CHESAPEAKE UTILITIES CORP 10-Q/A

Item 1. Financial Statements Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Income (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands, except shares and per share data) Operating Revenues Regulated Energy $ 80,910 $ 73,518 $ 202,107 $ 176,473 Unregulated Energy and other 30,172 23,533 100,161 73,268 Total Operating Revenues 111,082 97,051 302,268 249,741 Operating Expenses Regulated Energy cost of sales 14,447 16,387 57,491 51,219 Unregulated Energy and other cost of sales 12,254 6,575 43,506 24,611 Operations 36,371 34,605 75,810 70,557 Maintenance 4,259 4,143 8,300 7,979 Gain from settlement — ( 130 ) — ( 130 ) Depreciation and amortization 15,298 12,247 30,662 24,500 Other taxes 5,875 5,247 12,324 10,894 Total Operating Expenses 88,504 79,074 228,093 189,630 Operating Income 22,578 17,977 74,175 60,111 Other income (expense), net 1,456 ( 279 ) 1,841 3,039 Interest charges 5,054 5,054 10,159 10,868 Income from Continuing Operations Before Income Taxes 18,980 12,644 65,857 52,282 Income Taxes on Continuing Operations 5,165 1,983 17,570 12,580 Income from Continuing Operations 13,815 10,661 48,287 39,702 Income (Loss) from Discontinued Operations, Net of Tax ( 2 ) 295 ( 8 ) 184 Net Income $ 13,813 $ 10,956 $ 48,279 $ 39,886 Weighted Average Common Shares Outstanding: Basic 17,546,346 16,448,490 17,516,273 16,431,724 Diluted 17,616,496 16,503,603 17,585,006 16,487,807 Basic Earnings Per Share of Common Stock: Earnings from Continuing Operations $ 0.79 $ 0.65 $ 2.76 $ 2.42 Earnings from Discontinued Operations — 0.02 — 0.01 Basic Earnings Per Share of Common Stock $ 0.79 $ 0.67 $ 2.76 $ 2.43 Diluted Earnings Per Share of Common Stock: Earnings from Continuing Operations $ 0.78 $ 0.64 $ 2.75 $ 2.41 Earnings from Discontinued Operations — 0.02 — 0.01 Diluted Earnings Per Share of Common Stock $ 0.78 $ 0.66 $ 2.75 $ 2.42 The accompanying notes are an integral part of these financial statements. 1 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Comprehensive Income (Unaudited) Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands) Net Income $ 13,813 $ 10,956 $ 48,279 $ 39,886 Other Comprehensive Income (Loss), net of tax: Employee Benefits, net of tax: Amortization of prior service cost, net of tax of $(5), $(5), $(10) and $(10), respectively ( 14 ) ( 14 ) ( 28 ) ( 28 ) Net gain, net of tax of $28, $28, $53 and $55, respectively 78 80 156 160 Cash Flow Hedges, net of tax: Unrealized gain on commodity contract cash flow hedges, net of tax of $1,193, $651, $1,257 and $653, respectively 3,126 1,703 3,291 1,710 Unrealized gain/(loss) on interest rate swap cash flow hedges, net of tax of $2, $(14), $1 and $(14), respectively 6 ( 37 ) 4 ( 37 ) Total Other Comprehensive Income, net of tax 3,196 1,732 3,423 1,805 Comprehensive Income $ 17,009 $ 12,688 $ 51,702 $ 41,691 The accompanying notes are an integral part of these financial statements. 2 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited) Assets June 30, 2021 December 31, 2020 (in thousands, except shares and per share data) Property, Plant and Equipment Regulated Energy $ 1,643,904 $ 1,577,576 Unregulated Energy 309,139 300,647 Other businesses and eliminations 34,767 30,769 Total property, plant and equipment 1,987,810 1,908,992 Less: Accumulated depreciation and amortization ( 393,111 ) ( 368,743 ) Plus: Construction work in progress 78,187 60,929 Net property, plant and equipment 1,672,886 1,601,178 Current Assets Cash and cash equivalents 5,011 3,499 Trade and other receivables 45,206 61,675 Less: Allowance for credit losses ( 3,895 ) ( 4,785 ) Trade and other receivables, net 41,311 56,890 Accrued revenue 13,370 21,527 Propane inventory, at average cost 6,076 5,906 Other inventory, at average cost 6,524 5,539 Regulatory assets 9,429 10,786 Storage gas prepayments 2,385 2,455 Income taxes receivable 8,371 12,885 Prepaid expenses 9,497 13,239 Derivative assets, at fair value 8,056 3,269 Other current assets 523 436 Total current assets 110,553 136,431 Deferred Charges and Other Assets Goodwill 38,803 38,731 Other intangible assets, net 7,625 8,292 Investments, at fair value 11,745 10,776 Operating lease right-of-use assets 10,020 11,194 Regulatory assets 109,244 113,806 Receivables and other deferred charges 11,464 12,079 Total deferred charges and other assets 188,901 194,878 Total Assets $ 1,972,340 $ 1,932,487 The accompanying notes are an integral part of these financial statements. 3 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Balance Sheets (Unaudited) Capitalization and Liabilities June 30, 2021 December 31, 2020 (in thousands, except shares and per share data) Capitalization Stockholders’ equity Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding $ — $ — Common stock, par value $0.4867 per share (authorized 50,000,000 shares) 8,550 8,499 Additional paid-in capital 357,520 348,482 Retained earnings 374,936 342,969 Accumulated other comprehensive income (loss) 558 ( 2,865 ) Deferred compensation obligation 7,203 5,679 Treasury stock ( 7,203 ) ( 5,679 ) Total stockholders’ equity 741,564 697,085 Long-term debt, net of current maturities 498,450 508,499 Total capitalization 1,240,014 1,205,584 Current Liabilities Current portion of long-term debt 13,600 13,600 Short-term borrowing 169,294 175,644 Accounts payable 49,408 60,253 Customer deposits and refunds 33,983 33,302 Accrued interest 2,697 2,905 Dividends payable 8,433 7,683 Accrued compensation 10,767 13,994 Regulatory liabilities 13,911 6,284 Derivative liabilities, at fair value 351 127 Other accrued liabilities 19,812 15,240 Total current liabilities 322,256 329,032 Deferred Credits and Other Liabilities Deferred income taxes 219,490 205,388 Regulatory liabilities 143,681 142,736 Environmental liabilities 3,904 4,299 Other pension and benefit costs 29,463 30,673 Operating lease - liabilities 8,719 9,872 Deferred investment tax credits and other liabilities 4,813 4,903 Total deferred credits and other liabilities 410,070 397,871 Environmental and other commitments and contingencies (Notes 6 and 7) Total Capitalization and Liabilities $ 1,972,340 $ 1,932,487 The accompanying notes are an integral part of these financial statements. 4 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Cash Flows (Unaudited) Six Months Ended June 30, 2021 2020 (in thousands) Operating Activities Net income $ 48,279 $ 39,886 Adjustments to reconcile net income to net cash provided by operating activities: Depreciation and amortization 30,662 24,500 Depreciation and accretion included in other costs 5,061 4,807 Deferred income taxes 12,810 12,232 Gain on sale of discontinued operations — ( 200 ) Realized gain on commodity contracts and sale of assets ( 5,342 ) ( 3,496 ) Unrealized (gain) loss on investments/commodity contracts ( 988 ) 130 Employee benefits and compensation ( 346 ) 21 Share-based compensation 3,315 2,322 Changes in assets and liabilities: Accounts receivable and accrued revenue 23,664 11,455 Propane inventory, storage gas and other inventory ( 1,085 ) 4,140 Regulatory assets/liabilities, net 7,711 4,133 Prepaid expenses and other current assets 2,789 6,016 Accounts payable and other accrued liabilities 6,563 ( 1,604 ) Income taxes (payable) receivable 4,514 ( 1,480 ) Customer deposits and refunds 681 ( 232 ) Accrued compensation ( 3,397 ) ( 7,086 ) Other assets and liabilities, net ( 675 ) ( 3,866 ) Net cash provided by operating activities 134,216 91,678 Investing Activities Property, plant and equipment expenditures ( 104,631 ) ( 82,779 ) Proceeds from sale of assets 497 4,273 Proceeds from the sale of discontinued operations — 200 Environmental expenditures ( 395 ) ( 1,948 ) Net cash used in investing activities ( 104,529 ) ( 80,254 ) Financing Activities Common stock dividends ( 15,047 ) ( 12,976 ) Issuance of stock under the Dividend Reinvestment Plan, net of offering fees 4,799 359 Tax withholding payments related to net settled stock compensation ( 1,478 ) ( 977 ) Change in cash overdrafts due to outstanding checks ( 1,101 ) ( 1,690 ) Net advances (repayments) under line of credit agreements ( 5,249 ) 40,578 Repayment of long-term debt, net of offering fees — ( 13 ) Repayment of long-term debt ( 10,099 ) ( 40,100 ) Net cash used in financing activities ( 28,175 ) ( 14,819 ) Net Increase (Decrease) in Cash and Cash Equivalents 1,512 ( 3,395 ) Cash and Cash Equivalents—Beginning of Period 3,499 6,985 Cash and Cash Equivalents—End of Period $ 5,011 $ 3,590 The accompanying notes are an integral part of these financial statements. 5 Table of Contents Chesapeake Utilities Corporation and Subsidiaries Condensed Consolidated Statements of Stockholders’ Equity (Unaudited) Common Stock (1) (in thousands, except shares and per share data) Number of Shares (2) Par Value Additional Paid-In Capital Retained Earnings Accumulated Other Comprehensive Income/(Loss) Deferred Compensation Treasury Stock Total Balance at March 31, 2020 16,433,105 $ 7,998 $ 259,521 $ 322,804 $ ( 6,194 ) $ 5,468 $ ( 5,468 ) $ 584,129 Net income — — — 10,956 — — — 10,956 Other comprehensive gain — — — — 1,732 — — 1,732 Dividend declared ($0.440 per share) — — — ( 7,306 ) — — — ( 7,306 ) Dividend reinvestment plan 21,833 11 1,921 — — — — 1,932 Share-based compensation and tax benefit (3)(4) 8,870 4 1,830 — — — — 1,834 Treasury stock activities — — — — — 191 ( 191 ) — Balance at June 30, 2020 16,463,808 $ 8,013 $ 263,272 $ 326,454 $ ( 4,462 ) $ 5,659 $ ( 5,659 ) $ 593,277 Balance at December 31, 2019 16,403,776 $ 7,984 $ 259,253 $ 300,607 $ ( 6,267 ) $ 4,543 $ ( 4,543 ) $ 561,577 Net income — — — 39,886 — — — 39,886 Other comprehensive income — — — — 1,805 — — 1,805 Dividend declared ($0.845 per share) — — — ( 14,009 ) — — — ( 14,009 ) Dividend reinvestment plan 25,576 13 2,273 — — — — 2,286 Share-based compensation and tax benefit (3) (4) 34,456 16 1,746 — — — — 1,762 Treasury stock activities — — — — — 1,116 ( 1,116 ) — Cumulative effect of the adoption of ASU 2016-13 — — — ( 30 ) — — — ( 30 ) Balance at June 30, 2020 16,463,808 $ 8,013 $ 263,272 $ 326,454 $ ( 4,462 ) $ 5,659 $ ( 5,659 ) $ 593,277 Balance at March 31, 2021 17,521,493 $ 8,528 $ 350,875 $ 369,623 $ ( 2,638 ) $ 6,992 $ ( 6,992 ) $ 726,388 Net income — — — 13,813 — — — 13,813 Other comprehensive income — — — — 3,196 — — 3,196 Dividend declared ($0.480 per share) — — — ( 8,500 ) — — — ( 8,500 ) Dividend reinvestment plan 39,605 19 4,602 — — — — 4,621 Share-based compensation and tax benefit (3) (4) 6,830 3 2,043 — — — — 2,046 Treasury stock activities — — — — — 211 ( 211 ) — Balance at June 30, 2021 17,567,928 $ 8,550 $ 357,520 $ 374,936 $ 558 $ 7,203 $ ( 7,203 ) $ 741,564 Balance at December 31, 2020 17,461,841 8,499 348,482 342,969 ( 2,865 ) 5,679 ( 5,679 ) $ 697,085 Net income — — — 48,279 — — — 48,279 Other comprehensive income — — — — 3,423 — — 3,423 Dividend declared ($0.920 per share) — — — ( 16,312 ) — — — ( 16,312 ) Dividend reinvestment plan 60,116 29 6,806 — — — — 6,835 Share-based compensation and tax benefit (3) (4) 45,971 22 2,232 — — — — 2,254 Treasury stock activities — — — — — 1,524 ( 1,524 ) — Balance at June 30, 2021 17,567,928 $ 8,550 $ 357,520 $ 374,936 $ 558 $ 7,203 $ ( 7,203 ) $ 741,564 (1) 2,000,000 shares of preferred stock at $ 0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity. (2) Includes 117,193 , 105,087 , 107,141 , and 95,329 shares at June 30, 2021, December 31, 2020, June 30, 2020 and December 31, 2019, respectively, held in a Rabbi Trust related to our Non-Qualified Deferred Compensation Plan. (3) Includes amounts for shares issued for directors’ compensation. (4) The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2021 and 2020, we withheld 14,020 and 10,319 shares, respectively, for employee taxes. The accompanying notes are an integral part of these financial statements. 6 Table of Contents N OTES TO C ONDENSED C ONSOLIDATED F INANCIAL S TATEMENTS (U NAUDITED ) 1. Summary of Accounting Policies Basis of Presentation References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure. The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2020. In the opinion of management, these financial statements reflect all adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented. Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation. Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures. Effects of COVID-19 In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects while adhering to the social distancing restrictions that were in place. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May 2021 followed by Delaware and Maryland in July 2021, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of the new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities. Refer to Note 5 , Rates and Other Regulatory Activities , for further information on the regulated assets established as a result of the incremental expenses incurred associated with COVID-19. FASB Statements and Other Authoritative Pronouncements There are no new accounting pronouncements issued that are applicable to us. 7 Table of Contents 2. Calculation of Earnings Per Share Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Income from Continuing Operations $ 13,815 $ 10,661 $ 48,287 $ 39,702 Income/(Loss) from Discontinued Operations ( 2 ) 295 ( 8 ) 184 Net Income $ 13,813 $ 10,956 $ 48,279 $ 39,886 Weighted average shares outstanding 17,546,346 16,448,490 17,516,273 16,431,724 Basic Earnings Per Share from Continuing Operations $ 0.79 $ 0.65 $ 2.76 $ 2.42 Basic Earnings Per Share from Discontinued Operations — 0.02 — 0.01 Basic Earnings Per Share $ 0.79 $ 0.67 $ 2.76 $ 2.43 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted shares outstanding—Basic 17,546,346 16,448,490 17,516,273 16,431,724 Effect of dilutive securities—Share-based compensation 70,150 55,113 68,733 56,083 Adjusted denominator—Diluted 17,616,496 16,503,603 17,585,006 16,487,807 Diluted Earnings Per Share from Continuing Operations $ 0.78 $ 0.64 $ 2.75 $ 2.41 Diluted Earnings Per Share from Discontinued Operations — 0.02 — 0.01 Diluted Earnings Per Share $ 0.78 $ 0.66 $ 2.75 $ 2.42 3. Acquisitions Escambia Meter Station Asset Purchase In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light for $ 7.5 million and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline which provide gas supply to a natural gas fired power plant owned by Florida Power & Light in Pensacola, Florida. Acquisition of Western Natural Gas In October 2020, Sharp acquired certain propane operating assets of Western Natural Gas, which provides propane distribution service throughout Jacksonville, Florida and the surrounding communities, for approximately $ 6.7 million, net of cash acquired. Additionally, the purchase price included $ 0.3 million of working capital. We recorded contingent consideration of $ 0.3 million related to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We accounted for this acquisition as a business combination within our Unregulated Energy segment beginning in the fourth quarter of 2020. There are multiple strategic benefits to this acquisition including it: (i) expanded our propane territory serviced in Florida and (ii) included an established customer base with additional opportunities for future growth. In connection with this acquisition, we recorded $ 3.5 million in property plant and equipment, $ 1.4 million in intangible assets associated with customer relationships and non-compete agreements and $ 1.8 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the fourth quarter of 2021. For the three months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $ 0.6 million and $ 0.1 million, respectively. For the six months ended June 30, 2021, Western Natural Gas generated operating revenue and income of $ 1.4 million and $ 0.3 million, respectively. Acquisition of Elkton Gas 8 Table of Contents In July 2020, we closed on the acquisition of Elkton Gas, which provides natural gas distribution service to approximately 7,000 residential and commercial customers within a franchised area of Cecil County, Maryland for approximately, $ 15.6 million, net of cash acquired. Additionally, the purchase price included $ 0.6 million of working capital. Elkton Gas’ territory is contiguous to our franchised service territory in Cecil County, Maryland. In connection with this acquisition, we recorded $ 15.9 million in property, plant and equipment, $ 0.6 million in accounts receivable, $ 2.6 million in other liabilities, $ 2.6 million in regulatory liabilities and $ 4.3 million in goodwill, all of which is deductible for income tax purposes. All of the assets and liabilities are recorded in the Regulated Energy segment. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions. The purchase price allocation will be finalized in the third quarter of 2021. For the three months ended June 30, 2021, Elkton Gas generated operating revenue and income of $ 0.5 million and $ 0.3 million, respectively. For the six months ended June 30, 2021, Elkton Gas generated operating revenue and income of $ 3.1 million and $ 0.9 million, respectively. 4. Revenue Recognition We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays our revenue from continuing operations by major source based on product and service type for the three months ended June 30, 2021 and 2020: 9 Table of Contents Three months ended June 30, 2021 Three months ended June 30, 2020 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 10,068 $ — $ — $ 10,068 $ 11,758 $ — $ — $ 11,758 Florida natural gas division 8,446 — — 8,446 7,231 — — 7,231 FPU electric distribution 18,898 — — 18,898 15,701 — — 15,701 FPU natural gas distribution 23,159 — — 23,159 19,498 — — 19,498 Maryland natural gas division 3,224 — — 3,224 3,979 — — 3,979 Sandpiper natural gas/propane operations 3,814 — — 3,814 2,858 — — 2,858 Elkton Gas 1,195 — — 1,195 — — — — Total energy distribution 68,804 — — 68,804 61,025 — — 61,025 Energy transmission Aspire Energy — 5,578 — 5,578 — 4,554 — 4,554 Aspire Energy Express 47 — — 47 — — — — Eastern Shore 18,617 — — 18,617 18,277 — — 18,277 Peninsula Pipeline 6,610 — — 6,610 5,361 — — 5,361 Total energy transmission 25,274 5,578 — 30,852 23,638 4,554 — 28,192 Energy generation Eight Flags — 4,173 — 4,173 — 3,694 — 3,694 Propane operations Propane delivery operations — 23,098 — 23,098 — 17,260 — 17,260 Energy delivery services Marlin Gas Services — 1,989 — 1,989 — 2,248 — 2,248 Other and eliminations Eliminations ( 13,168 ) ( 65 ) ( 4,734 ) ( 17,967 ) ( 11,145 ) ( 16 ) ( 4,340 ) ( 15,501 ) Other — — 133 133 — — 133 133 Total other and eliminations ( 13,168 ) ( 65 ) ( 4,601 ) ( 17,834 ) ( 11,145 ) ( 16 ) ( 4,207 ) ( 15,368 ) Total operating revenues (1) $ 80,910 $ 34,773 $ ( 4,601 ) $ 111,082 $ 73,518 $ 27,740 $ ( 4,207 ) $ 97,051 (1) Total operating revenues for the three months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $ 0.1 million and $ 0.09 million for our Regulated and Unregulated Energy segments, respectively, and $ 0.1 million and $ 0.04 million for our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees. The following table displays our revenue from continuing operations by major source based on product and service type for the six months ended June 30, 2021 and 2020: 10 Table of Contents Six months ended June 30, 2021 Six months ended June 30, 2020 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 43,340 $ — $ — $ 43,340 $ 38,325 $ — $ — $ 38,325 Florida natural gas division 17,402 — — 17,402 15,708 — — 15,708 FPU electric distribution 37,449 — — 37,449 29,920 — — 29,920 FPU natural gas distribution 50,020 — — 50,020 44,942 — — 44,942 Maryland natural gas division 13,690 — — 13,690 13,117 — — 13,117 Sandpiper natural gas/propane operations 11,885 — — 11,885 9,150 — — 9,150 Elkton Gas 3,830 — — 3,830 — — — — Total energy distribution 177,616 — — 177,616 151,162 — — 151,162 Energy transmission Aspire Energy — 18,484 — 18,484 — 14,335 — 14,335 Aspire Energy Express 93 — — 93 — — — — Eastern Shore 38,589 — — 38,589 37,556 — — 37,556 Peninsula Pipeline 13,077 — — 13,077 10,185 — — 10,185 Total energy transmission 51,759 18,484 — 70,243 47,741 14,335 — 62,076 Energy generation Eight Flags — 8,502 — 8,502 — 8,017 — 8,017 Propane operations Propane delivery operations — 78,361 — 78,361 — 55,882 — 55,882 Energy delivery services Marlin Gas Services — 4,340 — 4,340 — 3,557 — 3,557 Other and eliminations Eliminations ( 27,268 ) ( 156 ) ( 9,635 ) ( 37,059 ) ( 22,430 ) ( 39 ) ( 8,749 ) ( 31,218 ) Other — 265 265 — — 265 265 Total other and eliminations ( 27,268 ) ( 156 ) ( 9,370 ) ( 36,794 ) ( 22,430 ) ( 39 ) ( 8,484 ) ( 30,953 ) Total operating revenues (1) $ 202,107 $ 109,531 $ ( 9,370 ) $ 302,268 $ 176,473 $ 81,752 $ ( 8,484 ) $ 249,741 (1) Total operating revenues for the six months ended June 30, 2021, include other revenue (revenues from sources other than contracts with customers) of $( 0.2 ) million and $ 0.2 million for our Regulated and Unregulated Energy segments, respectively, and $ 0.8 million and $ 0.1 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2020. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees. 11 Table of Contents Contract balances The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2021 and December 31, 2020 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Non-current) Contract Liabilities (Current) (in thousands) Balance at 12/31/2020 $ 55,600 $ 18 $ 4,816 $ 644 Balance at 6/30/2021 37,341 18 5,179 342 Increase (decrease) $ ( 18,259 ) $ — $ 363 $ ( 302 ) Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and primarily relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement. At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the condensed consolidated balance sheets and relate to non-refundable prepaid fixed fees for our Mid-Atlantic propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three months ended June 30, 2021 and 2020, we recognized revenue of $ 0.2 million. For each of the six months ended June 30, 2021 and 2020, we recognized revenue of $ 0.6 million. Remaining performance obligations Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations, at June 30, 2021, are expected to be recognized as follows: (in thousands) 2021 2022 2023 2024 2025 2026 2027 and thereafter Eastern Shore and Peninsula Pipeline $ 18,561 $ 31,914 $ 24,570 $ 22,402 $ 21,550 $ 20,494 $ 176,316 Natural gas distribution operations 3,005 6,501 6,039 5,807 5,266 5,062 33,448 FPU electric distribution 489 652 652 652 275 275 550 Total revenue contracts with remaining performance obligations $ 22,055 $ 39,067 $ 31,261 $ 28,861 $ 27,091 $ 25,831 $ 210,314 5. Rates and Other Regulatory Activities Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively. Delaware There were no material regulatory activities in the second quarter of 2021. Maryland Strategic Infrastructure Development and Enhancement (“STRIDE”) plan: In March 2021, Elkton Gas filed a strategic infrastructure development and enhancement plan with the Maryland PSC. The STRIDE plan proposes to 12 Table of Contents increase the speed of Elkton Gas' Aldyl-A pipeline replacement program and to recover the costs of the plan in the form of fixed charge rider through a proposed five-year surcharge. Under Elkton Gas’ proposed STRIDE plan, the Aldyl-A pipelines would be replaced by 2023. In June 2021, we reached a settlement with the Maryland PSC Staff and the Maryland Office of the Peoples Counsel. The settlement agreement is currently being reviewed by a Maryland Public Utilities Law Judge, who must issue a final recommendation to the Commission. A final order is expected in August 2021. Florida Hurricane Michael: In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida and caused widespread and severe damage to FPU's infrastructure resulting in the loss of electric service to 100 percent of its customers in the Northwest Florida service territory. In August 2019, FPU filed a limited proceeding requesting recovery of storm-related costs associated with Hurricane Michael (capital and expenses) through a change in base rates. FPU also requested treatment and recovery of certain storm-related costs as regulatory assets for items currently not allowed to be recovered through the storm reserve as well as the recovery of capital replaced as a result of the storm. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. In March 2020, we filed an update to our original filing to account for actual charges incurred through December 2019, revised the amortization period of the storm-related costs from 30 years as originally requested to 10 years, and included costs related to Hurricane Dorian of approximately $ 1.2 million in this filing. In late 2019, the Florida PSC approved an interim rate increase, subject to refund, effective January 1, 2020, associated with the restoration effort following Hurricane Michael. We fully reserved these interim rates, pending a final resolution and settlement of the limited proceeding. In September 2020, the Florida PSC approved a settlement agreement between FPU and the Office of the Public Counsel regarding final cost recovery and rates associated with Hurricane Michael. The settlement agreement allowed us to: (a) refund the over-collection of interim rates through the fuel clause; (b) record regulatory assets for storm costs in the amount of $ 45.8 million including interest which will be amortized over six years; (c) recover these storm costs through a surcharge for a total of $ 7.7 million annually; and (d) collect an annual increase in revenue of $ 3.3 million to recover capital costs associated with new plant and a regulatory asset for cost of removal and undepreciated plant. The new base rates and storm surcharge were effective on November 1, 2020. Electric Depreciation Study: In September 2019, FPU filed a petition, with the Florida PSC, for approval of its consolidated electric depreciation rates. The petition was joined to the Hurricane Michael docket, and was approved at the Florida PSC Agenda in September 2020. The approved rates were retroactively applied effective January 1, 2020. West Palm Beach Expansion Project: In June 2019, Peninsula Pipeline filed with the Florida PSC for approval of its Transportation Service Agreement with FPU. Peninsula Pipeline will construct several new interconnection points and pipeline expansions in Palm Beach County, Florida, which will enable FPU to serve an industrial research park and several new residential developments. Peninsula Pipeline will provide transportation service to FPU, increasing reliability, system pressure as well as introducing diversity in fuel source for natural gas to serve the increased demand in these areas. The petition was approved by the Florida PSC at the August 6, 2019 Agenda. Interim services began in the fourth quarter of 2019. We expect to complete the remainder of the project in phases through the fourth quarter of 2021. Winter Haven Expansion Project: In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use the additional firm service to support new incremental load due to growth in the area, including providing service to a new can manufacturing facility, as well as provide reliability and operational benefits to CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. Escambia Meter Station: In June 2021, Peninsula Pipeline purchased the Escambia Meter Station from Florida Power and Light and entered into a Transportation Service Agreement with Gulf Power Company to provide up to 530,000 Dts/d of firm service from an interconnect with FGT to Florida Power & Light Company’s Crist Lateral pipeline, which provides gas supply to their natural gas fired power plant owned by Florida Power & Light in Pensacola, 13 Table of Contents Florida. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021. Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline will construct approximately 11.33 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021. Eastern Shore Del-Mar Energy Pathway Project: In December 2019, the FERC issued an order approving the construction of the Del-Mar Energy Pathway project. The order approved the construction and operation of new facilities that will provide an additional 14,300 Dts/d of firm service to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Wicomico and Somerset Counties in Maryland; and new pressure control and delivery stations in these counties. The benefits of this project include: (i) additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. Construction on the project began in January 2020, and Eastern Shore anticipates that this project will be fully in-service by the end of 2021. Capital Cost Surcharge: In June 2021, Eastern Shore filed with the FERC a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge is an approved item in the settlement of Eastern Shore’s last rate case. In conjunction with the filing of this surcharge, pursuant to the settlement agreement, a true-up of the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge will become effective July 15, 2021. COVID-19 Impact In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued into 2021. Chesapeake Utilities is considered an “essential business,” which has allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place. In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred support the ongoing delivery of our essential services during these unprecedented times. At this time, restrictions continue to be lifted as vaccines have become more available in the United States. For example, the state of emergency in Florida was terminated in May followed by Delaware and Maryland in July, resulting in reduced restrictions. Despite these positive state orders and in light of the continued emergence and growing prevalence of new variants of COVID-19, we continue to operate under our pandemic response plan, monitor developments affecting employees, customers, suppliers, stockholders and take all precautions warranted to operate safely and to comply with the CDC, Occupational Safety and Health Administration, in order to protect our employees, customers and the communities. In April 2020, the Maryland PSC issued an order that authorized utilities to establish a regulatory asset to record prudently incurred incremental costs related to COVID-19, beginning on March 16, 2020. The Maryland PSC found that the creation of a regulatory asset for COVID-19 related expenses will facilitate the recovery of those costs prudently incurred to serve customers during this period, and that the deferral of such costs is appropriate because the 14 Table of Contents current catastrophic health emergency is outside the control of the utility and is a non-recurring event. The Maryland PSC is working on a plan that will provide funds to assist with the repayment of arrearages for customers in need and those impacted by COVID-19. Chesapeake Utilities – Maryland Division, Sandpiper Energy, and Elkton Gas will receive funds in the third quarter of 2021 to credit the accounts of those customers experiencing financial hardship in becoming current on their past due balances. In May 2020, the Delaware PSC issued an order that authorized Delaware utilities to establish a regulatory asset to record COVID-19 related incremental costs incurred to ensure customers have essential utility services, for the period beginning on March 24, 2020 and ending 30 days after the state of emergency ends. The state of emergency was lifted July 12, 2021. The creation of the regulatory asset for COVID-19 related costs offers utilities the ability to seek recovery of those costs. In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset will allow us to seek recovery of these costs in the next base rate proceedings. In November 2020, the Office of Public Counsel filed a protest to the order approving the establishment of this regulatory asset treatment, contending that the order should be a reversed or modified and to request a hearing on the protest. The Company’s Florida regulated business units reached a settlement with Office of Public Counsel in June 2021. The settlement allows the units to establish a regulatory asset in a total amount of $ 2.1 million as of June 30, 2021. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units will amortize the amount over two years and recover the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric division. This settlement agreement was approved by the Florida PSC on July 8, 2021. In the fourth quarter of 2020, we began recording regulatory assets based on the net incremental expense resulting from the COVID-19 pandemic for our natural gas distribution and electric business units as authorized by the Delaware, Maryland and Florida PSCs. As of June 30, 2021 our total COVID-19 regulatory asset balance was $ 1.6 million. 15 Table of Contents Summary TCJA Table Customer rates for our regulated businesses were adjusted as approved by the regulators, prior to 2020 with the exception of Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarizes the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of June 30, 2021 and December 31, 2020: Amount (in thousands) Operation and Regulatory Jurisdiction June 30, 2021 December 31, 2020 Status Eastern Shore (FERC) $ 34,190 $ 34,190 Will be addressed in Eastern Shore's next rate case filing. Delaware Division (Delaware PSC) $ 12,660 $ 12,728 PSC approved amortization of ADIT in January 2019. Maryland Division (Maryland PSC) $ 3,905 $ 3,970 PSC approved amortization of ADIT in May 2018. Sandpiper Energy (Maryland PSC) $ 3,684 $ 3,713 PSC approved amortization of ADIT in May 2018. Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC) $ 8,108 $ 8,184 PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019. FPU Natural Gas (excludes Fort Meade and Indiantown) (Florida PSC) $ 19,149 $ 19,257 Same treatment on a net basis as Chesapeake Florida Gas Division (above). FPU Fort Meade and Indiantown Divisions $ 303 $ 309 Same treatment on a net basis as Chesapeake Florida Gas Division (above). FPU Electric (Florida PSC) $ 6,569 $ 6,694 In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates. Elkton Gas (Maryland PSC) $ 1,124 $ 1,124 PSC approved amortization of ADIT in March 2018. 6. Environmental Commitments and Contingencies We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances. MGP Sites We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. As of June 30, 2021 and December 31, 2020, we had approximately $ 5.6 million and $ 5.9 million, respectively, in environmental liabilities related to FPU’s four MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and through customer rates, up to $ 14.0 million of its environmental costs related to its MGP sites. As of June 30, 2021 and December 31, 2020, we had recovered approximately $ 12.6 million and $ 12.4 million, respectively, leaving approximately $ 1.4 million and $ 1.6 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers. Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. Remediation is ongoing for the MGPs in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $ 0.3 million to $ 0.9 million for these three sites. The 16 Table of Contents Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial. The following is a summary of our remediation status and estimated costs to implement clean-up of our West Palm Beach Florida site: Status Estimated Clean-Up Costs Remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of the site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected be completed in 2022. Between $3.3 million to $14.2 million, including costs associated with the relocation of FPU’s operations at this site, and any potential costs associated with future redevelopment of the properties. 7. Other Commitments and Contingencies Natural Gas and Electric In March 2020, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2020 and expire in March 2023. FPU natural gas distribution operations and Eight Flags have entered into separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements are for a 10 -year term that commenced in November 2020 and expire in October 2030. Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency. FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2021, FPU was in compliance with all of the requirements of its fuel supply contracts. Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20 -year power purchase agreement for distribution to our electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20 -year contract, to the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline. Corporate Guarantees The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of June 30, 2021 was $ 20.0 million. The aggregate amount guaranteed at June 30, 2021 was approximately $ 8.0 million with the guarantees expiring on various dates through March 30, 2022. 17 Table of Contents As of June 30, 2021, we have issued letters of credit totaling approximately $ 4.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and our current and previous primary insurance carriers. These letters of credit have various expiration dates through October 5, 2021. We have not drawn on these letters of credit as of June 30, 2021 and do not anticipate that the counterparties will draw upon these letters of credit. We expect that they will be renewed to the extent necessary in the future. 8. Segment Information We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. Our operations are entirely domestic and are comprised of two reportable segments: • Regulated Energy . Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore. • Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions subsidiary. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. These operations are unregulated as to their rates and services. Effective in the third quarter of 2019, the natural gas marketing and related services subsidiary (PESCO), previously reported in the Unregulated Energy segment, was reflected in discontinued operations. The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments: 18 Table of Contents Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy $ 80,374 $ 73,044 $ 201,095 $ 175,512 Unregulated Energy 30,708 24,007 101,173 74,229 Total operating revenues, unaffiliated customers $ 111,082 $ 97,051 $ 302,268 $ 249,741 Intersegment Revenues (1) Regulated Energy $ 536 $ 474 $ 1,012 $ 961 Unregulated Energy 4,065 3,733 8,358 7,523 Other businesses 133 133 265 265 Total intersegment revenues $ 4,734 $ 4,340 $ 9,635 $ 8,749 Operating Income Regulated Energy $ 22,808 $ 18,006 $ 55,673 $ 45,894 Unregulated Energy ( 445 ) 281 18,660 14,142 Other businesses and eliminations 215 ( 310 ) ( 158 ) 75 Operating income 22,578 17,977 74,175 60,111 Other income (expense), net 1,456 ( 279 ) 1,841 3,039 Interest charges 5,054 5,054 10,159 10,868 Income from Continuing Operations before Income Taxes 18,980 12,644 65,857 52,282 Income Taxes on Continuing Operations 5,165 1,983 17,570 12,580 Income from Continuing Operations 13,815 10,661 48,287 39,702 Income (Loss) from Discontinued Operations, Net of Tax ( 2 ) 295 ( 8 ) 184 Net Income $ 13,813 $ 10,956 $ 48,279 $ 39,886 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) June 30, 2021 December 31, 2020 Identifiable Assets Regulated Energy segment $ 1,568,136 $ 1,547,619 Unregulated Energy segment 359,971 347,665 Other businesses and eliminations 44,233 37,203 Total identifiable assets $ 1,972,340 $ 1,932,487 19 Table of Contents 9. Stockholders' Equity Common Stock Issuances In June 2020, we filed a shelf registration statement with the SEC to facilitate the issuance of our common stock from time to time. In August 2020, we filed a prospectus supplement under the shelf registration statement for an ATM equity program under which we may issue and sell shares of our common stock up to an aggregate offering price of $ 75.0 million. In the third and fourth quarters of 2020, we issued 0.7 million shares of common stock at an average price per share of $ 82.93 and received net proceeds of approximately $ 61.0 million, after deducting commissions and other fees of $ 1.5 million. We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. In the third and fourth quarters of 2020, we issued 0.3 million shares at an average price per share of $ 86.12 and received net proceeds of $ 22.0 million under the DRIP. In the first six months of 2021, we issued less than 0.1 million shares at an average price per share of $ 113.51 and received net proceeds of $ 4.5 million under the DRIP. We used the net proceeds from the ATM equity program and the DRIP, after deducting the commissions or other fees and related offering expenses payable by us, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes. Accumulated Other Comprehensive Gain (Loss) Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive gain (loss) as of June 30, 2021 and 2020. All amounts in the following tables are presented net of tax. Defined Benefit Commodity Interest Rate Pension and Contracts Swap Postretirement Cash Flow Cash Flow Plan Items Hedges Hedges Total (in thousands) As of December 31, 2020 $ ( 5,146 ) $ 2,309 $ ( 28 ) $ ( 2,865 ) Other comprehensive income before reclassifications — 5,825 23 5,848 Amounts reclassified from accumulated other comprehensive income (loss) 128 ( 2,534 ) ( 19 ) ( 2,425 ) Net current-period other comprehensive income 128 3,291 4 3,423 As of June 30, 2021 $ ( 5,018 ) $ 5,600 $ ( 24 ) $ 558 (in thousands) As of December 31, 2019 $ ( 4,933 ) $ ( 1,334 ) $ — $ ( 6,267 ) Other comprehensive income/(loss) before reclassifications — 2,770 ( 29 ) $ 2,741 Amounts reclassified from accumulated other comprehensive income/(loss) 132 ( 1,060 ) ( 8 ) ( 936 ) Net prior-period other comprehensive income/(loss) 132 1,710 ( 37 ) 1,805 As of June 30, 2020 $ ( 4,801 ) $ 376 $ ( 37 ) $ ( 4,462 ) 20 Table of Contents The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2021 and 2020. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement. Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 19 $ 38 $ 38 Net loss (1) ( 106 ) ( 108 ) ( 209 ) ( 215 ) Total before income taxes ( 87 ) ( 89 ) ( 171 ) ( 177 ) Income tax benefit 23 23 43 45 Net of tax $ ( 64 ) $ ( 66 ) $ ( 128 ) $ ( 132 ) Gains on commodity contracts cash flow hedges: Propane swap agreements (2) $ 455 $ 238 $ 3,502 $ 1,465 Income tax expense ( 126 ) ( 66 ) ( 968 ) ( 405 ) Net of tax $ 329 $ 172 $ 2,534 $ 1,060 Gains on interest rate swap cash flow hedges: Interest rate swap agreements $ 22 $ 11 $ 26 $ 11 Income tax expense ( 6 ) ( 3 ) ( 7 ) ( 3 ) Net of tax $ 16 $ 8 $ 19 $ 8 Total reclassifications for the period $ 281 $ 114 $ 2,425 $ 936 (1) These amounts are included in the computation of net periodic costs (benefits). See Note 10 , Employee Benefit Plans , for additional details. (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments , for additional details. Amortization of defined benefit pension and postretirement plan items are included in other expense, net gains and losses on propane swap agreements, natural gas swaps, and natural gas futures contracts are included in cost of sales, the realized gain or loss on interest rate swap agreements is recognized as a component of interest charges in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income. 10. Employee Benefit Plans Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2021 and 2020 are set forth in the following tables: 21 Table of Contents Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Three Months Ended June 30, 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 (in thousands) Interest cost $ 34 $ 46 $ 429 $ 518 $ 12 $ 16 $ 6 $ 8 $ 6 $ 10 Expected return on plan assets ( 40 ) ( 42 ) ( 830 ) ( 745 ) — — — — — — Amortization of prior service credit — — — — — — ( 19 ) ( 19 ) — — Amortization of net (gain) loss 60 65 155 135 7 5 10 12 ( 2 ) — Net periodic cost (benefit) 54 69 ( 246 ) ( 92 ) 19 21 ( 3 ) 1 4 10 Amortization of pre-merger regulatory asset — — — — — — — — — 2 Total periodic cost (benefit) $ 54 $ 69 $ ( 246 ) $ ( 92 ) $ 19 $ 21 $ ( 3 ) $ 1 $ 4 $ 12 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Six Months Ended June 30, 2021 2020 2021 2020 2021 2020 2021 2020 2021 2020 (in thousands) Interest cost $ 68 $ 92 $ 858 $ 1,036 $ 24 $ 32 $ 12 $ 16 $ 12 $ 20 Expected return on plan assets ( 80 ) ( 84 ) ( 1,660 ) ( 1,490 ) — — — — — — Amortization of prior service credit — — — — — — ( 38 ) ( 38 ) — — Amortization of net (gain) loss 120 130 310 270 14 10 18 24 ( 4 ) — Net periodic cost (benefit) 108 138 ( 492 ) ( 184 ) 38 42 ( 8 ) 2 8 20 Amortization of pre-merger regulatory asset — — — — — — — — — 4 Total periodic cost (benefit) $ 108 $ 138 $ ( 492 ) $ ( 184 ) $ 38 $ 42 $ ( 8 ) $ 2 $ 8 $ 24 We expect to record $ 0.7 million in pension and post-retirement benefits for 2021. The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss. In 2019, we executed a de-risking strategy for the Chesapeake Pension Plan. As a result of this strategy, we are planning to terminate the Chesapeake Pension Plan in the fourth quarter of 2021. The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2021 and 2020: For the Three Months Ended June 30, 2021 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ ( 19 ) $ — $ ( 19 ) Net loss 60 155 7 10 ( 2 ) 230 Total recognized in net periodic benefit cost 60 155 7 ( 9 ) ( 2 ) 211 Recognized from accumulated other comprehensive loss/(gain) (1) 60 29 7 ( 9 ) — 87 Recognized from regulatory asset — 126 — — ( 2 ) 124 Total $ 60 $ 155 $ 7 $ ( 9 ) $ ( 2 ) $ 211 22 Table of Contents For the Three Months Ended June 30, 2020 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ ( 19 ) $ — $ ( 19 ) Net loss 65 135 5 12 — 217 Total recognized in net periodic benefit cost 65 135 5 ( 7 ) — 198 Recognized from accumulated other comprehensive loss/(gain) (1) 65 26 5 ( 7 ) — 89 Recognized from regulatory asset — 109 — — — 109 Total $ 65 $ 135 $ 5 $ ( 7 ) $ — $ 198 For the Six Months Ended June 30, 2021 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ ( 38 ) $ — $ ( 38 ) Net loss 120 310 14 18 ( 4 ) 458 Total recognized in net periodic benefit cost 120 310 14 ( 20 ) ( 4 ) 420 Recognized from accumulated other comprehensive loss/(gain) (1) 120 58 14 ( 20 ) ( 1 ) 171 Recognized from regulatory asset — 252 — — ( 3 ) 249 Total $ 120 $ 310 $ 14 $ ( 20 ) $ ( 4 ) $ 420 For the Six Months Ended June 30, 2020 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ ( 38 ) $ — $ ( 38 ) Net loss 130 270 10 24 — 434 Total recognized in net periodic benefit cost 130 270 10 ( 14 ) — 396 Recognized from accumulated other comprehensive loss/(gain) (1) 130 52 10 ( 14 ) — 178 Recognized from regulatory asset — 218 — — — 218 Total $ 130 $ 270 $ 10 $ ( 14 ) $ — $ 396 (1) See Note 9 , Stockholders' Equity . During the three and six months ended June 30, 2021, we contributed approximately $ 0.1 million to the Chesapeake Pension Plan and approximately $ 0.5 million to the FPU Pension Plan. We expect to contribute approximately $ 0.3 million and $ 2.1 million, respectively, to the Chesapeake Pension Plan and FPU Pension Plans during 2021, which represents the minimum annual contribution payments required. The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2021 were immaterial and $ 0.1 million, respectively. We expect to pay total cash benefits of approximately $ 0.2 million under the Chesapeake SERP in 2021. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2021 were immaterial and $ 0.2 million, respectively. We estimate that approximately $ 0.2 million will be paid for such benefits under the Chesapeake Postretirement Plan in 2021. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2021, were immaterial. We estimate that approximately $ 0.1 million will be paid for such benefits under the FPU Medical Plan in 2021. 23 Table of Contents 11. Investments The investment balances at June 30, 2021 and December 31, 2020, consisted of the following: (in thousands) June 30, 2021 December 31, 2020 Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan) $ 11,723 $ 10,755 Investments in equity securities 22 21 Total $ 11,745 $ 10,776 We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $ 0.6 million and $ 1.4 million, respectively, in other income, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2021 and 2020, we recorded a net unrealized gain of approximately $ 1.0 million and a net unrealized loss of approximately $ 0.1 million, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust. 12. Share-Based Compensation Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period. The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2021 and 2020: Three Months Ended Six Months Ended June 30, June 30, 2021 2020 2021 2020 (in thousands) Awards to non-employee directors $ 192 $ 181 $ 380 $ 357 Awards to key employees 1,247 1,085 2,935 1,965 Total compensation expense 1,439 1,266 3,315 2,322 Less: tax benefit ( 384 ) ( 331 ) ( 885 ) ( 607 ) Share-based compensation amounts included in net income $ 1,055 $ 935 $ 2,430 $ 1,715 Non-employee Directors Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2021, after the most recent election of directors, each of our non-employee directors received an annual retainer of 683 shares of common stock under the SICP for service as a director through the 2022 Annual Meeting of Stockholders; accordingly, 6,830 shares, with a weighted average fair value of $ 117.11 per share, were issued and vested in 2021. At June 30, 2021, there was approximately $ 0.7 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May of 2022. Key Employees The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2021: 24 Table of Contents Number of Shares Weighted Average Fair Value Outstanding—December 31, 2020 186,878 $ 87.06 Granted 66,612 $ 102.73 Vested ( 53,147 ) $ 76.31 Expired ( 852 ) $ 74.85 Forfeited ( 5,384 ) $ 93.39 Outstanding—June 30, 2021 194,107 $ 94.61 In February 2021, we granted awards of 66,612 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2023. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of each market-based award granted. In March 2021, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in February 2021 for the performance period ended December 31, 2020, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 14,020 shares, based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $ 1.5 million. At June 30, 2021, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $ 23.4 million. At June 30, 2021, there was approximately $ 6.1 million of unrecognized compensation cost related to these awards, which will be recognized as expense for the remainder of 2021 through 2023. Stock Options There were no stock options outstanding or issued during the six months ended June 30, 2021 and 2020. 13. Derivative Instruments We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Our natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. We have also entered into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of June 30, 2021, our natural gas and electric distribution operations did not have any outstanding derivative contracts. Volume of Derivative Activity As of June 30, 2021, the volume of our commodity derivative contracts were as follows: Business unit Commodity Contract Type Quantity hedged (in millions) Designation Longest Expiration date of hedge Sharp Propane (gallons) Purchases 23.3 Cash flows hedges June 2024 Sharp Propane (gallons) Sales 5.0 Cash flows hedges March 2022 Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes that are expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in 25 Table of Contents June 2021 through June 2024) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $ 5.4 million from accumulated other comprehensive income to earnings during the next 12 -month period ended June 30, 2022. Interest Rate Swap Activities We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In the fourth quarter of 2020, we entered into interest rate swaps with notional amount of $ 60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $ 40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate. We designated and accounted for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges. We expect to reclassify less than $ 0.1 million from accumulated other comprehensive (loss) to earnings during the next 12 -month period ended June 30, 2022. Broker Margin Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp, with the balance related to the account is as follows: (in thousands) Balance Sheet Location June 30, 2021 December 31, 2020 Sharp Other Current Liabilities $ 4,808 $ 1,505 Financial Statements Presentation The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2021 and December 31, 2020, are as follows: Derivative Assets Fair Value As Of (in thousands) Balance Sheet Location June 30, 2021 December 31, 2020 Derivatives designated as fair value hedges Propane put options Derivative assets, at fair value $ — $ 14 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value 8,056 3,255 Total asset derivatives $ 8,056 $ 3,269 26 Table of Contents Derivative Liabilities Fair Value As Of (in thousands) Balance Sheet Location June 30, 2021 December 31, 2020 Derivatives designated as fair value hedges Propane put options Derivative liabilities, at fair value $ — $ 23 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value 317 64 Interest rate swap agreements Derivative liabilities, at fair value 34 40 Total liability derivatives $ 351 $ 127 The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows: Amount of Gain (Loss) on Derivatives: Location of Gain For the Three Months Ended June 30, For the Six Months Ended June 30, (in thousands) (Loss) on Derivatives 2021 2020 2021 2020 Derivatives designated as fair value hedges Propane put options Cost of sales $ — $ — $ ( 24 ) $ — Derivatives designated as cash flow hedges Propane swap agreements Cost of sales 455 238 3,502 1,465 Propane swap agreements Other comprehensive income 4,319 2,354 4,548 2,363 Interest rate swap agreements Interest expense 22 11 26 11 Interest rate swap agreements Other comprehensive income (loss) 8 ( 51 ) 5 ( 51 ) Total $ 4,804 $ 2,552 $ 8,057 $ 3,788 27 Table of Contents 14. Fair Value of Financial Instruments GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are the following: Fair Value Hierarchy Description of Fair Value Level Fair Value Technique Utilized Level 1 Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities Investments - equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities. Investments - mutual funds and other - The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares. Level 2 Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability Derivative assets and liabilities - The fair value of the propane put/call options, propane and interest rate swap agreements are measured using market transactions for similar assets and liabilities in either the listed or over-the-counter markets. Level 3 Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity) Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value. Financial Assets and Liabilities Measured at Fair Value The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2021 and December 31, 2020: Fair Value Measurements Using: As of June 30, 2021 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 2,191 — — 2,191 Investments—mutual funds and other 9,532 9,532 — — Total investments 11,745 9,554 — 2,191 Derivative assets 8,056 — 8,056 — Total assets $ 19,801 $ 9,554 $ 8,056 $ 2,191 Liabilities: Derivative liabilities $ 351 $ — $ 351 $ — 28 Table of Contents Fair Value Measurements Using: As of December 31, 2020 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 2,156 — — 2,156 Investments—mutual funds and other 8,599 8,599 — — Total investments 10,776 8,620 — 2,156 Derivative assets 3,269 — 3,269 — Total assets $ 14,045 $ 8,620 $ 3,269 $ 2,156 Liabilities: Derivative liabilities $ 127 $ — $ 127 $ — The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2021 and 2020: Six months ended June 30, 2021 2020 (in thousands) Beginning Balance $ 2,156 $ 803 Purchases and adjustments 70 226 Transfers — 1,345 Distribution ( 51 ) ( 50 ) Investment income 16 10 Ending Balance $ 2,191 $ 2,334 Investment income from the Level 3 investments is reflected in other expense, (net) in the condensed consolidated statements of income. At June 30, 2021, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required. Other Financial Assets and Liabilities Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its near-term maturities and because interest rates approximate current market rates (Level 3 measurement). At June 30, 2021, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $ 512.9 million, compared to the estimated fair value of $ 541.5 million. At December 31, 2020, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $ 523.0 million, compared to a fair value of approximately $ 548.5 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement. 29 Table of Contents 15. Long-Term Debt Our outstanding long-term debt is shown below: June 30, December 31, (in thousands) 2021 2020 Uncollateralized senior notes: 5.93% note, due October 31, 2023 $ 7,500 $ 9,000 5.68% note, due June 30, 2026 14,500 17,400 6.43% note, due May 2, 2028 4,900 5,600 3.73% note, due December 16, 2028 16,000 16,000 3.88% note, due May 15, 2029 40,000 45,000 3.25% note, due April 30, 2032 70,000 70,000 3.48% note, due May 31, 2038 50,000 50,000 3.58% note, due November 30, 2038 50,000 50,000 3.98% note, due August 20, 2039 100,000 100,000 2.98% note, due December 20, 2034 70,000 70,000 3.00% note, due July 15, 2035 50,000 50,000 2.96% note, due August 15, 2035 40,000 40,000 Less: debt issuance costs ( 850 ) ( 901 ) Total long-term debt 512,050 522,099 Less: current maturities ( 13,600 ) ( 13,600 ) Total long-term debt, net of current maturities $ 498,450 $ 508,499 . Shelf Agreements We have entered into Shelf Agreements with Prudential, MetLife and NYL, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at June 30, 2021: (in thousands) Total Borrowing Capacity Less: Amount of Debt Issued Less: Unfunded Commitments Remaining Borrowing Capacity Shelf Agreement Prudential Shelf Agreement (1) $ 370,000 $ ( 220,000 ) $ — $ 150,000 MetLife Shelf Agreement (1) 150,000 — — 150,000 NYL Shelf Agreement (1) 150,000 ( 140,000 ) — 10,000 Total Shelf Agreements as of June 30, 2021 $ 670,000 $ ( 360,000 ) $ — $ 310,000 (1) The Prudential, MetLife and NYL Shelf Agreements expire in April 2023, May 2023 and November 2021, respectively. The Uncollateralized Senior Notes, Shelf Agreements or Shelf Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries. 16. Short-Term Borrowings We are authorized by our Board of Directors to borrow up to $ 400.0 million of short-term debt, as required. At June 30, 2021 and December 31, 2020, we had $ 169.3 million and $ 175.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 1.11 percent and 1.28 percent. Included in the June 30, 2021 balance, is $ 100.0 million in short-term debt for which we have entered into interest rate swap agreements. In the fourth quarter of 2020, we entered into interest rate swaps with a notional amount of $ 60.0 million through December 2021 with pricing of 0.20 and 0.205 percent for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $ 40.0 million 30 Table of Contents through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest rate swaps are cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate. In September 2020, we entered into a $ 375.0 million syndicated Revolver with six participating lenders. As a result of entering into the Revolver, in September 2020, we terminated and paid all outstanding balances under the previously existing bilateral lines of credit and the previous revolving credit facility. The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of June 30, 2021, we are in compliance with this covenant. The Revolver expires on September 29, 2021 and is available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged. Our pricing is adjusted each quarter based upon total indebtedness to total capitalization ratio. As of June 30, 2021, the pricing under the Revolver included an unused commitment fee of 0.15 percent and an interest rate of 1.0 percent over LIBOR. Our available credit under the Revolver at June 30, 2021 was $ 200.9 million. As of June 30, 2021, we had issued $ 4.8 million in letters of credit to various counterparties under the syndicated Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under our syndicated Revolver. 17. Leases We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These lease arrangements enable us to better conduct business operations in the regions in which we operate. Office space is leased to provide adequate workspace for our employees in several locations throughout the Mid-Atlantic, Mid-West and in Florida. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. We also lease warehouses to store equipment and materials used in repairs and maintenance for our businesses. Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would not have resulted in material additional annual lease costs. Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our consolidated balance sheet at June 30, 2021, pertaining to the right-of-use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options. Our existing leases are not subject to any restrictions or covenants that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of June 30, 2021, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income: Three Months Ended Six Months Ended June 30, June 30, ( in thousands) Classification 2021 2020 2021 2020 Operating lease cost (1) Operations expense $ 515 $ 629 $ 1,038 $ 1,255 (1) Includes short-term leases and variable lease costs, which are immaterial . The following table presents the balance and classifications of our right of use assets and lease liabilities included in our condensed consolidated balance sheet at June 30, 2021 and December 31, 2020: 31 Table of Contents (in thousands) Balance sheet classification June 30, 2021 December 31, 2020 Assets Operating lease assets Operating lease right-of-use assets $ 10,020 $ 11,194 Liabilities Current Operating lease liabilities Other accrued liabilities $ 1,732 $ 1,747 Noncurrent Operating lease liabilities Operating lease - liabilities 8,719 9,872 Total lease liabilities $ 10,451 $ 11,619 The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2021 and December 31, 2020: June 30, 2021 December 31, 2020 Weighted-average remaining lease term ( in years ) Operating leases 8.65 8.70 Weighted-average discount rate Operating leases 3.8 % 3.8 % The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of June 30, 2021 and 2020: Six Months Ended June 30, (in thousands) 2021 2020 Operating cash flows from operating leases $ 936 $ 1,034 The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2021 and for each of the next five years and thereafter: (in thousands) Operating Leases (1) Remainder of 2021 $ 1,060 2022 1,845 2023 1,762 2024 1,607 2025 1,387 2026 951 Thereafter 3,596 Total lease payments $ 12,208 Less: Interest 1,757 Present value of lease liabilities $ 10,451 (1) Operating lease payments include $ 2.1 million related to options to extend lease terms that are reasonably certain of being exercised. 32 Table of Contents