percent and 26.7 percent, for the three months ended March 31, 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 $48.7 million for the three months ended March 31, 2021. In the table below, we have provided a range of our forecasted capital expenditures for 2021:
2021
(dollars in thousands)LowHigh
Regulated Energy:
Natural gas distribution$79,000 $85,000 
Natural gas transmission55,000 60,000 
Electric distribution9,000 13,000 
Total Regulated Energy143,000 158,000 
Unregulated Energy:
Propane distribution9,000 12,000 
Energy transmission14,000 15,000 
Other unregulated energy8,000 12,000 
Total Unregulated Energy31,000 39,000 
Other:
Corporate and other businesses1,000 3,000 
Total Other1,000 3,000 
Total 2021 Forecasted Capital Expenditures$175,000 $200,000 

The 2021 forecast, which excludes any potential acquisitions, includes capital expenditures associated with the following projects: Delmarva Natural Gas distribution's Somerset County expansion and the Bioenergy Devco RNG Project, Eastern Shore's Del-Mar Energy Pathway and the CleanBay RNG project, 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.

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 March 31, 2021 and December 31, 2020:
March 31, 2021December 31, 2020
(in thousands)    
Long-term debt, net of current maturities$508,525 41 %$508,499 42 %
Stockholders’ equity726,388 59 %697,085 58 %
Total capitalization, excluding short-term debt$1,234,913 100 %$1,205,584 100 %
 March 31, 2021December 31, 2020
(in thousands)    
Short-term debt$156,123 11 %$175,644 13 %
Long-term debt, including current maturities522,125 37 %522,099 37 %
Stockholders’ equity726,388 52 %697,085 50 %
Total capitalization, including short-term debt$1,404,636 100 %$1,394,828 100 %
Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was 52 percent as of March 31, 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 were added to the general funds. In the first quarter of 2021 we issued less than 0.1 million shares at an average price per share of $109.05 and received net proceeds of $1.9 million under the DRIP. In April 2021, we also issued less than 0.1 million shares at an average price per share of $115.35 and received net proceeds of $1.0 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 March 31, 2021:
(in thousands)Total Borrowing CapacityLess: Amount of Debt IssuedLess: Unfunded CommitmentsRemaining 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 March 31, 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
At March 31, 2021 and December 31, 2020, we had $156.1 million and $175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent, respectively. Included in the March 31, 2021 balance is $100.0 million in short-term debt for which we have entered into interest rate swap agreements.

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

The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of March 31, 2021, we are in compliance with this covenant.

The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon our total indebtedness to total capitalization ratio. As of March 31, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the new Revolver at March 31, 2021 was $214.1 million. As of March 31, 2021, we had issued $4.8 million in letters of credit to various counterparties under the syndicated Revolver. Although the letters of credit are not included in the outstanding short-term borrowings and we do not anticipate they will be drawn upon by the counterparties, the letters of credit reduce the available borrowings under our syndicated Revolver.
In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate.
We are authorized by our Board of Directors to borrow up to $375 million of short-term debt, as required.

Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2021 and 2020:
 
Three Months Ended
March 31,
(in thousands)20212020
Net cash provided by (used in):
Operating activities$80,382 $58,808 
Investing activities(51,847)(31,498)
Financing activities(26,459)(30,313)
Net increase (decrease) in cash and cash equivalents2,076 (3,003)
Cash and cash equivalents—beginning of period3,499 6,985 
Cash and cash equivalents—end of period$5,575 $3,982 


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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 three months ended March 31, 2021 and 2020, net cash provided by operating activities was $80.4 million and $58.8 million, respectively, resulting in an increase in cash flows of $21.6 million. Significant operating activities generating the cash flows change were as follows:
Changes in net prepaid expenses and other current assets, customer deposits and refunds, accrued compensation and other net assets and liabilities, increased cash flows by $10.5 million;
Net income, adjusted for non-cash adjustments and reconciling activities, increased cash flows by $9.1 million, due primarily to higher net income, depreciation and amortization and gain on sale of assets;
Changes in net regulatory assets and liabilities increased cash flows by $6.8 million due primarily to the change in fuel costs collected through the various cost recovery mechanisms;
Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $3.6 million;
Net cash flows from changes in propane inventory, storage gas and other inventories decreased by approximately $2.6 million; and
Net cash flows from income taxes receivable increased by $1.3 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $51.8 million and $31.5 million during the three months ended March 31, 2021 and 2020, respectively, resulting in a decrease in cash flows of $20.3 million. Cash paid for capital expenditures was $52.0 million for the first three months of 2021, compared to $35.2 million for the same period in 2020, resulting in decreased cash flows of $16.8 million.

Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $26.5 million during the three months ended March 31, 2021 compared to $30.3 million of net cash used in financing activities over the same period in 2020, resulting in an increase in cash flows of $3.8 million. The increase in net cash provided by financing activities resulted primarily from the following:
Increased cash flows of $30.0 million from the absence of repayments of long-term debt;
Increased cash flows of $1.8 million as a result of changes in cash overdrafts in 2021;
Cash dividends of $7.5 million paid during the three months ended March 31, 2021, compared to $6.5 million for the three months ended March 31, 2020;
Decreased cash flows from short-term borrowing of $28.2 million under our line of credit arrangements; and
Increased cash flows of $1.9 million as a result of issuing shares of our common stock under the DRIP program.
Off-Balance Sheet Arrangements
The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of March 31, 2021 was $20.0 million. The aggregate amount guaranteed at March 31, 2021 was $8.3 million, with the guarantees expiring on various dates through March 30, 2022.
As of March 31, 2021, we have issued letters of credit totaling approximately $4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, to our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn upon these letters of credit as of March 31, 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.


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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 March 31, 2021:
 
 Payments Due by Period
Less than 1 year1 - 3 years3 - 5 yearsMore than 5 yearsTotal
(in thousands)     
Purchase obligations - Commodity (1)
$23,190 $16,546 $— $— $39,736 
Total$23,190 $16,546 $ $ $39,736 
 
(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 is subject to regulation by the Florida PSC. At March 31, 2021, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 5, Rates and Other Regulatory Activities, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1, Summary of Accounting Policies, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

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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. The fluctuation in interest rates expose us to potential increased cost we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. We utilize interest rate swap agreements to mitigate short-term borrowing rate risk. Additional information about our long-term debt and short-term borrowing is disclosed in Note 15, Long-Term Debt, and Note 16, Short-Term Borrowings, respectively, in the condensed consolidated financial statements.

COMMODITY PRICE RISK

Regulated Energy Segment

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

Unregulated Energy Segment

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

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

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

The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2020 to March 31, 2021:
(in thousands)Balance at December 31, 2020Increase (Decrease) in Fair Market ValueLess Amounts SettledBalance at March 31, 2021
Sharp$3,182 $3,285 $(3,047)$3,420 
Total$3,182 $3,285 $(3,047)$3,420 
There were no changes in methods of valuations during the three months ended March 31, 2021.

The following is a summary of fair market value of financial derivatives as of March 31, 2021, by method of valuation and by maturity for each fiscal year period.
(in thousands)20212022202320242025Total Fair Value
Price based on Mont Belvieu - Sharp$2,071 $1,279 $86 $(16)$— $3,420 
Total$2,071 $1,279 $86 $(16)$— $3,420 

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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 March 31, 2021. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 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 March 31, 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. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial, also may affect Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact 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
PeriodPurchasedper Share
or Programs (2)
or Programs (2)
January 1, 2021
through January 31, 2021(1)
440 $103.54 — — 
February 1, 2021
through February 28, 2021
    
March 1, 2021
through March 31, 2021
 
Total440 $103.54   
 
(1) Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts for certain directors and senior executives under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 9, Employee Benefit Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2020. During the quarter ended March 31, 2021, 440 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
 
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.
104Cover 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: May 4, 2021


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