Document and Entity Information
Document and Entity Information - USD ($) $ in Billions | 12 Months Ended | ||
Dec. 31, 2023 | Feb. 16, 2024 | Jun. 30, 2023 | |
Cover [Abstract] | |||
Document Type | 10-K | ||
Document Annual Report | true | ||
Document Period End Date | Dec. 31, 2023 | ||
Document Transition Report | false | ||
Entity File Number | 001-11590 | ||
Entity Registrant Name | CHESAPEAKE UTILITIES CORPORATION | ||
Entity Incorporation, State or Country Code | DE | ||
Entity Tax Identification Number | 51-0064146 | ||
Entity Address, Address Line One | 500 Energy Lane | ||
Entity Address, City or Town | Dover | ||
Entity Address, State or Province | DE | ||
Entity Address, Postal Zip Code | 19901 | ||
City Area Code | 302 | ||
Local Phone Number | 734-6799 | ||
Title of 12(b) Security | Common Stock—par value per share $0.4867 | ||
Trading Symbol | CPK | ||
Security Exchange Name | NYSE | ||
Entity Well-known Seasoned Issuer | Yes | ||
Entity Voluntary Filers | No | ||
Entity Current Reporting Status | Yes | ||
Entity Interactive Data Current | Yes | ||
Entity Filer Category | Large Accelerated Filer | ||
Entity Small Business | false | ||
Entity Emerging Growth Company | false | ||
Entity Shell Company | false | ||
Entity Public Float | $ 2.1 | ||
Entity Common Stock, Shares Outstanding | 22,238,384 | ||
Documents Incorporated by Reference | Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2024 Annual Meeting of Shareholders are incorporated by reference in Part II and Part III hereof | ||
Entity Central Index Key | 0000019745 | ||
Current Fiscal Year End Date | --12-31 | ||
Document Fiscal Year Focus | 2023 | ||
Document Fiscal Period Focus | FY | ||
Amendment Flag | false | ||
ICFR Auditor Attestation Flag | true | ||
Document Financial Statement Error Correction [Flag] | false |
Audit Information
Audit Information | 12 Months Ended |
Dec. 31, 2023 | |
Auditor Information [Abstract] | |
Auditor Name | Baker Tilly US, LLP |
Auditor Location | Lancaster, Pennsylvania |
Auditor Firm ID | 23 |
Consolidated Statements of Inco
Consolidated Statements of Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Revenues | |||
Regulated Energy | $ 473,595 | $ 429,424 | $ 383,920 |
Unregulated Energy | 223,148 | 280,750 | 206,869 |
Other | (26,139) | (29,470) | (20,821) |
Total operating revenues | 670,604 | 680,704 | 569,968 |
Operating Expenses | |||
Natural gas and electricity costs | 140,008 | 127,172 | 100,737 |
Propane and natural gas costs | 76,474 | 133,334 | 86,213 |
Operations | 178,437 | 164,505 | 148,294 |
Maintenance | 20,401 | 18,176 | 16,793 |
Depreciation and amortization | 65,501 | 68,973 | 62,661 |
Other taxes | 28,625 | 25,611 | 24,158 |
Total operating expenses | 519,801 | 537,771 | 438,856 |
Operating Income | 150,803 | 142,933 | 131,112 |
Other income, net | 1,438 | 5,051 | 1,720 |
Interest charges | 36,951 | 24,356 | 20,135 |
Income Before Income Taxes | 115,290 | 123,628 | 112,697 |
Income taxes | 28,078 | 33,832 | 29,231 |
Net Income (Loss) Attributable to Parent | $ 87,212 | $ 89,796 | $ 83,466 |
Weighted Average Common Shares Outstanding: | |||
Basic (in shares) | 18,370,758 | 17,722,227 | 17,558,078 |
Diluted (in shares) | 18,434,857 | 17,804,294 | 17,633,029 |
Earnings Per Share of Common Stock: | |||
Income (Loss) from Continuing Operations, Per Basic Share | $ 4.75 | $ 5.07 | $ 4.75 |
Basic (in usd per share) | 4.75 | 5.07 | 4.75 |
Earnings Per Share, Diluted [Abstract] | |||
Income (Loss) from Continuing Operations, Per Diluted Share | 4.73 | 5.04 | 4.73 |
Diluted (in usd per share) | $ 4.73 | $ 5.04 | $ 4.73 |
Transaction-related expenses | $ 10,355 | $ 0 | $ 0 |
Consolidated Statements of Comp
Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Comprehensive Income [Abstract] | |||
Net Income | $ 87,212 | $ 89,796 | $ 83,466 |
Employee Benefits, net of tax: | |||
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $11, $18 and $550, respectively | 32 | 57 | 1,616 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax | 110 | (705) | (262) |
Cash Flow Hedges, net of tax: | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent | 0 | 0 | |
Total Other Comprehensive (Loss) Income | (1,359) | (2,682) | 4,168 |
Comprehensive Income | 85,853 | 87,114 | 87,634 |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (400) | (2,453) | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 400 | 2,453 | |
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $11, $18 and $550, respectively | 32 | 57 | 1,616 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax | 110 | (705) | (262) |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (959) | (229) | |
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent | 0 | 0 | |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | |||
Cash Flow Hedges, net of tax: | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (388) | 35 | 28 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 388 | (35) | (28) |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | |||
Cash Flow Hedges, net of tax: | |||
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(501), $(369) and $2,702, respectively | (934) | 7,075 | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (44) | (2,545) | (4,813) |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 44 | 2,545 | 4,813 |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (1,322) | (934) | |
Net (loss) gain on commodity contract cash flow hedges, net of tax of $(501), $(369) and $2,702, respectively | (934) | $ 7,075 | |
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges | |||
Cash Flow Hedges, net of tax: | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (388) | 35 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 388 | (35) | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | $ 473 | $ 0 |
Consolidated Statements of Co_2
Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Comprehensive Income [Abstract] | |||
Tax expense recognized on the amortization of prior service cost | $ 11,000 | $ 18,082 | $ 550,000 |
Tax expense recognized on the net gain (loss) | (37,000) | 242,699 | 93,000 |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax | (165,000) | 0 | 0 |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Tax expense recognized on the amortization of prior service cost | 11,000 | 18,082 | 550,000 |
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, Tax | 37,000 | (242,699) | (93,000) |
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax | (165,000) | 0 | 0 |
Unrealized Gain (Loss) On Cash Flow Hedging Instruments, Tax | (501,000) | (369,000) | 2,702,000 |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax | (17,000) | (963,000) | (1,838,000) |
Accumulated Net Gain (Loss) from Cash Flow Hedges Attributable to Parent | |||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax | $ 135,000 | $ (12,000) | $ 12,000 |
Consolidated Statements of Cash
Consolidated Statements of Cash Flows - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Activities | |||
Net Income | $ 87,212 | $ 89,796 | $ 83,466 |
Adjustments to reconcile net income to net operating cash: | |||
Depreciation and amortization | 65,501 | 68,973 | 62,661 |
Depreciation and accretion included in operations expenses | 11,934 | 11,044 | 10,228 |
Deferred income taxes, net | 3,413 | 23,705 | 26,658 |
Realized (loss) on sale of assets/commodity contracts | (824) | (7,532) | (9,026) |
Unrealized loss (gain) on investments/commodity contracts | (1,916) | 1,817 | (1,464) |
Employee benefits and compensation | 342 | (1,111) | (53) |
Share-based compensation | 7,622 | 6,438 | 5,945 |
Changes in assets and liabilities: | |||
Accounts receivable and accrued revenue | 2,270 | (11,159) | (1,634) |
Propane inventory, storage gas and other inventory | 293 | (7,847) | (9,517) |
Regulatory assets/liabilities, net | 20,102 | (38,671) | (18,464) |
Prepaid expenses and other current assets | 18,689 | 9,124 | (1,520) |
Accounts payable and other accrued liabilities | (16,795) | 2,724 | 8,285 |
Income taxes receivable | (1,288) | 14,919 | (4,575) |
Customer deposits and refunds | 3,928 | 664 | 3,176 |
Accrued compensation | 1,462 | (1,231) | 1,198 |
Other assets and liabilities, net | 1,367 | (2,771) | (4,860) |
Net cash provided by operating activities | 203,482 | 158,882 | 150,504 |
Investing Activities | |||
Property, plant and equipment expenditures | (188,618) | (128,276) | (186,924) |
Proceeds from sale of assets | 2,926 | 3,860 | 1,033 |
Acquisitions, net of cash acquired | (925,034) | (11,766) | (36,371) |
Environmental expenditures | (665) | (266) | (761) |
Net cash used in investing activities | (1,111,391) | (136,448) | (223,023) |
Financing Activities | |||
Common stock dividends | (40,009) | (35,147) | (31,537) |
Issuance of stock for Dividend Reinvestment Plan | (28) | 4,534 | 15,851 |
Proceeds from issuance of common stock, net of expenses | 366,417 | 0 | 0 |
Payment, Tax Withholding, Share-based Payment Arrangement | (2,455) | (2,838) | (1,478) |
Change in cash overdrafts due to outstanding checks | (301) | 955 | (1,154) |
Net borrowings (repayments) under line of credit agreements | (22,544) | (20,608) | 46,647 |
Proceeds from issuance of long-term debt | 627,011 | 49,859 | 59,478 |
Repayment of long-term debt and finance lease obligation | (21,482) | (17,961) | (13,811) |
Net cash provided by (used in) financing activities | 906,609 | (21,206) | 73,996 |
Net (Decrease) Increase in Cash and Cash Equivalents | (1,300) | 1,228 | 1,477 |
Other Operating Activities, Cash Flow Statement | 170 | 0 | 0 |
Cash and Cash Equivalents — Beginning of Period | 6,204 | 4,976 | 3,499 |
Cash and Cash Equivalents — End of Period | $ 4,904 | $ 6,204 | $ 4,976 |
Consolidated Balance Sheets
Consolidated Balance Sheets - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Property, Plant and Equipment | ||
Regulated Energy | $ 2,418,494 | $ 1,802,999 |
Unregulated Energy | 410,807 | 393,215 |
Other businesses and eliminations | 30,310 | 29,890 |
Total property, plant and equipment | 2,859,611 | 2,226,104 |
Accumulated depreciation | 516,429 | 462,926 |
Construction Work in Progress | 113,192 | 47,295 |
Net property, plant and equipment | 2,456,374 | 1,810,473 |
Current Assets | ||
Cash and cash equivalents | 4,904 | 6,204 |
Accounts Receivable, before Allowance for Credit Loss, Current | 74,485 | 65,758 |
Allowance for uncollectible accounts | 2,699 | 2,877 |
Trade receivables, net | 71,786 | 62,881 |
Accrued Revenue | 32,597 | 29,206 |
Propane inventory, at average cost | 9,313 | 9,365 |
Other inventory, at average cost | 19,912 | 16,896 |
Regulatory assets | 19,506 | 41,439 |
Storage gas prepayments | 4,695 | 6,364 |
Income taxes receivable | 3,829 | 2,541 |
Prepaid expenses | 15,407 | 15,865 |
Derivative assets, at fair value | 1,027 | 2,787 |
Other current assets | 2,723 | 428 |
Total current assets | 185,699 | 193,976 |
Deferred Charges and Other Assets | ||
Goodwill | 508,174 | 46,213 |
Other intangible assets, net | 16,865 | 17,859 |
Investments, Fair Value Disclosure | 12,282 | 10,576 |
Operating Lease, Right-of-Use Asset | 12,426 | 14,421 |
Regulatory assets | 96,396 | 108,214 |
Receivables and other deferred charges | 16,448 | 12,323 |
Total deferred charges and other assets | 662,631 | 210,588 |
Total Assets | 3,304,704 | 2,215,037 |
Stockholders’ equity | ||
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding | 0 | 0 |
Common stock, par value $0.4867 per share (authorized 50,000,000 shares) | 10,823 | 8,635 |
Additional paid-in capital | 749,356 | 380,036 |
Retained earnings | 488,663 | 445,509 |
Accumulated other comprehensive loss | (2,738) | (1,379) |
Deferred compensation obligation | 9,050 | 7,060 |
Treasury Stock, Value | (9,050) | (7,060) |
Total stockholders’ equity | 1,246,104 | 832,801 |
Long-term debt, net of current maturities | 1,187,075 | 578,388 |
Total capitalization | 2,433,179 | 1,411,189 |
Current Liabilities | ||
Current portion of long-term debt | 18,505 | 21,483 |
Short-term borrowing | 179,853 | 202,157 |
Accounts payable | 77,481 | 61,496 |
Customer deposits and refunds | 46,427 | 37,152 |
Accrued interest | 7,020 | 3,349 |
Dividends payable | 13,119 | 9,492 |
Accrued compensation | 16,544 | 14,660 |
Regulatory liabilities | 13,719 | 5,031 |
Derivative liabilities, at fair value | 354 | 585 |
Other accrued liabilities | 13,362 | 13,618 |
Total current liabilities | 386,384 | 369,023 |
Deferred Credits and Other Liabilities | ||
Deferred income taxes | 259,082 | 256,167 |
Regulatory liabilities | 195,279 | 142,989 |
Environmental liabilities | 2,607 | 3,272 |
Other pension and benefit costs | 15,330 | 16,965 |
Operating Lease, Liability, Noncurrent | 10,550 | 12,392 |
Deferred investment tax credits and other liabilities | 1,366 | 1,410 |
Total deferred credits and other liabilities | 485,141 | 434,825 |
Commitments and Contingencies | ||
Total Capitalization and Liabilities | 3,304,704 | 2,215,037 |
Regulated Energy | 2,418,494 | 1,802,999 |
Unregulated Energy | 410,807 | 393,215 |
Other businesses and eliminations | 30,310 | 29,890 |
Total property, plant and equipment | 2,859,611 | 2,226,104 |
Accumulated depreciation | 516,429 | 462,926 |
Construction Work in Progress | 113,192 | 47,295 |
Net property, plant and equipment | 2,456,374 | 1,810,473 |
Cash and cash equivalents | 4,904 | 6,204 |
Accounts Receivable, before Allowance for Credit Loss, Current | 74,485 | 65,758 |
Allowance for uncollectible accounts | 2,699 | 2,877 |
Trade receivables, net | 71,786 | 62,881 |
Accrued Revenue | 32,597 | 29,206 |
Propane inventory, at average cost | 9,313 | 9,365 |
Other inventory, at average cost | 19,912 | 16,896 |
Regulatory assets | 19,506 | 41,439 |
Storage gas prepayments | 4,695 | 6,364 |
Income taxes receivable | 3,829 | 2,541 |
Prepaid expenses | 15,407 | 15,865 |
Derivative assets, at fair value | 1,027 | 2,787 |
Other current assets | 2,723 | 428 |
Disposal Group, Including Discontinued Operation, Assets, Current | 185,699 | 193,976 |
Goodwill | 508,174 | 46,213 |
Other intangible assets, net | 16,865 | 17,859 |
Investments, Fair Value Disclosure | 12,282 | 10,576 |
Energy Marketing Contracts Assets, Noncurrent | 40 | 982 |
Operating Lease, Right-of-Use Asset | 12,426 | 14,421 |
Regulatory assets | 96,396 | 108,214 |
Receivables and other deferred charges | 16,448 | 12,323 |
Deferred Charges And Other Assets | 662,631 | 210,588 |
Total identifiable assets | 3,304,704 | 2,215,037 |
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding | 0 | 0 |
Common stock, par value $0.4867 per share (authorized 50,000,000 shares) | 10,823 | 8,635 |
Additional paid-in capital | 749,356 | 380,036 |
Retained earnings | 488,663 | 445,509 |
Accumulated other comprehensive loss | (2,738) | (1,379) |
Deferred compensation obligation | 9,050 | 7,060 |
Treasury Stock, Value | 9,050 | 7,060 |
Stockholders' Equity Attributable to Parent | 1,246,104 | 832,801 |
Long-term debt, net of current maturities | 1,187,075 | 578,388 |
Total capitalization | 2,433,179 | 1,411,189 |
Current portion of long-term debt | 18,505 | 21,483 |
Short-term borrowing | 179,853 | 202,157 |
Accounts payable | 77,481 | 61,496 |
Customer deposits and refunds | 46,427 | 37,152 |
Accrued interest | 7,020 | 3,349 |
Dividends payable | 13,119 | 9,492 |
Accrued compensation | 16,544 | 14,660 |
Regulatory liabilities | 13,719 | 5,031 |
Derivative liabilities, at fair value | 354 | 585 |
Other accrued liabilities | 13,362 | 13,618 |
Liabilities, Current | 386,384 | 369,023 |
Deferred income taxes | 259,082 | 256,167 |
Regulatory liabilities | 195,279 | 142,989 |
Environmental liabilities | 2,607 | 3,272 |
Other pension and benefit costs | 15,330 | 16,965 |
Energy Marketing Contract Liabilities, Noncurrent | 927 | 1,630 |
Operating Lease, Liability, Noncurrent | 10,550 | 12,392 |
Deferred investment tax credits and other liabilities | 1,366 | 1,410 |
Deferred Credits and Other Liabilities | 485,141 | 434,825 |
Liabilities and Equity | $ 3,304,704 | $ 2,215,037 |
Consolidated Balance Sheets (Pa
Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Statement of Financial Position [Abstract] | ||
Allowance for uncollectible accounts | $ 2,699 | $ 2,877 |
Common stock, par value | $ 0.4867 | $ 0.4867 |
Common stock, shares authorized | 50,000,000 | 50,000,000 |
Preferred Stock, Shares Authorized | 2,000,000 | 2,000,000 |
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 |
Consolidated Statements of Stoc
Consolidated Statements of Stockholders' Equity - USD ($) | Total | Florida City Gas | Common Stock [Member] | Common Stock [Member] Florida City Gas | Additional Paid-In Capital [Member] | Additional Paid-In Capital [Member] Florida City Gas | Retained Earnings [Member] | Accumulated Other Comprehensive Loss [Member] | Deferred Compensation [Member] | Treasury Stock, Common | ||
Shares, Issued | [1],[2] | 17,461,841 | ||||||||||
Stockholders' Equity Attributable to Parent | $ 697,085,000 | [2] | $ 8,499,000 | $ 348,482,000 | $ 342,969,000 | $ (2,865,000) | $ 5,679,000 | $ (5,679,000) | ||||
Net Income | 83,466,000 | 83,466,000 | ||||||||||
Other comprehensive loss | 4,168,000 | 4,168,000 | ||||||||||
Dividends | (33,363,000) | (33,363,000) | ||||||||||
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | $ 72,000 | |||||||||||
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | 147,256 | |||||||||||
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan | 18,248,000 | 18,176,000 | ||||||||||
Share-based compensation, shares | 46,313 | |||||||||||
Share-based compensation | 4,526,000 | [3],[4] | $ 22,000 | 4,504,000 | 0 | |||||||
Treasury stock activities | 0 | 1,561,000 | (1,561,000) | |||||||||
Shares, Issued | [1],[2] | 17,655,410 | ||||||||||
Stockholders' Equity Attributable to Parent | 774,130,000 | [2] | $ 8,593,000 | 371,162,000 | 393,072,000 | 1,303,000 | 7,240,000 | (7,240,000) | ||||
Net Income | 89,796,000 | 89,796,000 | ||||||||||
Other comprehensive loss | (2,682,000) | (2,682,000) | ||||||||||
Dividends | (37,359,000) | (37,359,000) | ||||||||||
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | $ 19,000 | 5,273,000 | ||||||||||
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan | 5,292,000 | |||||||||||
Share-based compensation, shares | [3],[4] | 46,590 | ||||||||||
Share-based compensation | 3,624,000 | [3],[4] | $ 23,000 | 3,601,000 | ||||||||
Treasury stock activities | $ 0 | (180,000) | 180,000 | |||||||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 100,000 | 39,418 | ||||||||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 136.26 | |||||||||||
Shares, Issued | [1],[2] | 17,741,418 | ||||||||||
Stockholders' Equity Attributable to Parent | 832,801,000 | $ 8,635,000 | 380,036,000 | 445,509,000 | (1,379,000) | 7,060,000 | (7,060,000) | |||||
Net Income | 87,212,000 | 87,212,000 | ||||||||||
Stock Issued During Period, Value, Acquisitions | $ 366,417,000 | $ 2,160,000 | $ 364,257,000 | |||||||||
Other comprehensive loss | (1,359,000) | (1,359,000) | ||||||||||
Dividends | (44,058,000) | (44,058,000) | ||||||||||
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | (26,000) | $ 0 | (26,000) | |||||||||
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan | 0 | |||||||||||
Share-based compensation, shares | [3],[4] | 55,323 | ||||||||||
Share-based compensation | 5,117,000 | [3],[4] | $ 28,000 | 5,089,000 | ||||||||
Treasury stock activities | 0 | 1,990,000 | (1,990,000) | |||||||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 4,438,596 | 4,400,000 | ||||||||||
Shares, Issued | [1],[2] | 22,235,337 | ||||||||||
Stockholders' Equity Attributable to Parent | $ 1,246,104,000 | $ 10,823,000 | $ 749,356,000 | $ 488,663,000 | $ (2,738,000) | $ 9,050,000 | $ (9,050,000) | |||||
[1] 2,000,000 shares of preferred stock at $0.01 par value per share have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity. Includes amounts for shares issued for directors’ compensation. shares, respectively, for taxes. (5) Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM equity issuances, as applicable. |
Consolidated Statements of St_2
Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Statement of Stockholders' Equity [Abstract] | |||
Preferred Stock, Shares Authorized | 2,000,000 | 2,000,000 | |
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 | |
Shares Held In Trust For Deferred Compensation Plan | 107,623 | 108,143 | 116,238 |
Dividends Declared | $ 2.3050 | $ 2.0850 | $ 1.8800 |
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes | 21,832 | 14,020 |
Summary of Significant Accounti
Summary of Significant Accounting Policies | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Summary of Significant Accounting Policies | S UMMARY OF S IGNIFICANT A CCOUNTING P OLICIES Use of Estimates Preparing the consolidated financial statements to conform with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments about various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates. As additional information becomes available, or actual amounts are determined, recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates. Property, Plant and Equipment Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2023 and 2022 is provided in the following table: As of December 31, (in thousands) 2023 2022 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida (1) $ 1,486,796 $ 925,501 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 788,185 741,865 Electric distribution 143,513 135,633 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 194,918 185,090 Natural gas transmission and supply – Ohio 134,192 128,620 Electricity and steam generation 37,064 36,886 Mobile CNG and pipeline solutions 40,558 38,543 Sustainable energy investments, including renewable natural gas 4,076 4,076 Other 30,309 29,890 Total property, plant and equipment 2,859,611 2,226,104 Less: Accumulated depreciation and amortization (516,429) (462,926) Plus: Construction work in progress 113,192 47,295 Net property, plant and equipment $ 2,456,374 $ 1,810,473 (1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition. Contributions or Advances in Aid of Construction Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2023 and 2022, the non-refundable contributions totaled $4.2 million and $7.6 million, respectively. AFUDC Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. During the years ended December 31, 2023, 2022 and 2021, AFUDC was immaterial and was reflected as a reduction of interest charges. Leases We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets. Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment. We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 14, Leases, for additional information. Jointly-owned Pipelines Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, 2023, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $2.2 million and $1.5 million at December 31, 2023 and 2022, respectively. Impairment of Long-lived Assets We periodically evaluate whether events or circumstances have occurred, which indicate that long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any. Depreciation and Accretion Included in Operations Expenses We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 million, respectively, of depreciation and accretion in operations expenses. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 Natural gas distribution – Delmarva Peninsula 2.5% 2.5% 2.5% Natural gas distribution – Florida (1) (2) 2.2% 2.5% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.3% Natural gas transmission – Ohio 5.0% 5.0% N/A Electric distribution 2.4% 2.8% 2.8% (1) Excludes the acquisition of FCG which was completed on November 30, 2023. (2) Average for 2023 includes the impact of the depreciation study that was approved by the Florida PSC in connection with the natural gas base rate proceeding. For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets: Asset Description Useful Life Propane distribution mains 10-37 years Propane bulk plants and tanks 10-40 years Propane equipment, meters and meter installations 5-33 years Measuring and regulating station equipment 5-37 years Natural gas pipelines 45 years Natural gas right of ways Perpetual CHP plant 30 years Natural gas processing equipment 20-25 years Office furniture and equipment 3-10 years Transportation equipment 4-20 years Structures and improvements 5-45 years Other Various Regulated Operations We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in our consolidated statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows. We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980 continue to apply to our regulated operations and that the recovery of our regulatory assets is probable. Revenue Recognition Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates. For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms. These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis. Our unregulated propane distribution businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses. Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly. Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers. Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees. We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis. For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date. Natural Gas, Electric and Propane Costs Natural gas, electric and propane costs include the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable commodity cost of natural gas, electricity and propane, costs of pipeline capacity needed to transport and store natural gas, transmission costs for electricity, costs to gather and process natural gas, costs to transport propane to/from our storage facilities or our mobile CNG equipment to customer locations, and steam and electricity generation costs. Depreciation expense is not included in natural gas, electric and propane costs. Operations and Maintenance Expenses Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses. Cash and Cash Equivalents Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents. Accounts Receivable and Allowance for Credit Losses Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and impacts from general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible. Our estimate for expected credit losses has been developed by analyzing our portfolio of financial assets that present potential credit exposure risk. These assets consist solely of our trade receivables from customers and contract assets. The estimate is based on five years of historical collections experience, a review of current economic and operating conditions in our service territories, and an examination of economic indicators which provide a reasonable and supportable basis of potential future activity. Those indicators include metrics which we believe provide insight into the future collectability of our trade receivables such as unemployment rates and economic growth statistics in our service territories. When determining estimated credit losses, we analyze the balance of our trade receivables based on the underlying line of business. This includes an examination of trade receivables from our energy distribution, energy transmission, energy delivery services and propane operations businesses. Our energy distribution business consists of all our regulated distribution utility (natural gas and electric) operations on the Delmarva Peninsula and in Florida. These business units have the ability to recover their costs through the rate-making process, which can include consideration for amounts historically written off to be included in rate base. Therefore, they possess a mechanism to recover credit losses which we believe reduces their exposure to credit risk. Our energy transmission and energy delivery services business units consist of our natural gas pipelines and our mobile CNG delivery operations. The majority of customers served by these business units are regulated distribution utilities who also have the ability to recover their costs. We believe this cost recovery mechanism significantly reduces the amount of credit risk associated with these customers. Our propane operations are unregulated and do not have the same ability to recover their costs as our regulated operations. However, historically our propane operations have not had material write offs relative to the amount of revenues generated. Our estimate of expected credit losses reflects our anticipated losses associated with our trade receivables as a result of non-payment from our customers beginning the day the trade receivable is established. We believe the risk of loss associated with trade receivables classified as current presents the least amount of credit exposure risk and therefore, we assign a lower estimate to our current trade receivables. As our trade receivables age outside of their expected due date, our estimate increases. Our allowance for credit losses relative to the balance of our trade receivables has historically been immaterial as a result of on time payment activity from our customers. The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2023: (in thousands) Balance at December 31, 2022 $ 2,877 Additions: Provision for credit losses 2,340 Recoveries 166 Deductions: Write offs (2,684) Balance at December 31, 2023 $ 2,699 Inventories We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2023, 2022 or 2021. Goodwill and Other Intangible Assets Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. There were no goodwill impairments recognized during the years ended December 31, 2023, 2022 and 2021. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Other Deferred Charges Other deferred charges include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings. Asset Removal Cost As authorized by the appropriate regulatory body (state PSC or FERC), we accrue future asset removal costs associated with utility property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When we retire depreciable utility plant and equipment, we charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with our asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates. See Note 18, Rates and Other Regulatory Activities , for information related to FCG's reserve surplus amortization mechanism ("RSAM") that was approved as part of its rate case effective as of May 1, 2023. Pension and Other Postretirement Plans Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high-quality corporate bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options. The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on plan assets. We estimate the health care cost trend rates used in determining our postretirement expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date. The mortality assumption used for our pension and postretirement plans is reviewed periodically and is based on the actuarial table that best reflects the expected mortality of the plan participants. Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property. We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income. We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities. Financial Instruments We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being initially recorded in accumulated other comprehensive income (loss) and reclassified to earnings when the associated hedged transaction settles. The ineffective portion of the gain or loss of a hedge is immediately recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging , it is recorded at fair value with all gains or losses being recorded directly in earnings. Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and normal sales” treatment under ASC Topic 815 and are accounted for on an accrual basis. 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. We designate and account for the 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. Recent Accounting Standards Yet to be Adopted Segment Reporting (ASC 280) - In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures , which modifies required disclosures about a public entity’s reportable segments and addresses requests from investors for more detailed information about a reportable segment’s expenses and a more comprehensive reconciliation of each segment's reported profit or loss. ASU 2023-07 will be effective for our annual financial statements beginning January 1, 2024 and our interim financial statements beginning January 1, 2025. ASU 2023-07 only impacts disclosures, and as a result, will not have a material impact on our financial position or results of operations. Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, |
Earnings Per Share
Earnings Per Share | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Earnings Per Share | 3. E ARNINGS P ER S HARE The following table presents the calculation of our basic and diluted earnings per share: For the Year Ended December 31, 2023 2022 2021 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 87,212 $ 89,796 $ 83,466 Weighted average shares outstanding (1) 18,370,758 17,722,227 17,558,078 Basic Earnings Per Share $ 4.75 $ 5.07 $ 4.75 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted average shares outstanding — Basic (1) 18,370,758 17,722,227 17,558,078 Effect of dilutive securities — Share-based compensation 64,099 82,067 74,951 Adjusted denominator — Diluted (1) 18,434,857 17,804,294 17,633,029 Diluted Earnings Per Share $ 4.73 $ 5.04 $ 4.73 |
Acquisitions
Acquisitions | 12 Months Ended |
Dec. 31, 2023 | |
Business Combinations [Abstract] | |
Acquisitions | 4. A CQUISITIONS Acquisition of Florida City Gas On November 30, 2023, we completed the acquisition of FCG for $923.4 million in cash, including working capital adjustments as defined in the agreement, pursuant to the previously disclosed stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment. FCG, a regulated utility, serves approximately 120,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,800 miles of distribution main and 80 miles of transmission pipe. The purchase price of the acquisition was funded with $366.4 million of net proceeds from the issuance of 4.4 million shares of our common stock, the issuance of approximately $550.0 million principal amount of uncollateralized senior notes, and borrowings under the Company's Revolver. See Note 12, Long-Term Debt , and Note 15, Stockholders' Equity, for additional details on these financing activities . We accounted for the acquisition of FCG using the acquisition method. At December 31, 2023, the allocation of the purchase price remains preliminary pending finalizing of certain working capital balances. As such, the fair value measurements presented below are subject to change within the measurement period not to exceed one year from the date of the acquisition. As FCG is a regulated utility, the measurement of the fair value of most of the assets acquired and liabilities assumed were determined using the predecessor’s carrying value. In certain other instances where assets and liabilities are not subject to regulation, we determined the fair value in accordance with the principles of ASC Topic 820, Fair Value Measurements. The excess of the purchase price for FCG over the fair value of the assets acquired and liabilities assumed has been reflected as goodwill within the Regulated Energy segment. Goodwill resulting from the acquisition is largely attributable to expansion opportunities provided within our existing regulated operations in Florida, including planned customer growth and growth in rate base through continued investment in our utility infrastructure, as well as natural gas transmission infrastructure supporting the distribution operations. The goodwill recognized in connection with the acquisition of FCG will be deductible for income tax purposes. The components of the preliminary purchase price allocation are as follows: (in thousands) Assets acquired: Acquisition Date Fair Value Cash $ 2,270 Accounts receivable, net 14,396 Regulatory assets - current 2,983 Other current assets 2,707 Property, plant and equipment 453,845 Goodwill 461,193 Regulatory assets - non-current 3,381 Other deferred charges and other assets, 18,309 Total assets acquired 959,084 Liabilities assumed: Current liabilities (20,954) Regulatory liabilities (14,137) Other deferred credits and other liabilities (548) Total liabilities assumed (35,639) Net purchase price $ 923,445 Direct transaction costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges include $4.1 million related to fees and expenses associated with the Bridge Facility, which was terminated without any funds drawn, for the year ended December 31, 2023. Other transaction costs of $15.9 million related primarily to the debt and equity financings executed in connection with the acquisition have been deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate. For the period from the acquisition date through December 31, 2023, the Company’s consolidated results include $12.1 million of operating revenue and a $3.3 million net loss attributable to FCG which includes $7.5 million of the transaction-related expenses described above. For additional information on FCG's results, see discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations . The following unaudited financial information reflects our pro forma operating revenues and net income assuming the FCG acquisition had occurred on January 1, 2022. The unaudited pro forma financial information has been presented for illustrative purposes only and is not necessarily indicative of the results of operations that would have been achieved or the future results of operations of FCG. For the Year Ended December 31, 2023 2022 (in thousands) Operating Revenue $ 786,473 $ 798,355 Net Income $ 85,398 $ 81,508 Acquisition of J.T. Lee and Son's In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $3.9 million. In connection with this acquisition, we recorded a $0.3 million liability which is subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. Sharp added approximately 3,000 customers and distribution of approximately 800,000 gallons of propane annually. The transaction also includes a bulk plant with 60,000 gallons of propane storage, enabling the Company to realize efficiencies with additional storage capacity and overlapping delivery territories. In connection with this acquisition, we recorded $2.7 million in property plant and equipment, $0.9 million in goodwill, $0.2 million in working capital, and less than $0.1 million in intangible assets associated primarily with non-compete agreements, all of which are deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the year ended December 31, 2023. Acquisition of Planet Found Energy Development In October 2022, we acquired Planet Found Energy Development, LLC ("Planet Found") for $9.5 million. In connection with this acquisition, we recorded a $0.9 million liability which was released after 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 2022. Planet Found's farm scale anaerobic digestion pilot system and technology produces biogas from 1200 tons of poultry litter annually. The transaction accelerated our efforts in converting poultry waste to renewable, sustainable energy while simultaneously improving the local environments in our service territories. In connection with this acquisition, we recorded $4.4 million in intangible assets associated primarily with intellectual property and non-compete agreements, $4.0 million in property plant and equipment, $1.1 million in goodwill, and less than $0.1 million in working capital, all of which are deductible for income tax purposes. The operating revenues and net income of Planet Found were not material to our consolidated results for the years ended December 31, 2023 and 2022. Acquisition of Davenport Energy In June 2022, Sharp acquired the propane operating assets of Davenport Energy's Siler City, North Carolina propane division for approximately $2.0 million. Through this acquisition, the Company expanded its operating footprint further into North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. Sharp added approximately 850 customers, and expected distribution of approximately 0.4 million gallons of propane annually. We recorded $1.5 million in property plant and equipment, $0.5 million in goodwill, and immaterial amounts associated with customer relationships and non-compete agreements, all of which are deductible for income tax purposes. The financial results associated with this acquisition are included within the Company's propane distribution operations within its Unregulated Energy segment. The operating revenues and net income of Davenport Energy were not material to our consolidated results for the years ended December 31, 2023 and 2022. |
Acquisitions Florida City Gas Pro forma | For the Year Ended December 31, 2023 2022 (in thousands) Operating Revenue $ 786,473 $ 798,355 Net Income $ 85,398 $ 81,508 |
Revenue Recognition Revenue Rec
Revenue Recognition Revenue Recognition (Notes) | 12 Months Ended |
Dec. 31, 2023 | |
Revenue from Contract with Customer [Abstract] | |
Revenue from Contract with Customer [Text Block] | R EVENUE R ECOGNITION We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays revenue by major source based on product and service type for the years ended December 31, 2023, 2022 and 2021: For the year ended December 31, 2023 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 83,882 $ — $ — $ 83,882 Florida Natural Gas distribution (1) 168,360 — — 168,360 Florida City Gas (2) 12,073 — — 12,073 FPU electric distribution 99,474 — — 99,474 Maryland natural gas division 28,092 — — 28,092 Sandpiper natural gas/propane operations 20,185 — — 20,185 Elkton Gas 8,814 — — 8,814 Total energy distribution 420,880 — — 420,880 Energy transmission Aspire Energy — 37,139 — 37,139 Aspire Energy Express 1,478 — — 1,478 Eastern Shore 79,923 — — 79,923 Peninsula Pipeline 30,400 — — 30,400 Total energy transmission 111,801 37,139 — 148,940 Energy generation Eight Flags — 19,207 — 19,207 Propane operations Propane distribution operations — 154,748 — 154,748 Compressed Natural Gas Services Marlin Gas Services — 12,300 — 12,300 Other and eliminations Eliminations (59,086) (246) (26,321) (85,653) Other — — 182 182 Total other and eliminations (59,086) (246) (26,139) (85,471) Total operating revenues (3) $ 473,595 $ 223,148 $ (26,139) $ 670,604 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions , and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. (3) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees. For the year ended December 31, 2022 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 82,176 $ — $ — $ 82,176 Florida Natural Gas distribution (1) 155,870 — — 155,870 FPU electric distribution 81,714 — — 81,714 Maryland natural gas division 26,607 — — 26,607 Sandpiper natural gas/propane operations 21,278 — — 21,278 Elkton Gas 9,198 — — 9,198 Total energy distribution 376,843 — — 376,843 Energy transmission Aspire Energy — 56,225 — 56,225 Aspire Energy Express 1,377 — — 1,377 Eastern Shore 78,624 — — 78,624 Peninsula Pipeline 27,263 — — 27,263 Total energy transmission 107,264 56,225 — 163,489 Energy generation Eight Flags — 25,318 — 25,318 Propane operations Propane distribution operations — 188,412 — 188,412 Compressed Natural Gas Services Marlin Gas Services — 11,159 — 11,159 Other and eliminations Eliminations (54,683) (364) (29,778) (84,825) Other — — 308 308 Total other and eliminations (54,683) (364) (29,470) (84,517) Total operating revenues (2) $ 429,424 $ 280,750 $ (29,470) $ 680,704 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees. For the year ended December 31, 2021 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 71,195 $ — $ — $ 71,195 Florida Natural Gas distribution (1) 134,609 — — 134,609 FPU electric distribution 78,300 — — 78,300 Maryland natural gas division 22,449 — — 22,449 Sandpiper natural gas/propane operations 20,746 — — 20,746 Elkton Gas 7,105 — — 7,105 Total energy distribution 334,404 — — 334,404 Energy transmission Aspire Energy — 38,163 — 38,163 Aspire Energy Express 187 — — 187 Eastern Shore 76,911 — — 76,911 Peninsula Pipeline 26,630 — — 26,630 Total energy transmission 103,728 38,163 — 141,891 Energy generation Eight Flags — 18,652 — 18,652 Propane operations Propane distribution operations — 142,082 — 142,082 Compressed Natural Gas Services Marlin Gas Services — 8,315 — 8,315 Other and eliminations Eliminations (54,212) (343) (21,348) (75,903) Other — — 527 527 Total other and eliminations (54,212) (343) (20,821) (75,376) Total operating revenues (2) $ 383,920 $ 206,869 $ (20,821) $ 569,968 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees. Regulated Energy Segment The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC or the FERC. Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide. Revenues for Eastern Shore are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to the FERC-approved maximum rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers receive service only when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on capacity used or reserved and the fixed monthly charge. Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period. Aspire Energy Express is engaged in natural gas intrastate transmission in the State of Ohio. We currently serve the Guernsey power plant and our performance obligation is satisfied over time as the natural gas is transported to the plant. We recognize revenue based on rates approved by the Ohio PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period. Unregulated Energy Segment Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period. Eight Flags' CHP plant, which is located on land leased from a customer, produces three sources of energy: electricity, steam and heated water. This customer purchases the steam (unfired and fired) and heated water, which are used in the customer’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers. For our propane distribution operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane distribution customers with meters, we satisfy our performance obligation over time. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane distribution metered customers, we accrue unbilled revenues for propane that is estimated to have been consumed, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period. Marlin Gas Services provides mobile CNG and pipeline solutions primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. Marlin Gas Services' performance obligations are comprised of the compression of natural gas, mobilization of CNG equipment, utilization of equipment and on-site CNG support. Our performance obligations for the compression of natural gas, utilization of mobile CNG equipment and for the on-site CNG staff support are satisfied over time when the natural gas is compressed, equipment is utilized or as our staff provide support services to our customers. Our performance obligation for the mobilization of CNG equipment is satisfied at a point-in-time when the equipment is delivered to the customer project location. We recognize revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees. Contract balances The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2023 and 2022 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Noncurrent) Contract Liabilities (Current) (in thousands) Balance at 12/31/2022 $ 61,687 $ 18 $ 4,321 $ 983 Balance at 12/31/2023 67,741 18 3,524 1,022 Increase (decrease) $ 6,054 $ — $ (797) $ 39 Our trade receivables are included in trade and other receivables in the consolidated balance sheets. Our non-current contract assets are included in receivables and other deferred charges in the consolidated balance sheet and relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement. At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2023 and 2022, the amounts recognized in revenue were not material. Remaining performance obligations Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for these businesses for the remaining performance obligations at December 31, 2023 are expected to be recognized as follows: (in thousands) 2024 2025 2026 2027 2028 2029 and thereafter Eastern Shore and Peninsula Pipeline $ 36,657 $ 30,330 $ 26,547 $ 23,433 $ 22,559 $ 149,124 Natural gas distribution operations 9,680 9,216 8,501 6,472 5,252 28,428 FPU electric distribution 652 275 275 275 275 — Total revenue contracts with remaining performance obligations $ 46,989 $ 39,821 $ 35,323 $ 30,180 $ 28,086 $ 177,552 |
Segment Information
Segment Information | 12 Months Ended |
Dec. 31, 2023 | |
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Segment Information | S EGMENT I NFORMATION We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief decision maker (our Chief Executive Officer, or "CEO") 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 distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas. 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. 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 tables present information about our reportable segments: For the Year Ended December 31, 2023 2022 2021 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy $ 471,591 $ 422,894 $ 381,879 Unregulated Energy 199,013 257,810 188,089 Total operating revenues, unaffiliated customers $ 670,604 $ 680,704 $ 569,968 Intersegment Revenues (1) Regulated Energy $ 2,004 $ 6,530 $ 2,041 Unregulated Energy 24,135 22,940 18,780 Other businesses 182 308 527 Total intersegment revenues $ 26,321 $ 29,778 $ 21,348 Operating Income Regulated Energy $ 126,199 $ 115,317 $ 106,174 Unregulated Energy 24,426 27,350 24,427 Other businesses and eliminations 178 266 511 Operating Income 150,803 142,933 131,112 Other income, net 1,438 5,051 1,720 Interest charges 36,951 24,356 20,135 Income before Income Taxes 115,290 123,628 112,697 Income Taxes 28,078 33,832 29,231 Net Income $ 87,212 $ 89,796 $ 83,466 Depreciation and Amortization Regulated Energy (2) $ 48,162 $ 52,707 $ 48,748 Unregulated Energy 17,347 16,257 13,869 Other businesses and eliminations (8) 9 44 Total depreciation and amortization $ 65,501 $ 68,973 $ 62,661 Capital Expenditures Regulated Energy (3) $ 1,095,871 $ 97,554 $ 139,733 Unregulated Energy 40,264 40,773 81,651 Other businesses 1,762 2,355 6,425 Total capital expenditures $ 1,137,897 $ 140,682 $ 227,809 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details. (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details. As of December 31, (in thousands) 2023 2022 Identifiable Assets Regulated Energy segment $ 2,781,581 $ 1,716,255 Unregulated Energy segment 477,402 463,239 Other businesses and eliminations 45,721 35,543 Total identifiable assets $ 3,304,704 $ 2,215,037 |
Supplemental Cash Flow Disclosu
Supplemental Cash Flow Disclosures | 12 Months Ended |
Dec. 31, 2023 | |
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Supplemental Cash Flow Disclosures | S UPPLEMENTAL C ASH F LOW D ISCLOSURES Cash paid for interest and income taxes during the years ended December 31, 2023, 2022 and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (in thousands) Cash paid for interest $ 30,525 $ 24,267 $ 20,809 Cash (received) paid for income taxes, net of refunds $ 21,920 $ (4,963) $ 8,395 Non-cash investing and financing activities during the years ended December 31, 2023, 2022, and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (in thousands) Capital property and equipment acquired on account, but not paid for as of December 31, $ 33,334 $ 13,211 $ 16,164 Common stock issued for the Retirement Savings Plan $ — $ — $ 1,712 Common stock issued under the SICP $ 3,740 $ 2,868 $ 2,834 |
Derivative Instruments
Derivative Instruments | 12 Months Ended |
Dec. 31, 2023 | |
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Derivative Instruments | 8. D ERIVATIVE I NSTRUMENTS 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. Occasionally, we may enter into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of December 31, 2023 and 2022, our natural gas and electric distribution operations did not have any outstanding derivative contracts. Volume of Derivative Activity As of December 31, 2023, the volume of our open 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 18.1 Cash flow hedges June 2026 Sharp Propane (gallons) Sales 3.2 Cash flow hedges March 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 and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2023 through June 2026) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is initially recorded as a component of accumulated other comprehensive income (loss) and later recognized in our consolidated statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.3 million of unrealized losses from accumulated other comprehensive income (loss) to earnings during the next 12-month period. 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 September 2022, we entered into an interest rate swap with a notional amount of $50.0 million through September 2025, with pricing of 3.98 percent. In February 2021, we entered into an interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. In the fourth quarter of 2020, we entered into interest rate swaps with notional amounts totaling $60.0 million through December 2021 with pricing of approximately 0.20 percent for the period associated with our outstanding borrowing under the Revolver. In August 2022, we amended and restated the Revolver and transitioned the benchmark interest rate to the 30-day SOFR as a result of the expiration of LIBOR. Accordingly, our current interest rate swap is cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate. Prior to August 2022, our short-term borrowing interest rate was based on the 30-day LIBOR rate. Our pre-2022 interest rate swaps were cash settled monthly as the counter-party paid us the 30-day LIBOR rate less the fixed rate. We designate and account for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are initially recorded as a component of accumulated other comprehensive income (loss). As the interest rate swap settles each month, the realized gain or loss is recorded in the income statement and is recognized as a component of interest charges. 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 included within other current assets on the consolidated balance sheet with a balance of $2.1 million as of December 31, 2023 compared to a current liability of $0.1 million at December 31, 2022. 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. Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2023 and 2022 are as follows: Derivative Assets Fair Value as of (in thousands) Balance Sheet Location December 31, 2023 December 31, 2022 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value (1) $ 702 $ 3,317 Interest rate swap agreements Derivative assets, at fair value (1) 365 452 Total Derivative Assets $ 1,067 $ 3,769 (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term. Derivative Liabilities Fair Value as of (in thousands) Balance Sheet Location December 31, 2023 December 31, 2022 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value (1) $ 1,078 $ 1,810 Interest rate swap agreements Derivative liabilities, at fair value (1) 203 405 Total Derivative Liabilities $ 1,281 $ 2,215 (1) Derivative liabilities, at fair value include $0.4 million and $0.6 million in current liabilities in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term. The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows: Amount of Gain (Loss) on Derivatives: Location of Gain For the Year Ended December 31, (in thousands) 2023 2022 2021 Derivatives not designated as hedging instruments Propane swap agreements Propane and natural gas costs $ — $ 56 $ (1) Derivatives designated as fair value hedges Put/Call option Propane and natural gas costs — — (24) Derivatives designated as cash flow hedges Propane swap agreements Revenues 1,221 (373) (536) Propane swap agreements Propane and natural gas costs (1,160) 3,881 7,187 Interest rate swap agreements Interest expense 523 (47) (40) Total $ 584 $ 3,517 $ 6,586 |
Fair Value of Financial Instrum
Fair Value of Financial Instruments | 12 Months Ended |
Dec. 31, 2023 | |
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Fair Value of Financial Instruments | F AIR V ALUE OF F INANCIAL I NSTRUMENTS 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 as follows: 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 December 31, 2023 and 2022, respectively: Fair Value Measurements Using: As of December 31, 2023 Fair Value Quoted Prices in Significant Other Significant (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 1,489 — — 1,489 Investments—mutual funds and other 10,772 10,772 — — Total investments 12,282 10,793 — 1,489 Derivative assets 1,067 — 1,067 — Total assets $ 13,349 $ 10,793 $ 1,067 $ 1,489 Liabilities: Derivative liabilities $ 1,281 $ — $ 1,281 $ — Fair Value Measurements Using: As of December 31, 2022 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Significant (in thousands) Assets: Investments—equity securities $ 24 $ 24 $ — $ — Investments—guaranteed income fund 1,853 — — 1,853 Investments—mutual funds and other 8,699 8,699 — — Total investments 10,576 8,723 — 1,853 Derivative assets 3,769 — 3,769 — Total assets $ 14,345 $ 8,723 $ 3,769 $ 1,853 Liabilities: Derivative liabilities $ 2,215 $ — $ 2,215 $ — The changes in the fair value of our Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income. At December 31, 2023 and 2022, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required. Other Financial Assets and Liabilities Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable, other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market (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 2 measurement). At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.2 billion, compared to the estimated fair value of $1.2 billion. At December 31, 2022, long-term debt, which includes the current maturities and excludes debt issuance costs, had a carrying value of $600.8 million, compared to a fair value of $505.0 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 2 measurement. See Note 16, Employee Benefit Plans, for fair value measurement information related to our pension plan assets. |
Goodwill and Other Intangible A
Goodwill and Other Intangible Assets | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Goodwill and Other Intangible Assets | G OODWILL AND O THER I NTANGIBLE A SSETS The carrying value of goodwill as of December 31, 2023 and 2022 was as follows: (in thousands) Regulated Energy Unregulated Energy Total Goodwill Balance at December 31, 2022 $ 7,689 $ 38,524 $ 46,213 Additions (1) 461,025 936 461,961 Balance at December 31, 2023 $ 468,714 $ 39,460 $ 508,174 (1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details. There were no goodwill impairments recognized during the three-year period ended December 31, 2023. The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2023 and 2022 was as follows: As of December 31, 2023 2022 (in thousands) Gross Accumulated Gross Accumulated Customer relationships $ 17,004 $ 7,146 $ 16,965 $ 6,131 Non-Compete agreements 3,125 1,855 3,105 1,411 Patents (1) 6,558 859 5,819 533 Other 270 232 270 225 Total $ 26,957 $ 10,092 $ 26,159 $ 8,300 (1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found. The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted average of 14 years. Amortization expense of intangible assets for the year ended December 31, 2023, 2022 and 2021 w as $1.8 million, $1.5 million and $1.3 million , respectively. |
Income Taxes
Income Taxes | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Income Taxes | I NCOME T AXES We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our state returns for tax years after 2017 are subject to examination. At December 31, 2023, the 2015 through 2019 federal income tax returns are no longer under examination. For state income tax purposes, we had NOL in various states of $72.9 million and $67.7 million as of December 31, 2023 and 2022, respectively, almost all of which will expire in 2040. Excluding NOLs from discontinued operations, we have recorded deferred tax assets of $1.8 million and $1.5 million related to state NOL carry-forwards at December 31, 2023 and 2022, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized. Tax Law Changes In March 2020, the CARES Act was signed into law and included several significant changes to the Internal Revenue Code. The CARES Act includes certain tax relief provisions including the ability to carryback five years net operating losses arising in a tax year beginning in 2018, 2019, or 2020. This provision allows a taxpayer to recover taxes previously paid at a 35 percent federal income tax rate during tax years prior to 2018. In addition, the CARES Act removed the taxable income limitation to allow a tax NOL to fully offset taxable income for tax years beginning before January 1, 2021. As a result, our income tax expense for the year ended December 31, 2021 included a tax benefit $0.9 million, attributable to the tax NOL carryback provided under the CARES Act for losses generated in 2018 and 2019 and then applied back to our 2013 and 2015 tax years in which we paid federal income taxes at a 35 percent tax rate. Tax benefits associated with this legislation were not available for the year ended December 31, 2023. On December 22, 2017, the TCJA was signed into law. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 18, Rates and Other Regulatory Activities, for further discussion of the TCJA's impact on our regulated businesses. The following tables provide: (a) the components of income tax expense in 2023, 2022, and 2021; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2023, 2022, and 2021; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2023 and 2022. For the Year Ended December 31, 2023 2022 2021 (in thousands) Current Income Tax Expense Federal $ 14,736 $ 8,284 $ 2,775 State 5,496 1,948 (96) Other (47) (47) (47) Total current income tax expense (benefit) 20,185 10,185 2,632 Deferred Income Tax Expense (1) Property, plant and equipment 17,797 14,968 24,074 Deferred gas costs (7,739) 8,923 1,857 Pensions and other employee benefits (974) 1,109 (655) FPU merger-related premium cost and deferred gain (351) (351) (351) Net operating loss carryforwards (370) 2 97 Other (470) (1,004) 1,577 Total deferred income tax expense 7,893 23,647 26,599 Total Income Tax $ 28,078 $ 33,832 $ 29,231 (1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively. For the Year Ended December 31, 2023 2022 2021 (in thousands) Reconciliation of Effective Income Tax Rates Federal income tax expense (1) $ 24,214 $ 25,982 $ 23,666 State income taxes, net of federal benefit 4,377 7,714 6,371 ESOP dividend deduction (184) (177) (180) CARES Act Tax Benefit — — (919) Other (329) 313 293 Total Income Tax Expense $ 28,078 $ 33,832 $ 29,231 Effective Income Tax Rate 24.35 % 27.34 % 25.94 % (1) Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021. As of December 31, 2023 2022 (in thousands) Deferred Income Taxes Deferred income tax liabilities: Property, plant and equipment $ 252,125 $ 238,687 Acquisition adjustment 5,564 5,915 Loss on reacquired debt 145 164 Deferred gas costs 3,550 11,288 Natural gas conversion costs 4,824 5,026 Storm reserve liability 5,797 5,791 Other 9,655 8,236 Total deferred income tax liabilities $ 281,660 $ 275,107 Deferred income tax assets: Pension and other employee benefits $ 4,993 $ 3,985 Environmental costs 951 1,052 Net operating loss carryforwards 1,847 1,488 Storm reserve liability 213 453 Accrued expenses 3,335 9,007 Other 11,239 2,955 Total deferred income tax assets $ 22,578 $ 18,940 Deferred Income Taxes Per Consolidated Balance Sheets $ 259,082 $ 256,167 |
Long-Term Debt
Long-Term Debt | 12 Months Ended |
Dec. 31, 2023 | |
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Long-Term Debt | L ONG - TERM D EBT Our outstanding long-term debt is shown below: As of December 31, (in thousands) 2023 2022 Uncollateralized Senior Notes: 5.93% notes, due October 31, 2023 $ — $ 3,000 5.68% notes, due June 30, 2026 8,700 11,600 6.43% notes, due May 2, 2028 3,500 4,200 3.73% notes, due December 16, 2028 10,000 12,000 3.88% notes, due May 15, 2029 30,000 35,000 3.25% notes, due April 30, 2032 59,500 66,500 3.48% notes, due May 31, 2038 50,000 50,000 3.58% notes, due November 30, 2038 50,000 50,000 3.98% notes, due August 20, 2039 100,000 100,000 2.98% notes, due December 20, 2034 70,000 70,000 3.00% notes, due July 15, 2035 50,000 50,000 2.96% notes, due August 15, 2035 40,000 40,000 2.49% notes, due January 25, 2037 50,000 50,000 2.95% notes, due March 15, 2042 50,000 50,000 5.43% notes, due March 14, 2038 80,000 — 6.39% notes, due December 2026 100,000 — 6.44% notes, due December 2027 100,000 — 6.45% notes, due December 2028 100,000 — 6.62% notes, due December 2030 100,000 — 6.71% notes, due December 2033 100,000 — 6.73% notes, due December 2038 50,000 — Equipment security note 2.46% note, due September 24, 2031 7,633 8,517 Less: debt issuance costs (3,753) (946) Total long-term debt 1,205,580 599,871 Less: current maturities (18,505) (21,483) Total long-term debt, net of current maturities $ 1,187,075 $ 578,388 Terms of the Senior Notes All of our outstanding Senior 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. Senior Notes On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG which closed during the fourth quarter of 2023. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes will be due on their respective maturity dates with interest payments payable semiannually until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes. On March 14, 2023 we issued 5.43 percent Senior Notes due March 14, 2038 in the aggregate principal amount of $80.0 million and used the proceeds received from the issuances of the Senior Notes to reduce short-term borrowings under our Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal amortization payment beginning in the sixth year after the issuance. Annual Maturities Annual maturities and principal repayments of long-term debt are as follows: Year 2024 2025 2026 2027 2028 Thereafter Total (in thousands) Payments $ 18,505 $ 25,528 $ 134,551 $ 131,674 $ 136,699 $ 762,376 $ 1,209,333 Shelf Agreements We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended these Shelf Agreements, which expanded the total borrowing capacity and extended the term of the agreements for an additional three years to 2026. The following table summarizes the current available capacity under our Shelf Agreements at December 31, 2023: (in thousands) Total Borrowing Capacity Less Amount of Debt Issued Less Unfunded Commitments Remaining Borrowing Capacity Shelf Agreements (1) Prudential Shelf Agreement $ 405,000 $ (300,000) $ — $ 105,000 MetLife Shelf Agreement 200,000 (50,000) — 150,000 Total $ 605,000 $ (350,000) $ — $ 255,000 |
Short-Term Borrowing
Short-Term Borrowing | 12 Months Ended |
Dec. 31, 2023 | |
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Short-Term Borrowing | S HORT - TERM B ORROWINGS We are authorized by our Board of Directors to borrow up to $375.0 million of short-term debt, as required. At December 31, 2023 and 2022, we had $179.9 million and $202.2 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.83 percent and 5.04 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2023. We have entered into several amendments to our Revolver which resulted in modifications to both tranches of the facility. The most recent amendment in October 2023 allowed for a change in our funded indebtedness ratio from 65 percent to 70 percent during the quarter in which the acquisition of FCG is consummated and the quarter subsequent to the closing of the acquisition. The amendment in August 2023 served to renew the 364-day tranche of the Revolver, providing for $175.0 million of short-term debt capacity. Additionally, the amendment for borrowings under the 364-day tranche shall now bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. Further, the amendment provided that borrowings under the 364-day green loan sublimit shall now bear interest at (i) the SOFR rate plus a 10-basis point credit spread adjustment and an applicable margin of 1.00 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate plus 0.05 percent or less, solely at our discretion. The amendment entered into in 2022 served to reset the benchmark interest rate to SOFR and to eliminate a previous covenant which capped our investment limit to $150.0 million for investments where we maintain less than 50 percent ownership. The 364-day tranche of the Revolver expires in August 2024 and the five-year tranche expires in August 2026. Borrowings under both tranches of the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. As of December 31, 2023, the pricing under the 364-day tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 75-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances. As of December 31, 2023, the pricing under the five-year tranche of the Revolver included a commitment fee of 9-basis points on undrawn amounts and an interest rate of 95-basis points over SOFR plus a 10-basis point SOFR adjustment on outstanding balances. 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 the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio as described above. As of December 31, 2023, we are in compliance with this covenant. Our total available credit under the Revolver at December 31, 2023 was $188.1 million. As of December 31, 2023, we had issued $7.0 million in letters of credit to various counterparties under the 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 the Revolver. In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 1 5 , Stockholders Equity . For additional information on interest rate swaps related to our short-term borrowings, see Note 8 , Derivative Instruments . |
Leases
Leases | 12 Months Ended |
Dec. 31, 2023 | |
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Leases | L EASES 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 our service territories. 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. 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 December 31, 2023, 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 December 31, 2023, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our consolidated statements of income: Year Ended December 31, (in thousands) Classification 2023 2022 Operating lease cost (1) Operations expense $ 3,040 $ 2,883 (1) Includes short-term leases and variable lease costs, which are immaterial. The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2023 and 2022: (in thousands) Balance sheet classification December 31, 2023 December 31, 2022 Assets Operating lease assets Operating lease right-of-use assets $ 12,426 $ 14,421 Liabilities Current Operating lease liabilities Other accrued liabilities $ 2,454 $ 2,552 Noncurrent Operating lease liabilities Operating lease - liabilities 10,550 12,392 Total lease liabilities $ 13,004 $ 14,944 The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Weighted-average remaining lease term ( in years ) Operating leases 8.1 8.5 Weighted-average discount rate Operating leases 3.5 % 3.4 % The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2023 and 2022: Year Ended December 31, (in thousands) 2023 2022 Operating cash flows from operating leases $ 2,906 $ 2,931 The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2023 and for each of the next five years and thereafter: (in thousands) Operating Leases (1) 2024 $ 2,771 2025 2,288 2026 1,774 2027 1,583 2028 1,205 Thereafter 5,243 Total lease payments 14,864 Less: Interest (1,860) Present value of lease liabilities $ 13,004 (1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised. |
Stockholders' Equity
Stockholders' Equity | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Accumulated Other Comprehensive Income (Loss) | S TOCKHOLDERS' E QUITY Common Stock Issuances In November 2023, in connection with our acquisition of FCG, we completed an overnight offering resulting in the issuance of 4.4 million shares of our common stock at a price per share of $82.72 (net of underwriter discounts and commissions). We received net proceeds of $366.4 million which were used to partially finance the acquisition. We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and our previous ATM programs. 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. There were no issuances under the DRIP in 2023. In 2022, we issued less than 0.1 million shares at an average price per share of $136.26 and received net proceeds of $4.5 million under the DRIP. Our most recent ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $75 million, expired in June 2023. Net proceeds from share issuances under our DRIP and ATM programs are used 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 Income (Loss) Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contract 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 balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2023 and 2022. All amounts in the following tables are presented net of tax. Defined Benefit Pension and Postretirement Plan Items Commodity Contract Cash Flow Hedges Interest Rate Swap Cash Flow Hedges Total (in thousands) As of December 31, 2021 $ (3,268) $ 4,571 $ — $ 1,303 Other comprehensive income (loss) before reclassifications 705 (934) — (229) Amounts reclassified from accumulated other comprehensive income (loss) 57 (2,545) 35 (2,453) Net current-period other comprehensive income (loss) 762 (3,479) 35 (2,682) As of December 31, 2022 (2,506) 1,092 35 (1,379) Other comprehensive income (loss) before reclassifications (110) (1,322) 473 (959) Amounts reclassified from accumulated other comprehensive income (loss) 32 (44) (388) (400) Net current-period other comprehensive income (loss) (78) (1,366) 85 (1,359) As of December 31, 2023 $ (2,584) $ (274) $ 120 $ (2,738) |
Employee Benefit Plans
Employee Benefit Plans | 12 Months Ended |
Dec. 31, 2023 | |
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Employee Benefit Plans | E MPLOYEE B ENEFIT P LANS We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year. The changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs are recorded as a component of other comprehensive income (loss) or a regulatory asset. Defined Benefit Pension Plans At December 31, 2023 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake Supplemental Executive Retirement Plan ("SERP"). The FPU Pension Plan, a qualified plan, covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the FPU merger, the FPU Pension Plan was frozen with respect to additional years of service and compensation, effective December 31, 2009. The Chesapeake SERP, a nonqualified plan, is comprised of two sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. The second sub-plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit. The unfunded liability for all plans at both December 31, 2023 and 2022, is included in the other pension and benefit costs liability in our consolidated balance sheets. The following schedules set forth the funded status at December 31, 2023 and 2022 and the net periodic cost (benefit) for the years ended December 31, 2023, 2022 and 2021 for the FPU Pension Plan and the Chesapeake SERP: FPU Chesapeake At December 31, 2023 2022 2023 2022 (in thousands) Change in benefit obligation: Benefit obligation — beginning of year $ 49,941 $ 67,030 $ 1,659 $ 2,096 Interest cost 2,495 1,781 81 50 Actuarial (gain) loss 454 (15,713) 48 (335) Benefits paid (3,233) (3,157) (152) (152) Benefit obligation — end of year 49,657 49,941 1,636 1,659 Change in plan assets: Fair value of plan assets — beginning of year 46,203 58,712 — — Actual return on plan assets 6,462 (9,552) — — Employer contributions — 200 152 152 Benefits paid (3,233) (3,157) (152) (152) Fair value of plan assets — end of year 49,432 46,203 — — Accrued pension cost / funded status $ (225) $ (3,738) $ (1,636) $ (1,659) Assumptions: Discount rate 5.00 % 5.25 % 4.88 % 5.00 % Expected return on plan assets 6.00 % 6.00 % — % — % FPU Chesapeake For the Years Ended December 31, 2023 2022 2021 2023 2022 2021 (in thousands) Components of net periodic pension cost: Interest cost $ 2,495 $ 1,781 $ 1,714 $ 81 $ 50 $ 48 Expected return on assets (2,670) (3,430) (3,306) — — — Amortization of actuarial loss 407 466 612 8 28 28 Total periodic cost $ 232 $ (1,183) $ (980) $ 89 $ 78 $ 76 Assumptions: Discount rate 5.25 % 2.75 % 2.50 % 5.00 % 2.50 % 2.25 % Expected return on plan assets 6.00 % 6.00 % 6.00 % — % — % — % During the fourth quarter of 2021, we formally terminated the Chesapeake Pension Plan. Total periodic cost for the plan during that year was $2.0 million attributable to a settlement charge. Our funding policy provides that payments to the trust of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2023, 2022 and 2021: FPU Pension Plan At December 31, 2023 2022 2021 Asset Category Equity securities 50 % 53 % 52 % Debt securities 49 % 38 % 38 % Other 1 % 9 % 10 % Total 100 % 100 % 100 % The investment policy of the FPU Pension Plan is designed to provide the capital assets necessary to meet the financial obligations of the plan. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plan, earn a competitive return to increasingly fund a large portion of the plan’s retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain the appropriate mix of investments to reduce the risk of large losses over the expected remaining life of the plan. The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives: Asset Allocation Strategy Asset Class Minimum Allocation Percentage Maximum Allocation Percentage Domestic Equities (Large Cap, Mid Cap and Small Cap) 33 % 57 % Fixed Income (Inflation Bond and Taxable Fixed) 38 % 58 % Foreign Equities (Developed and Emerging Markets) 3 % 7 % Cash 0 % 5 % Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance. At December 31, 2023 and 2022, the assets of the FPU Pension Plan were comprised of the following investments: Fair Value Measurement Hierarchy For Year Ended December 31, Asset Category 2023 2022 (in thousands) Mutual Funds - Equity securities U.S. Large Cap (1) $ 15,360 $ 3,413 U.S. Mid Cap (1) 4,271 1,425 U.S. Small Cap (1) 2,518 692 International (2) 2,499 9,352 Alternative Strategies (3) — 4,824 24,648 19,706 Mutual Funds - Debt securities Fixed income (4) 24,228 15,343 High Yield (4) — 2,269 24,228 17,612 Mutual Funds - Other Commodities (5) — 1,832 Real Estate (6) — 1,709 Guaranteed deposit (7) 556 398 556 3,939 Total Pension Plan Assets in fair value hierarchy (8) 49,432 41,257 Investments measured at net asset value (9) — 4,946 Total Pension Plan Assets $ 49,432 $ 46,203 (1) Includes funds that invest primarily in United States common stocks. (2) Includes funds that invest primarily in foreign equities and emerging markets equities. (3) Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade. (4) Includes funds that invest in investment grade and fixed income securities. (5) Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities. (6) Includes funds that invest primarily in real estate. (7) Includes investment in a group annuity product issued by an insurance company. (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3. (9) Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets. At December 31, 2023 and 2022, our pension plan investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees. Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy and are presented in the table above to reconcile to total pension plan assets. The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Other Postretirement Benefits Plans We sponsor two defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. At December 31, 2023 and 2022, the funded status of the Chesapeake Postretirement Plan was $1.1 million and $0.6 million, respectively. The funded status of the FPU Medical Plan was $0.4 million and $0.7 million as of December 31, 2023 and 2022, respectively. Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2023, 2022, and 2021. As of December 31, 2023, there was $12.8 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $10.8 million and $1.2 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $3.2 million recorded in accumulated other comprehensive income (loss) and $8.7 million recorded as a regulatory asset at December 31, 2023. Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset the portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations. Assumptions The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2023, considering the expected lives of each of the plans. In determining the average expected return on plan assets for the FPU Pension Plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the FPU Pension Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable. The health care inflation rate for 2023 used to calculate the benefit obligation is 5 percent for medical and 6 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5 percent for both medical and prescription drugs for the FPU Medical Plan. Estimated Future Benefit Payments In 2024, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.2 million are expected for the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan combined. The schedule below shows the estimated future benefit payments for each of the plans previously described: FPU Pension Plan (1) Chesapeake SERP (2) Chesapeake Postretirement Plan (2) FPU Medical Plan (2) (in thousands) 2024 $ 3,528 $ 151 $ 42 $ 35 2025 $ 3,603 $ 164 $ 46 $ 35 2026 $ 3,617 $ 161 $ 45 $ 34 2027 $ 3,616 $ 158 $ 48 $ 33 2028 $ 3,651 $ 154 $ 49 $ 32 Years 2029 through 2033 $ 17,951 $ 689 $ 299 $ 143 (1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets. (2) Benefit payments are expected to be paid out of our general funds. Retirement Savings Plan We sponsor a 401(k) Retirement Savings Plan which is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum of six percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of ten percent. All contributions and matched funds can be invested among the mutual funds available for investment. Employer contributions to our Retirement Savings Plan totaled $6.6 million, $6.2 million, and $5.9 million for the years ended December 31, 2023, 2022 and 2021, respectively. As of December 31, 2023, there were 798,586 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan. Non-Qualified Deferred Compensation Plan Members of our Board of Directors and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up to six percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of deferred compensation to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier or later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years. All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of cash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. Deferred stock compensation may not be diversified. The participants are credited with dividends on their deferred common stock units in the same amount that is received by all other stockholders. Such dividends are reinvested into additional deferred common stock units. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheet, had a fair value of $12.3 million and $10.6 million at December 31, 2023 and 2022, respectively. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors. |
Share-Based Compensation Plans
Share-Based Compensation Plans | 12 Months Ended |
Dec. 31, 2023 | |
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Share-Based Compensation Plans | S HARE -B ASED C OMPENSATION P LANS Our key employees and non-employee directors have been 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. We have 561,115 shares of common stock reserved for issuance under the SICP. The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2023, 2022 and 2021: For the Year Ended December 31, 2023 2022 2021 (in thousands) Awards to key employees $ 6,716 $ 5,479 $ 5,163 Awards to non-employee directors 906 959 782 Total compensation expense 7,622 6,438 5,945 Less: tax benefit (1,947) (1,663) (1,535) Share-based compensation amounts included in net income $ 5,675 $ 4,775 $ 4,410 Officers and Key Employees Our Compensation Committee is authorized to grant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals and subject to SEC transfer restrictions once awarded. Our President and CEO has the right to issue awards of shares of our common stock, to other officers and key employees of the Company, contingent upon various performance goals and subject to SEC transfer restrictions. We currently have several outstanding multi-year performance plans, which are based upon the successful achievement of long-term goals, growth and financial results and comprise both market-based and performance-based conditions and targets. The fair value per share, tied to a performance-based condition or target, is equal to the market price per share on the grant date. For the market-based conditions, we used a Monte Carlo valuation to estimate the fair value of each share granted. The table below presents the summary of the stock activity for awards to all officers: Number of Weighted Average Outstanding — December 31, 2021 197,398 $ 94.15 Granted 69,620 117.61 Vested (60,191) 90.60 Expired (2,678) 91.42 Outstanding — December 31, 2022 204,149 103.17 Granted 80,820 126.06 Vested (68,302) 91.59 Expired (2,053) 94.64 Forfeited (1,490) 113.44 Outstanding — December 31, 2023 213,124 $ 117.74 During the year ended December 31, 2023, we granted awards of 80,820 shares of common stock to officers and key employees under the SICP, including awards granted in February 2023 and to key employees appointed to officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2025. The aggregate intrinsic value of the SICP awards granted was $22.5 million, $24.1 million, and $28.8 million at December 31, 2023, 2022 and 2021, respectively. At December 31, 2023, there was $6.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2025. In March 2023, 2022 and 2021, upon the election by 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 March 2023, 2022 and 2021 for the performance periods ended December 31, 2022, 2021, and 2020. We paid the balance of such awarded shares to each such executive officer and remitted the cash equivalent of the withheld shares to the appropriate taxing authorities. The below table presents the number of shares withheld and amounts remitted: For the Year Ended December 31, 2023 2022 2021 (amounts in thousands, except shares) Shares withheld to satisfy tax obligations 19,859 21,832 14,020 Amounts remitted to tax authorities to satisfy obligations $ 2,455 $ 2,838 $ 1,478 |
Rates and Other Regulatory Acti
Rates and Other Regulatory Activities | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Rates and Other Regulatory Activities | R ATES AND O THER R EGULATORY A CTIVITIES 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. Refer to the additional details below pertaining to the Customer Information System Regulatory Asset Petition and COVID-19 impact. Delaware The October 2, 2023, application for the issuance of common stock and long-term debt was unanimously approved on October 25, 2023, by the Delaware PSC. In September 2023, the Delaware Division submitted the Energy Efficiency Rider application for natural gas with the Delaware PSC after obtaining an affirmative recommendation from the Delaware Energy Efficiency Advisory Council (“EEAC”). The application is the first in the state and applies to a portfolio of four programs including, Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and standard Offer Program in which customers can participate and allow for recovery. The evidentiary hearing on this matter is set for April 2024. If approved as filed, rates will be effective May 1, 2024. Maryland On October 2, 2023, Chesapeake filed a notification of the financing plans associated with the FCG acquisition with the Maryland PSC. The filing was successfully noted during the November 1, 2023, Maryland PSC administrative meeting. Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $6.9 million; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses under the new corporate entity which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. The outcome of the application is subject to review and approval by the Maryland PSC. Maryland Natural Gas Depreciation Study: In January 2024, our Maryland natural gas distribution businesses filed a joint petition for approval of their proposed unified depreciation rates with the Maryland PSC. If approved, new rates will become effective retroactively on January 1, 2023. Ocean City Maryland Reinforcement: During the second quarter of 2022, we began construction of an extension of service into North Ocean City, Maryland. Our Delaware natural gas division and Sandpiper installed approximately 5.4 miles of pipeline across southern Sussex County, Delaware to Fenwick Island, Delaware and Worcester County, Maryland. The project reinforces our existing system in Ocean City, Maryland and enables incremental growth along the pipeline. Construction of this project was completed in the second quarter of 2023. The Company filed a natural gas rate case application with the PSC for the state of Maryland in January 2024 as discussed above. Florida Wildlight Expansion: In August 2022, Peninsula Pipeline and FPU filed a joint petition with the Florida PSC for approval of its Transportation Service Agreement associated with the Wildlight planned community located in Nassau County, Florida. The project enables us to meet the significant growing demand for service in Yulee, Florida. The agreement will enable us to construct the project during the build-out of the community, and charge the reservation rate as each phase of the project goes into service. Construction of the pipeline facilities will occur in two separate phases. Phase one consists of three extensions with associated facilities, and a gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. The various phases of the project commenced in the first quarter of 2023, with construction on the overall project continuing through 2025. The petition was approved by the Florida PSC in November 2022. Florida Natural Gas Rate Case: In May 2022, our legacy natural gas distribution businesses in Florida filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 2023, (ii) a depreciation study also submitted with the filing; (iii) authorization to make certain changes to tariffs to include the consolidation of rates and rate structure across the businesses and to unify the Florida Natural Gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (v) authorization to establish an environmental remediation surcharge for the purposes of addressing future expected remediation costs for FPU MGP sites. In August 2022, interim rates were approved by the Florida PSC in the amount of approximately $7.7 million on an annualized basis, effective for all meter readings in September 2022. The discovery process and subsequent hearings were concluded during the fourth quarter of 2022 and briefs were submitted during the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023. FCG Natural Gas Rate Case: In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed RSAM with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. On June 23, 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied on September 12, 2023. On July 7, 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief on January 31, 2024. The RSAM is recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM is calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve months regulatory base net operating income, which primarily includes the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items is adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. For the year ended December 31, 2023, the Company recorded decreases to asset removal costs and depreciation expense of $5.1 million as a result of the RSAM adjustment. Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and FCG entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support FCG’s growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline constructed 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida area, traveling east under the Intercoastal Waterway and southward on the barrier island. The project was placed in-service during April 2023. St. Cloud / Twin Lakes Expansion: In July 2022, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 2,400 Dt/d of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline constructed a pipeline extension and regulator station for FPU. The extension supports new incremental load due to growth in the area, including providing service, most immediately, to the residential development, Twin Lakes. The expansion also improves reliability and provides operational benefits to FPU's existing distribution system in the area, supporting future growth. The petition was approved by the Florida PSC in October 2022, and the expansion was placed into service during the third quarter of 2023. Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operations' SPP was filed d uring the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. The Company filed 2024 SPPCRC projections on May 1, 2023. A hearing was held on September 12, 2023. The Commission voted to approve the projections on November 9, 2023. FPU projects to spend $13.6 million on the program in 2024. Lake Wales Pipeline Acquisition : In February 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 9,000 Dt/d of firm service in the Lake Wales, Florida area. The Commission approved the petition in April 2023. Approval of the agreement allowed Peninsula Pipeline to complete the acquisition of the existing pipeline in May 2023 which is being utilized to serve both current and new natural gas customers. GUARD : In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a ten-year program to enhance the safety, reliability, and accessibility of portions of our natural gas distribution system. We identified various categories of projects to be included in GUARD, which include the relocation of mains and service lines located in rear easements and other difficult to access areas to the front of the street, the replacement of problematic distribution mains, service lines, and maintenance and repair equipment and system reliability projects. In August 2023, the Florida PSC approved the GUARD program, which included $205.0 million of capital expenditures projected to be spent over a 10-year period. Newberry Expansion : In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 Dt/d of firm service in the Newberry, Florida area. The petition was approved by the Florida PSC in the third quarter of 2023. Peninsula Pipeline will construct a pipeline extension, which will be used by FPU to support the development of a natural gas distribution system to provide gas service to the City of Newberry. A filing to address the acquisition and conversion of propane community gas systems in Newberry was made in November 2023, and the Florida PSC is scheduled to vote on this in March 2024. The Company anticipates beginning the conversions of the community gas systems in the second quarter of 2024. Amendment to Escambia County Agreement : In April of 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to an existing contract with FPU. This amendment will allow Peninsula Pipeline to construct an additional delivery point on a pipeline located in Escambia County. The additional delivery point comes at the request of an FPU customer and will be used to enhance natural gas service in the area. The amendment was approved by the Florida PSC in the third quarter of 2023. Florida Electric Depreciation Study : The Florida PSC requires electric utilities to file a depreciation study every four years to reevaluate and set depreciation rates for the utility's plant assets. In June 2023, FPU filed a petition with the Florida PSC for approval of its proposed depreciation rates, which was approved in December 2023. East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that have experienced an increase in population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/day and 3,400 Dts/day, respectively. Eastern Shore Southern Expansion Project: In January 2022, Eastern Shore submitted a prior notice filing with the FERC pursuant to blanket certificate procedures, regarding its proposal to install an additional compressor unit and related facilities at Eastern Shore's compressor station in Bridgeville, Sussex County, Delaware. The project enables Eastern Shore to provide additional firm natural gas transportation service to an existing shipper on its pipeline system. The project obtained FERC approval in December 2022 and went into service in October 2023. Capital Cost Surcharge: In December 2022, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities as a result of mandated highway relocation projects as well as compliance with the PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore’s last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed on December 19, 2022. The combined revised surcharge became effective January 1, 2023. Worcester Resiliency Upgrade: In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. Eastern Shore has requested certificate authorization by December 2024, with a target in-service date by the third quarter of 2025. Various Jurisdictional Activity Related to the Joint Customer Information System Project In July 2022, we filed a joint petition for our natural gas divisions in Maryland (Maryland Division, Sandpiper, and Elkton Gas) for the approval to establish a regulatory asset for non-capitalizable expenses related to the initial development and implementation of our new Customer Information System ("CIS") system. The petition was approved by the Maryland PSC in August 2022. A similar petition for our Florida Regulated Energy businesses was filed during the same time frame, however, the Florida PSC approved capitalization of these expenses in lieu of establishment of regulatory assets. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. We have completed the system selection process and the CIS implementation began during the first quarter of 2023. 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 to impact economic conditions, to a lesser extent, through 2021 and 2022. Chesapeake Utilities is considered an “essential business,” which 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 the height of the pandemic. In April and May 2020, we were authorized by the Maryland and Delaware PSCs, respectively, to record regulatory assets for COVID-19 related costs which offered us the ability to seek recovery of those costs. In July 2021, the Florida PSC issued an order that approved incremental expenses we incurred due to COVID-19. The order allowed us to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021 for natural gas and electric distribution operations. The regulatory asset is being amortized over two years and is recovered through the Purchased Gas Adjustment and Swing Service mechanisms for our natural gas distribution businesses and through the Fuel Purchased Power Cost Recovery clause for our electric division. As of December 31, 2023 and 2022, our total COVID-19 regulatory asset balance was $0.2 million and $1.2 million, respectively. Summary TCJA Table Customer rates for our regulated business were adjusted, as approved by the regulators, prior to 2020 except for Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarized the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of December 31, 2023 and 2022: Amount (in thousands) Operation and Regulatory Jurisdiction December 31, 2023 December 31, 2022 Status Eastern Shore (FERC) $34,190 $34,190 Will be addressed in Eastern Shore's next rate case filing. Chesapeake Delaware natural gas division (Delaware PSC) $12,038 $12,230 PSC approved amortization of ADIT in January 2019. Chesapeake Maryland natural gas division (Maryland PSC) $3,585 $3,703 PSC approved amortization of ADIT in May 2018. Sandpiper Energy (Maryland PSC) $3,487 $3,597 PSC approved amortization of ADIT in May 2018. Florida Natural Gas distribution (Florida PSC) (1) $26,757 $27,179 PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019. FPU electric division (Florida PSC) $4,760 $4,993 In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates. Elkton Gas (Maryland PSC) $1,027 $1,059 PSC approved amortization of ADIT in March 2018. (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. Regulatory Assets and Liabilities At December 31, 2023 and 2022, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates. As of December 31, 2023 2022 (in thousands) Regulatory Assets Under-recovered purchased fuel, gas and conservation cost recovery (1) (2) $ 13,696 $ 43,583 Under-recovered GRIP revenue (3) 1,777 1,705 Deferred postretirement benefits (4) 10,802 13,927 Deferred conversion and development costs (1) 21,466 23,653 Acquisition adjustment (5) 31,857 25,609 Deferred costs associated with COVID-19 (6) 190 1,233 Deferred storm costs (7) 19,370 27,687 Deferred rate case expenses - current 1,171 — Other 15,573 12,256 Total Regulatory Assets $ 115,902 $ 149,653 Regulatory Liabilities Self-insurance (8) $ 521 $ 339 Over-recovered purchased fuel and conservation cost recovery (1) 12,340 3,827 Over-recovered GRIP revenue (3) 501 — Storm reserve (8) 1,900 2,845 Accrued asset removal cost (9) 86,534 50,261 Deferred income taxes due to rate change (10) 105,055 87,690 Interest related to storm recovery (7) 536 1,207 Other 1,611 1,851 Total Regulatory Liabilities $ 208,998 $ 148,020 (1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023. (3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP. (4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715 , Compensation - Retirement Benefits , related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16 , Employee Benefit Plans, for additional information. (5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above. (6) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs. (7) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. (8) We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred. (9) See Note 2 , Summary of Significant Accounting Policies, for additional information on our asset removal cost policies. (10) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes , for additional information. |
Environmental Commitments and C
Environmental Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Environmental Commitments and Contingencies | E NVIRONMENTAL C OMMITMENTS AND C ONTINGENCIES 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 December 31, 2023 and 2022, we had approximately $3.6 million and $4.3 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2023 and 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs from customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval for and has recovered, through a combination of insurance and customer rates, $14.0 million of its environmental costs related to its MGP sites as of December 31, 2023. 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 MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial. The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million. |
Other Commitments and Contingen
Other Commitments and Contingencies | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Other Commitments and Contingencies | O THER C OMMITMENTS AND C ONTINGENCIES Natural Gas, Electric and Propane Supply In March 2023, 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, 2023 and expire in March 2026. FPU natural gas distribution operations and Eight Flags have separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements commenced in November 2020 and expire in October 2030. Florida Natural Gas 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 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 December 31, 2023, FPU was in compliance with all of the requirements of its 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. The total purchase obligations for natural gas, electric and propane supplies are as follows: Year 2024 2025-2026 2027-2028 Beyond 2028 Total (in thousands) Purchase Obligations $ 86,040 $ 105,082 $ 83,851 $ 141,287 $ 416,260 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 December 31, 2023 was $35.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2023 was approximately $24.3 million with the guarantees expiring on various dates through December 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2023 was $4.0 million. |
Summary of Significant Accoun_2
Summary of Significant Accounting Policies (Policies) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Use of Estimates | Use of Estimates |
Property, Plant and Equipment | Property, Plant and Equipment Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2023 and 2022 is provided in the following table: As of December 31, (in thousands) 2023 2022 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida (1) $ 1,486,796 $ 925,501 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 788,185 741,865 Electric distribution 143,513 135,633 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 194,918 185,090 Natural gas transmission and supply – Ohio 134,192 128,620 Electricity and steam generation 37,064 36,886 Mobile CNG and pipeline solutions 40,558 38,543 Sustainable energy investments, including renewable natural gas 4,076 4,076 Other 30,309 29,890 Total property, plant and equipment 2,859,611 2,226,104 Less: Accumulated depreciation and amortization (516,429) (462,926) Plus: Construction work in progress 113,192 47,295 Net property, plant and equipment $ 2,456,374 $ 1,810,473 (1) Includes amounts attributable to the acquisition of FCG. See Note 4 for additional details on the acquisition. Contributions or Advances in Aid of Construction Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2023 and 2022, the non-refundable contributions totaled $4.2 million and $7.6 million, respectively. AFUDC Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. During the years ended December 31, 2023, 2022 and 2021, AFUDC was immaterial and was reflected as a reduction of interest charges. Leases We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets. Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment. We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 14, Leases, for additional information. Jointly-owned Pipelines Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, 2023, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $2.2 million and $1.5 million at December 31, 2023 and 2022, respectively. Impairment of Long-lived Assets |
Depreciation and Accretion Included in Operations Expenses | Depreciation and Accretion Included in Operations Expenses We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 million, respectively, of depreciation and accretion in operations expenses. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 Natural gas distribution – Delmarva Peninsula 2.5% 2.5% 2.5% Natural gas distribution – Florida (1) (2) 2.2% 2.5% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.3% Natural gas transmission – Ohio 5.0% 5.0% N/A Electric distribution 2.4% 2.8% 2.8% (1) Excludes the acquisition of FCG which was completed on November 30, 2023. (2) Average for 2023 includes the impact of the depreciation study that was approved by the Florida PSC in connection with the natural gas base rate proceeding. For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets: Asset Description Useful Life Propane distribution mains 10-37 years Propane bulk plants and tanks 10-40 years Propane equipment, meters and meter installations 5-33 years Measuring and regulating station equipment 5-37 years Natural gas pipelines 45 years Natural gas right of ways Perpetual CHP plant 30 years Natural gas processing equipment 20-25 years Office furniture and equipment 3-10 years Transportation equipment 4-20 years Structures and improvements 5-45 years Other Various |
Regulated Operations | Regulated Operations We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in our consolidated statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows. We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980 continue to apply to our regulated operations and that the recovery of our regulatory assets is probable. |
Operating Revenues | Revenue Recognition Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates. For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms. These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis. Our unregulated propane distribution businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses. Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly. Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers. Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees. We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis. For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date. |
Cost of Sales | Natural gas, electric and propane costs include the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable commodity cost of natural gas, electricity and propane, costs of pipeline capacity needed to transport and store natural gas, transmission costs for electricity, costs to gather and process natural gas, costs to transport propane to/from our storage facilities or our mobile CNG equipment to customer locations, and steam and electricity generation costs. Depreciation expense is not included in natural gas, electric and propane costs. |
Operations and Maintenance Expenses | Operations and Maintenance Expenses Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses. |
Cash and Cash Equivalents | Cash and Cash Equivalents Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents. |
Accounts Receivable and Allowance for Doubtful Accounts | Accounts Receivable and Allowance for Credit Losses Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and impacts from general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible. Our estimate for expected credit losses has been developed by analyzing our portfolio of financial assets that present potential credit exposure risk. These assets consist solely of our trade receivables from customers and contract assets. The estimate is based on five years of historical collections experience, a review of current economic and operating conditions in our service territories, and an examination of economic indicators which provide a reasonable and supportable basis of potential future activity. Those indicators include metrics which we believe provide insight into the future collectability of our trade receivables such as unemployment rates and economic growth statistics in our service territories. When determining estimated credit losses, we analyze the balance of our trade receivables based on the underlying line of business. This includes an examination of trade receivables from our energy distribution, energy transmission, energy delivery services and propane operations businesses. Our energy distribution business consists of all our regulated distribution utility (natural gas and electric) operations on the Delmarva Peninsula and in Florida. These business units have the ability to recover their costs through the rate-making process, which can include consideration for amounts historically written off to be included in rate base. Therefore, they possess a mechanism to recover credit losses which we believe reduces their exposure to credit risk. Our energy transmission and energy delivery services business units consist of our natural gas pipelines and our mobile CNG delivery operations. The majority of customers served by these business units are regulated distribution utilities who also have the ability to recover their costs. We believe this cost recovery mechanism significantly reduces the amount of credit risk associated with these customers. Our propane operations are unregulated and do not have the same ability to recover their costs as our regulated operations. However, historically our propane operations have not had material write offs relative to the amount of revenues generated. Our estimate of expected credit losses reflects our anticipated losses associated with our trade receivables as a result of non-payment from our customers beginning the day the trade receivable is established. We believe the risk of loss associated with trade receivables classified as current presents the least amount of credit exposure risk and therefore, we assign a lower estimate to our current trade receivables. As our trade receivables age outside of their expected due date, our estimate increases. Our allowance for credit losses relative to the balance of our trade receivables has historically been immaterial as a result of on time payment activity from our customers. The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2023: (in thousands) Balance at December 31, 2022 $ 2,877 Additions: Provision for credit losses 2,340 Recoveries 166 Deductions: Write offs (2,684) Balance at December 31, 2023 $ 2,699 |
Inventories | Inventories We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2023, 2022 or 2021. |
Goodwill and Other Intangible Assets | Goodwill and Other Intangible Assets |
Other Deferred Charges | Other Deferred Charges |
Asset Retirement Obligation [Policy Text Block] | Asset Removal Cost |
Pension and Other Postretirement Plans | Pension and Other Postretirement Plans Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high-quality corporate bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options. The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on plan assets. We estimate the health care cost trend rates used in determining our postretirement expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date. |
Income Taxes and Investment Tax Credit Adjustments | Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property. We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income. We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities. |
Financial Instruments | Financial Instruments We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being initially recorded in accumulated other comprehensive income (loss) and reclassified to earnings when the associated hedged transaction settles. The ineffective portion of the gain or loss of a hedge is immediately recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging , it is recorded at fair value with all gains or losses being recorded directly in earnings. Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and normal sales” treatment under ASC Topic 815 and are accounted for on an accrual basis. |
Recently Adopted Accounting Standards | |
Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block] | Recent Accounting Standards Yet to be Adopted Segment Reporting (ASC 280) - In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures , which modifies required disclosures about a public entity’s reportable segments and addresses requests from investors for more detailed information about a reportable segment’s expenses and a more comprehensive reconciliation of each segment's reported profit or loss. ASU 2023-07 will be effective for our annual financial statements beginning January 1, 2024 and our interim financial statements beginning January 1, 2025. ASU 2023-07 only impacts disclosures, and as a result, will not have a material impact on our financial position or results of operations. Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, |
Summary of Significant Accoun_3
Summary of Significant Accounting Policies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Accounting Policies [Abstract] | |
Property, Plant and Equipment [Table Text Block] | A summary of property, plant and equipment by classification as of December 31, 2023 and 2022 is provided in the following table: As of December 31, (in thousands) 2023 2022 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida (1) $ 1,486,796 $ 925,501 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 788,185 741,865 Electric distribution 143,513 135,633 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 194,918 185,090 Natural gas transmission and supply – Ohio 134,192 128,620 Electricity and steam generation 37,064 36,886 Mobile CNG and pipeline solutions 40,558 38,543 Sustainable energy investments, including renewable natural gas 4,076 4,076 Other 30,309 29,890 Total property, plant and equipment 2,859,611 2,226,104 Less: Accumulated depreciation and amortization (516,429) (462,926) Plus: Construction work in progress 113,192 47,295 Net property, plant and equipment $ 2,456,374 $ 1,810,473 (1) |
Annual Depreciation Rates Table [Table Text Block] | Depreciation and Accretion Included in Operations Expenses We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2023, 2022 and 2021, we reported $11.9 million, $11.0 million and $10.2 million, respectively, of depreciation and accretion in operations expenses. The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2023, 2022 and 2021: 2023 2022 2021 Natural gas distribution – Delmarva Peninsula 2.5% 2.5% 2.5% Natural gas distribution – Florida (1) (2) 2.2% 2.5% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.3% Natural gas transmission – Ohio 5.0% 5.0% N/A Electric distribution 2.4% 2.8% 2.8% (1) Excludes the acquisition of FCG which was completed on November 30, 2023. (2) |
Estimated Useful Life Of Assets Table [Table Text Block] | For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets: Asset Description Useful Life Propane distribution mains 10-37 years Propane bulk plants and tanks 10-40 years Propane equipment, meters and meter installations 5-33 years Measuring and regulating station equipment 5-37 years Natural gas pipelines 45 years Natural gas right of ways Perpetual CHP plant 30 years Natural gas processing equipment 20-25 years Office furniture and equipment 3-10 years Transportation equipment 4-20 years Structures and improvements 5-45 years Other Various |
Earnings Per Share (Tables)
Earnings Per Share (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Calculations of Basic and Diluted Earnings Per Share | The following table presents the calculation of our basic and diluted earnings per share: For the Year Ended December 31, 2023 2022 2021 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 87,212 $ 89,796 $ 83,466 Weighted average shares outstanding (1) 18,370,758 17,722,227 17,558,078 Basic Earnings Per Share $ 4.75 $ 5.07 $ 4.75 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted average shares outstanding — Basic (1) 18,370,758 17,722,227 17,558,078 Effect of dilutive securities — Share-based compensation 64,099 82,067 74,951 Adjusted denominator — Diluted (1) 18,434,857 17,804,294 17,633,029 Diluted Earnings Per Share $ 4.73 $ 5.04 $ 4.73 |
Acquisitions (Tables)
Acquisitions (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items] | |
Acquisitions Florida City Gas Pro forma | For the Year Ended December 31, 2023 2022 (in thousands) Operating Revenue $ 786,473 $ 798,355 Net Income $ 85,398 $ 81,508 |
Florida City Gas Purchas Price Allocation | (in thousands) Assets acquired: Acquisition Date Fair Value Cash $ 2,270 Accounts receivable, net 14,396 Regulatory assets - current 2,983 Other current assets 2,707 Property, plant and equipment 453,845 Goodwill 461,193 Regulatory assets - non-current 3,381 Other deferred charges and other assets, 18,309 Total assets acquired 959,084 Liabilities assumed: Current liabilities (20,954) Regulatory liabilities (14,137) Other deferred credits and other liabilities (548) Total liabilities assumed (35,639) Net purchase price $ 923,445 |
Revenue Recognition Revenue R_2
Revenue Recognition Revenue Recognition (Tables) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Revenue from Contract with Customer [Abstract] | |||
Disaggregation of Revenue [Table Text Block] | for the years ended December 31, 2023, 2022 and 2021: For the year ended December 31, 2023 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 83,882 $ — $ — $ 83,882 Florida Natural Gas distribution (1) 168,360 — — 168,360 Florida City Gas (2) 12,073 — — 12,073 FPU electric distribution 99,474 — — 99,474 Maryland natural gas division 28,092 — — 28,092 Sandpiper natural gas/propane operations 20,185 — — 20,185 Elkton Gas 8,814 — — 8,814 Total energy distribution 420,880 — — 420,880 Energy transmission Aspire Energy — 37,139 — 37,139 Aspire Energy Express 1,478 — — 1,478 Eastern Shore 79,923 — — 79,923 Peninsula Pipeline 30,400 — — 30,400 Total energy transmission 111,801 37,139 — 148,940 Energy generation Eight Flags — 19,207 — 19,207 Propane operations Propane distribution operations — 154,748 — 154,748 Compressed Natural Gas Services Marlin Gas Services — 12,300 — 12,300 Other and eliminations Eliminations (59,086) (246) (26,321) (85,653) Other — — 182 182 Total other and eliminations (59,086) (246) (26,139) (85,471) Total operating revenues (3) $ 473,595 $ 223,148 $ (26,139) $ 670,604 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions , and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations. (3) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees. | For the year ended December 31, 2022 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 82,176 $ — $ — $ 82,176 Florida Natural Gas distribution (1) 155,870 — — 155,870 FPU electric distribution 81,714 — — 81,714 Maryland natural gas division 26,607 — — 26,607 Sandpiper natural gas/propane operations 21,278 — — 21,278 Elkton Gas 9,198 — — 9,198 Total energy distribution 376,843 — — 376,843 Energy transmission Aspire Energy — 56,225 — 56,225 Aspire Energy Express 1,377 — — 1,377 Eastern Shore 78,624 — — 78,624 Peninsula Pipeline 27,263 — — 27,263 Total energy transmission 107,264 56,225 — 163,489 Energy generation Eight Flags — 25,318 — 25,318 Propane operations Propane distribution operations — 188,412 — 188,412 Compressed Natural Gas Services Marlin Gas Services — 11,159 — 11,159 Other and eliminations Eliminations (54,683) (364) (29,778) (84,825) Other — — 308 308 Total other and eliminations (54,683) (364) (29,470) (84,517) Total operating revenues (2) $ 429,424 $ 280,750 $ (29,470) $ 680,704 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) | For the year ended December 31, 2021 (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 71,195 $ — $ — $ 71,195 Florida Natural Gas distribution (1) 134,609 — — 134,609 FPU electric distribution 78,300 — — 78,300 Maryland natural gas division 22,449 — — 22,449 Sandpiper natural gas/propane operations 20,746 — — 20,746 Elkton Gas 7,105 — — 7,105 Total energy distribution 334,404 — — 334,404 Energy transmission Aspire Energy — 38,163 — 38,163 Aspire Energy Express 187 — — 187 Eastern Shore 76,911 — — 76,911 Peninsula Pipeline 26,630 — — 26,630 Total energy transmission 103,728 38,163 — 141,891 Energy generation Eight Flags — 18,652 — 18,652 Propane operations Propane distribution operations — 142,082 — 142,082 Compressed Natural Gas Services Marlin Gas Services — 8,315 — 8,315 Other and eliminations Eliminations (54,212) (343) (21,348) (75,903) Other — — 527 527 Total other and eliminations (54,212) (343) (20,821) (75,376) Total operating revenues (2) $ 383,920 $ 206,869 $ (20,821) $ 569,968 (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) Total operating revenues for the year ended December 31, 2021, include other revenue (revenues from sources other than contracts with customers) of $0.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees. |
Contract with Customer, Asset and Liability [Table Text Block] | The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2023 and 2022 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Noncurrent) Contract Liabilities (Current) (in thousands) Balance at 12/31/2022 $ 61,687 $ 18 $ 4,321 $ 983 Balance at 12/31/2023 67,741 18 3,524 1,022 Increase (decrease) $ 6,054 $ — $ (797) $ 39 | ||
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block] | Revenue for these businesses for the remaining performance obligations at December 31, 2023 are expected to be recognized as follows: (in thousands) 2024 2025 2026 2027 2028 2029 and thereafter Eastern Shore and Peninsula Pipeline $ 36,657 $ 30,330 $ 26,547 $ 23,433 $ 22,559 $ 149,124 Natural gas distribution operations 9,680 9,216 8,501 6,472 5,252 28,428 FPU electric distribution 652 275 275 275 275 — Total revenue contracts with remaining performance obligations $ 46,989 $ 39,821 $ 35,323 $ 30,180 $ 28,086 $ 177,552 |
Segment Information Segment Inf
Segment Information Segment Information (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Segment Reporting [Abstract] | |
Schedule of Segment Reporting Information, by Segment | : For the Year Ended December 31, 2023 2022 2021 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy $ 471,591 $ 422,894 $ 381,879 Unregulated Energy 199,013 257,810 188,089 Total operating revenues, unaffiliated customers $ 670,604 $ 680,704 $ 569,968 Intersegment Revenues (1) Regulated Energy $ 2,004 $ 6,530 $ 2,041 Unregulated Energy 24,135 22,940 18,780 Other businesses 182 308 527 Total intersegment revenues $ 26,321 $ 29,778 $ 21,348 Operating Income Regulated Energy $ 126,199 $ 115,317 $ 106,174 Unregulated Energy 24,426 27,350 24,427 Other businesses and eliminations 178 266 511 Operating Income 150,803 142,933 131,112 Other income, net 1,438 5,051 1,720 Interest charges 36,951 24,356 20,135 Income before Income Taxes 115,290 123,628 112,697 Income Taxes 28,078 33,832 29,231 Net Income $ 87,212 $ 89,796 $ 83,466 Depreciation and Amortization Regulated Energy (2) $ 48,162 $ 52,707 $ 48,748 Unregulated Energy 17,347 16,257 13,869 Other businesses and eliminations (8) 9 44 Total depreciation and amortization $ 65,501 $ 68,973 $ 62,661 Capital Expenditures Regulated Energy (3) $ 1,095,871 $ 97,554 $ 139,733 Unregulated Energy 40,264 40,773 81,651 Other businesses 1,762 2,355 6,425 Total capital expenditures $ 1,137,897 $ 140,682 $ 227,809 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details. (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details. As of December 31, (in thousands) 2023 2022 Identifiable Assets Regulated Energy segment $ 2,781,581 $ 1,716,255 Unregulated Energy segment 477,402 463,239 Other businesses and eliminations 45,721 35,543 Total identifiable assets $ 3,304,704 $ 2,215,037 |
Supplemental Cash Flow Disclo_2
Supplemental Cash Flow Disclosures (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Cash Paid for Interest and Income Taxes | Cash paid for interest and income taxes during the years ended December 31, 2023, 2022 and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (in thousands) Cash paid for interest $ 30,525 $ 24,267 $ 20,809 Cash (received) paid for income taxes, net of refunds $ 21,920 $ (4,963) $ 8,395 |
Non-Cash Investing and Financing Activities | Non-cash investing and financing activities during the years ended December 31, 2023, 2022, and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (in thousands) Capital property and equipment acquired on account, but not paid for as of December 31, $ 33,334 $ 13,211 $ 16,164 Common stock issued for the Retirement Savings Plan $ — $ — $ 1,712 Common stock issued under the SICP $ 3,740 $ 2,868 $ 2,834 |
Derivative Instruments (Tables)
Derivative Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Schedule of Derivative Instruments [Table Text Block] | As of December 31, 2023, the volume of our open 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 18.1 Cash flow hedges June 2026 Sharp Propane (gallons) Sales 3.2 Cash flow hedges March 2024 |
Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets | Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2023 and 2022 are as follows: Derivative Assets Fair Value as of (in thousands) Balance Sheet Location December 31, 2023 December 31, 2022 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value (1) $ 702 $ 3,317 Interest rate swap agreements Derivative assets, at fair value (1) 365 452 Total Derivative Assets $ 1,067 $ 3,769 (1) Derivative assets, at fair value include $1.0 million and $2.8 million in current assets in the consolidated balance sheet at December 31, 2023 and 2022, respectively, with the remainder of the balance classified as long-term. Derivative Liabilities Fair Value as of (in thousands) Balance Sheet Location December 31, 2023 December 31, 2022 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value (1) $ 1,078 $ 1,810 Interest rate swap agreements Derivative liabilities, at fair value (1) 203 405 Total Derivative Liabilities $ 1,281 $ 2,215 (1) |
Derivative Instruments, Gain (Loss) [Table Text Block] | The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows: Amount of Gain (Loss) on Derivatives: Location of Gain For the Year Ended December 31, (in thousands) 2023 2022 2021 Derivatives not designated as hedging instruments Propane swap agreements Propane and natural gas costs $ — $ 56 $ (1) Derivatives designated as fair value hedges Put/Call option Propane and natural gas costs — — (24) Derivatives designated as cash flow hedges Propane swap agreements Revenues 1,221 (373) (536) Propane swap agreements Propane and natural gas costs (1,160) 3,881 7,187 Interest rate swap agreements Interest expense 523 (47) (40) Total $ 584 $ 3,517 $ 6,586 |
Fair Value of Financial Instr_2
Fair Value of Financial Instruments (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Financial Assets and Liabilities Measured at Fair Value on Recurring Basis | The following tables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2023 and 2022, respectively: Fair Value Measurements Using: As of December 31, 2023 Fair Value Quoted Prices in Significant Other Significant (in thousands) Assets: Investments—equity securities $ 21 $ 21 $ — $ — Investments—guaranteed income fund 1,489 — — 1,489 Investments—mutual funds and other 10,772 10,772 — — Total investments 12,282 10,793 — 1,489 Derivative assets 1,067 — 1,067 — Total assets $ 13,349 $ 10,793 $ 1,067 $ 1,489 Liabilities: Derivative liabilities $ 1,281 $ — $ 1,281 $ — Fair Value Measurements Using: As of December 31, 2022 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Significant (in thousands) Assets: Investments—equity securities $ 24 $ 24 $ — $ — Investments—guaranteed income fund 1,853 — — 1,853 Investments—mutual funds and other 8,699 8,699 — — Total investments 10,576 8,723 — 1,853 Derivative assets 3,769 — 3,769 — Total assets $ 14,345 $ 8,723 $ 3,769 $ 1,853 Liabilities: Derivative liabilities $ 2,215 $ — $ 2,215 $ — |
Schedule of Changes in Fair Value of Plan Assets | The changes in the fair value of our Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income. |
Goodwill and Other Intangible_2
Goodwill and Other Intangible Assets (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Schedule of Carrying Value of Goodwill | The carrying value of goodwill as of December 31, 2023 and 2022 was as follows: (in thousands) Regulated Energy Unregulated Energy Total Goodwill Balance at December 31, 2022 $ 7,689 $ 38,524 $ 46,213 Additions (1) 461,025 936 461,961 Balance at December 31, 2023 $ 468,714 $ 39,460 $ 508,174 (1) |
Schedule of Carrying Value and Accumulated Amortization of Intangible Assets | The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2023 and 2022 was as follows: As of December 31, 2023 2022 (in thousands) Gross Accumulated Gross Accumulated Customer relationships $ 17,004 $ 7,146 $ 16,965 $ 6,131 Non-Compete agreements 3,125 1,855 3,105 1,411 Patents (1) 6,558 859 5,819 533 Other 270 232 270 225 Total $ 26,957 $ 10,092 $ 26,159 $ 8,300 |
Income Taxes (Tables)
Income Taxes (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Income Tax Disclosure [Abstract] | |
Schedule of Income Tax Expense | The following tables provide: (a) the components of income tax expense in 2023, 2022, and 2021; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2023, 2022, and 2021; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2023 and 2022. For the Year Ended December 31, 2023 2022 2021 (in thousands) Current Income Tax Expense Federal $ 14,736 $ 8,284 $ 2,775 State 5,496 1,948 (96) Other (47) (47) (47) Total current income tax expense (benefit) 20,185 10,185 2,632 Deferred Income Tax Expense (1) Property, plant and equipment 17,797 14,968 24,074 Deferred gas costs (7,739) 8,923 1,857 Pensions and other employee benefits (974) 1,109 (655) FPU merger-related premium cost and deferred gain (351) (351) (351) Net operating loss carryforwards (370) 2 97 Other (470) (1,004) 1,577 Total deferred income tax expense 7,893 23,647 26,599 Total Income Tax $ 28,078 $ 33,832 $ 29,231 (1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively. |
Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates | For the Year Ended December 31, 2023 2022 2021 (in thousands) Reconciliation of Effective Income Tax Rates Federal income tax expense (1) $ 24,214 $ 25,982 $ 23,666 State income taxes, net of federal benefit 4,377 7,714 6,371 ESOP dividend deduction (184) (177) (180) CARES Act Tax Benefit — — (919) Other (329) 313 293 Total Income Tax Expense $ 28,078 $ 33,832 $ 29,231 Effective Income Tax Rate 24.35 % 27.34 % 25.94 % (1) Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021. |
Schedule of Accumulated Deferred Income Tax Assets and Liabilities | As of December 31, 2023 2022 (in thousands) Deferred Income Taxes Deferred income tax liabilities: Property, plant and equipment $ 252,125 $ 238,687 Acquisition adjustment 5,564 5,915 Loss on reacquired debt 145 164 Deferred gas costs 3,550 11,288 Natural gas conversion costs 4,824 5,026 Storm reserve liability 5,797 5,791 Other 9,655 8,236 Total deferred income tax liabilities $ 281,660 $ 275,107 Deferred income tax assets: Pension and other employee benefits $ 4,993 $ 3,985 Environmental costs 951 1,052 Net operating loss carryforwards 1,847 1,488 Storm reserve liability 213 453 Accrued expenses 3,335 9,007 Other 11,239 2,955 Total deferred income tax assets $ 22,578 $ 18,940 Deferred Income Taxes Per Consolidated Balance Sheets $ 259,082 $ 256,167 |
Long-Term Debt (Tables)
Long-Term Debt (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Text Block [Abstract] | |
Outstanding Long-Term Debt | Our outstanding long-term debt is shown below: As of December 31, (in thousands) 2023 2022 Uncollateralized Senior Notes: 5.93% notes, due October 31, 2023 $ — $ 3,000 5.68% notes, due June 30, 2026 8,700 11,600 6.43% notes, due May 2, 2028 3,500 4,200 3.73% notes, due December 16, 2028 10,000 12,000 3.88% notes, due May 15, 2029 30,000 35,000 3.25% notes, due April 30, 2032 59,500 66,500 3.48% notes, due May 31, 2038 50,000 50,000 3.58% notes, due November 30, 2038 50,000 50,000 3.98% notes, due August 20, 2039 100,000 100,000 2.98% notes, due December 20, 2034 70,000 70,000 3.00% notes, due July 15, 2035 50,000 50,000 2.96% notes, due August 15, 2035 40,000 40,000 2.49% notes, due January 25, 2037 50,000 50,000 2.95% notes, due March 15, 2042 50,000 50,000 5.43% notes, due March 14, 2038 80,000 — 6.39% notes, due December 2026 100,000 — 6.44% notes, due December 2027 100,000 — 6.45% notes, due December 2028 100,000 — 6.62% notes, due December 2030 100,000 — 6.71% notes, due December 2033 100,000 — 6.73% notes, due December 2038 50,000 — Equipment security note 2.46% note, due September 24, 2031 7,633 8,517 Less: debt issuance costs (3,753) (946) Total long-term debt 1,205,580 599,871 Less: current maturities (18,505) (21,483) Total long-term debt, net of current maturities $ 1,187,075 $ 578,388 |
Line of Credit Facility [Line Items] | |
Schedule of Line of Credit Facilities [Table Text Block] | The following table summarizes the current available capacity under our Shelf Agreements at December 31, 2023: (in thousands) Total Borrowing Capacity Less Amount of Debt Issued Less Unfunded Commitments Remaining Borrowing Capacity Shelf Agreements (1) Prudential Shelf Agreement $ 405,000 $ (300,000) $ — $ 105,000 MetLife Shelf Agreement 200,000 (50,000) — 150,000 Total $ 605,000 $ (350,000) $ — $ 255,000 |
Leases Leases (Tables)
Leases Leases (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Leases [Abstract] | |
Lease, Cost [Table Text Block] | Year Ended December 31, (in thousands) Classification 2023 2022 Operating lease cost (1) Operations expense $ 3,040 $ 2,883 (1) Includes short-term leases and variable lease costs, which are immaterial. |
Schedule of Leases Reported on Consolidated Statement of Financial Position [Table Text Block] | The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2023 and 2022: (in thousands) Balance sheet classification December 31, 2023 December 31, 2022 Assets Operating lease assets Operating lease right-of-use assets $ 12,426 $ 14,421 Liabilities Current Operating lease liabilities Other accrued liabilities $ 2,454 $ 2,552 Noncurrent Operating lease liabilities Operating lease - liabilities 10,550 12,392 Total lease liabilities $ 13,004 $ 14,944 |
Leases, Weighted Average Remaining Lease Term [Table Text Block] | The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2023 and 2022: December 31, 2023 December 31, 2022 Weighted-average remaining lease term ( in years ) Operating leases 8.1 8.5 Weighted-average discount rate Operating leases 3.5 % 3.4 % |
Lease, Cash Flow [Table Text Block] | The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2023 and 2022: Year Ended December 31, (in thousands) 2023 2022 Operating cash flows from operating leases $ 2,906 $ 2,931 |
Lessee, Operating Lease, Liability, to be Paid, Maturity | The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2023 and for each of the next five years and thereafter: (in thousands) Operating Leases (1) 2024 $ 2,771 2025 2,288 2026 1,774 2027 1,583 2028 1,205 Thereafter 5,243 Total lease payments 14,864 Less: Interest (1,860) Present value of lease liabilities $ 13,004 (1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised. |
Stockholders' Equity (Tables)
Stockholders' Equity (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Equity [Abstract] | |
Schedule of Accumulated Other Comprehensive Income (Loss) | The following tables present the changes in the balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2023 and 2022. All amounts in the following tables are presented net of tax. Defined Benefit Pension and Postretirement Plan Items Commodity Contract Cash Flow Hedges Interest Rate Swap Cash Flow Hedges Total (in thousands) As of December 31, 2021 $ (3,268) $ 4,571 $ — $ 1,303 Other comprehensive income (loss) before reclassifications 705 (934) — (229) Amounts reclassified from accumulated other comprehensive income (loss) 57 (2,545) 35 (2,453) Net current-period other comprehensive income (loss) 762 (3,479) 35 (2,682) As of December 31, 2022 (2,506) 1,092 35 (1,379) Other comprehensive income (loss) before reclassifications (110) (1,322) 473 (959) Amounts reclassified from accumulated other comprehensive income (loss) 32 (44) (388) (400) Net current-period other comprehensive income (loss) (78) (1,366) 85 (1,359) As of December 31, 2023 $ (2,584) $ (274) $ 120 $ (2,738) |
Reclassification out of Accumulated Other Comprehensive Income | D |
Employee Benefit Plans (Tables)
Employee Benefit Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Schedule of Assets by Investment Type | The following schedule summarizes the assets of the FPU Pension Plan, by investment type, at December 31, 2023, 2022 and 2021: FPU Pension Plan At December 31, 2023 2022 2021 Asset Category Equity securities 50 % 53 % 52 % Debt securities 49 % 38 % 38 % Other 1 % 9 % 10 % Total 100 % 100 % 100 % |
Schedule of Asset Allocation Strategy | The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives: Asset Allocation Strategy Asset Class Minimum Allocation Percentage Maximum Allocation Percentage Domestic Equities (Large Cap, Mid Cap and Small Cap) 33 % 57 % Fixed Income (Inflation Bond and Taxable Fixed) 38 % 58 % Foreign Equities (Developed and Emerging Markets) 3 % 7 % Cash 0 % 5 % |
Summary of Pension Plan Assets | At December 31, 2023 and 2022, the assets of the FPU Pension Plan were comprised of the following investments: Fair Value Measurement Hierarchy For Year Ended December 31, Asset Category 2023 2022 (in thousands) Mutual Funds - Equity securities U.S. Large Cap (1) $ 15,360 $ 3,413 U.S. Mid Cap (1) 4,271 1,425 U.S. Small Cap (1) 2,518 692 International (2) 2,499 9,352 Alternative Strategies (3) — 4,824 24,648 19,706 Mutual Funds - Debt securities Fixed income (4) 24,228 15,343 High Yield (4) — 2,269 24,228 17,612 Mutual Funds - Other Commodities (5) — 1,832 Real Estate (6) — 1,709 Guaranteed deposit (7) 556 398 556 3,939 Total Pension Plan Assets in fair value hierarchy (8) 49,432 41,257 Investments measured at net asset value (9) — 4,946 Total Pension Plan Assets $ 49,432 $ 46,203 |
Schedule of Level Three Defined Benefit Plan Assets Roll Forward | The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2023 and 2022 were immaterial. |
Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets | As of December 31, 2023, there was $12.8 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $10.8 million and $1.2 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $3.2 million recorded in accumulated other comprehensive income (loss) and $8.7 million recorded as a regulatory asset at December 31, 2023. |
Schedule of Estimated Future Benefit Payments | The schedule below shows the estimated future benefit payments for each of the plans previously described: FPU Pension Plan (1) Chesapeake SERP (2) Chesapeake Postretirement Plan (2) FPU Medical Plan (2) (in thousands) 2024 $ 3,528 $ 151 $ 42 $ 35 2025 $ 3,603 $ 164 $ 46 $ 35 2026 $ 3,617 $ 161 $ 45 $ 34 2027 $ 3,616 $ 158 $ 48 $ 33 2028 $ 3,651 $ 154 $ 49 $ 32 Years 2029 through 2033 $ 17,951 $ 689 $ 299 $ 143 (1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets. (2) Benefit payments are expected to be paid out of our general funds. |
Pension benefit | |
Schedule of Funded Status of Benefit Obligation and Plan Assets | The following schedules set forth the funded status at December 31, 2023 and 2022 and the net periodic cost (benefit) for the years ended December 31, 2023, 2022 and 2021 for the FPU Pension Plan and the Chesapeake SERP: FPU Chesapeake At December 31, 2023 2022 2023 2022 (in thousands) Change in benefit obligation: Benefit obligation — beginning of year $ 49,941 $ 67,030 $ 1,659 $ 2,096 Interest cost 2,495 1,781 81 50 Actuarial (gain) loss 454 (15,713) 48 (335) Benefits paid (3,233) (3,157) (152) (152) Benefit obligation — end of year 49,657 49,941 1,636 1,659 Change in plan assets: Fair value of plan assets — beginning of year 46,203 58,712 — — Actual return on plan assets 6,462 (9,552) — — Employer contributions — 200 152 152 Benefits paid (3,233) (3,157) (152) (152) Fair value of plan assets — end of year 49,432 46,203 — — Accrued pension cost / funded status $ (225) $ (3,738) $ (1,636) $ (1,659) Assumptions: Discount rate 5.00 % 5.25 % 4.88 % 5.00 % Expected return on plan assets 6.00 % 6.00 % — % — % |
Component of Net Periodic Pension Cost (Benefit) | FPU Chesapeake For the Years Ended December 31, 2023 2022 2021 2023 2022 2021 (in thousands) Components of net periodic pension cost: Interest cost $ 2,495 $ 1,781 $ 1,714 $ 81 $ 50 $ 48 Expected return on assets (2,670) (3,430) (3,306) — — — Amortization of actuarial loss 407 466 612 8 28 28 Total periodic cost $ 232 $ (1,183) $ (980) $ 89 $ 78 $ 76 Assumptions: Discount rate 5.25 % 2.75 % 2.50 % 5.00 % 2.50 % 2.25 % Expected return on plan assets 6.00 % 6.00 % 6.00 % — % — % — % |
Other Postretirement Benefit Plans | |
Component of Net Periodic Pension Cost (Benefit) | Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2023, 2022, and 2021. |
Share-Based Compensation Plans
Share-Based Compensation Plans (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Share-Based Compensation Amounts Included in Net Income | The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2023, 2022 and 2021: For the Year Ended December 31, 2023 2022 2021 (in thousands) Awards to key employees $ 6,716 $ 5,479 $ 5,163 Awards to non-employee directors 906 959 782 Total compensation expense 7,622 6,438 5,945 Less: tax benefit (1,947) (1,663) (1,535) Share-based compensation amounts included in net income $ 5,675 $ 4,775 $ 4,410 |
Cash Proceeds Received and Tax Benefit from Share-based Payment Awards [Table Text Block] | The below table presents the number of shares withheld and amounts remitted: For the Year Ended December 31, 2023 2022 2021 (amounts in thousands, except shares) Shares withheld to satisfy tax obligations 19,859 21,832 14,020 Amounts remitted to tax authorities to satisfy obligations $ 2,455 $ 2,838 $ 1,478 |
SICP Awards to Key Employees | |
Summary of Stock Activity Non-employee directors | The table below presents the summary of the stock activity for awards to all officers: Number of Weighted Average Outstanding — December 31, 2021 197,398 $ 94.15 Granted 69,620 117.61 Vested (60,191) 90.60 Expired (2,678) 91.42 Outstanding — December 31, 2022 204,149 103.17 Granted 80,820 126.06 Vested (68,302) 91.59 Expired (2,053) 94.64 Forfeited (1,490) 113.44 Outstanding — December 31, 2023 213,124 $ 117.74 |
Rates and Other Regulatory Ac_2
Rates and Other Regulatory Activities Summary of Effects of Tax Reform Impact on Regulated Businesses (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Summary of Effects of Federal Tax Reform on Regulated Businesses [Abstract] | |
Summary of Effects of Federal Tax Reform on Regulated Businesses [Table Text Block] | Amount (in thousands) Operation and Regulatory Jurisdiction December 31, 2023 December 31, 2022 Status Eastern Shore (FERC) $34,190 $34,190 Will be addressed in Eastern Shore's next rate case filing. Chesapeake Delaware natural gas division (Delaware PSC) $12,038 $12,230 PSC approved amortization of ADIT in January 2019. Chesapeake Maryland natural gas division (Maryland PSC) $3,585 $3,703 PSC approved amortization of ADIT in May 2018. Sandpiper Energy (Maryland PSC) $3,487 $3,597 PSC approved amortization of ADIT in May 2018. Florida Natural Gas distribution (Florida PSC) (1) $26,757 $27,179 PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019. FPU electric division (Florida PSC) $4,760 $4,993 In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates. Elkton Gas (Maryland PSC) $1,027 $1,059 PSC approved amortization of ADIT in March 2018. |
Schedule of Regulatory Assets [Table Text Block] | At December 31, 2023 and 2022, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates. As of December 31, 2023 2022 (in thousands) Regulatory Assets Under-recovered purchased fuel, gas and conservation cost recovery (1) (2) $ 13,696 $ 43,583 Under-recovered GRIP revenue (3) 1,777 1,705 Deferred postretirement benefits (4) 10,802 13,927 Deferred conversion and development costs (1) 21,466 23,653 Acquisition adjustment (5) 31,857 25,609 Deferred costs associated with COVID-19 (6) 190 1,233 Deferred storm costs (7) 19,370 27,687 Deferred rate case expenses - current 1,171 — Other 15,573 12,256 Total Regulatory Assets $ 115,902 $ 149,653 Regulatory Liabilities Self-insurance (8) $ 521 $ 339 Over-recovered purchased fuel and conservation cost recovery (1) 12,340 3,827 Over-recovered GRIP revenue (3) 501 — Storm reserve (8) 1,900 2,845 Accrued asset removal cost (9) 86,534 50,261 Deferred income taxes due to rate change (10) 105,055 87,690 Interest related to storm recovery (7) 536 1,207 Other 1,611 1,851 Total Regulatory Liabilities $ 208,998 $ 148,020 (1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023. (3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP. (4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715 , Compensation - Retirement Benefits , related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16 , Employee Benefit Plans, for additional information. (5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above. (6) We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs. (7) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets. (8) We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred. (9) See Note 2 , Summary of Significant Accounting Policies, for additional information on our asset removal cost policies. (10) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes , for additional information. |
Environmental Commitments and_2
Environmental Commitments and Contingencies Environmental Remediation Status (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Environmental Remediation Obligations [Abstract] | |
Schedule of Environmental Loss Contingencies by Site [Table Text Block] | The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million. |
Other Commitments and Conting_2
Other Commitments and Contingencies Other Commitments and Contingencies (Tables) | 12 Months Ended |
Dec. 31, 2023 | |
Long-term Purchase Commitment [Line Items] | |
Long-term Purchase Commitment [Table Text Block] | The total purchase obligations for natural gas, electric and propane supplies are as follows: Year 2024 2025-2026 2027-2028 Beyond 2028 Total (in thousands) Purchase Obligations $ 86,040 $ 105,082 $ 83,851 $ 141,287 $ 416,260 |
Summary of Significant Accoun_4
Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 USD ($) mi | Dec. 31, 2022 USD ($) | |
Property, Plant and Equipment [Line Items] | ||
Contributions in Aid of Construction | $ 4,200 | $ 7,600 |
Number of Months to Establish ROU Asset and Liability | 12 months | |
Property, plant and equipment | ||
Total property, plant and equipment | $ 2,859,611 | 2,226,104 |
Less: Accumulated depreciation and amortization | (516,429) | (462,926) |
Net property, plant and equipment | 2,456,374 | 1,810,473 |
Construction Work in Progress | 113,192 | 47,295 |
Jointly Owned Pipeline [Member] | ||
Property, plant and equipment | ||
Net property, plant and equipment | 28,400 | |
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment | 2,200 | 1,500 |
Natural Gas Distribution [Member] | Delmarva and Florida [Member] | ||
Property, plant and equipment | ||
Total property, plant and equipment | 1,486,796 | 925,501 |
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member] | ||
Property, plant and equipment | ||
Total property, plant and equipment | 788,185 | 741,865 |
Natural Gas Transmission [Member] | OHIO | ||
Property, plant and equipment | ||
Total property, plant and equipment | 134,192 | 128,620 |
Electric distribution | Florida | ||
Property, plant and equipment | ||
Total property, plant and equipment | 143,513 | 135,633 |
Propane Operations [Member] | Mid-Atlantic and Florida [Member] | ||
Property, plant and equipment | ||
Total property, plant and equipment | 194,918 | 185,090 |
Electricity and Steam Generation [Member] | Florida | ||
Property, plant and equipment | ||
Total property, plant and equipment | 37,064 | 36,886 |
Mobile CNG Utility and Pipeline Solutions [Member] | Florida | ||
Property, plant and equipment | ||
Total property, plant and equipment | 40,558 | 38,543 |
Other | ||
Property, plant and equipment | ||
Total property, plant and equipment | 30,309 | 29,890 |
Other unregulated energy | Other [Member] | ||
Property, plant and equipment | ||
Total property, plant and equipment | $ 4,076 | $ 4,076 |
Natural Gas Operations | ||
Property, plant and equipment | ||
Miles Of Natural Gas Pipeline | mi | 26 |
Summary of Significant Accoun_5
Summary of Significant Accounting Policies - Additional Information (Detail) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 USD ($) mi | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Summary Of Accounting Policies [Line Items] | |||
Number of Months to Establish ROU Asset and Liability | 12 months | ||
Operating Lease, Liability | $ 13,004 | ||
Number of Utilities that do not have cost recovery mechanism | 1 | ||
Maturity Period To Be Considered Cash Equivalents | 3 months | ||
Contributions or Advances in Aid of Construction | $ 4,200 | $ 7,600 | |
Net property, plant and equipment | 2,456,374 | 1,810,473 | |
Accumulated depreciation | 516,429 | 462,926 | |
Depreciation and accretion reported in operations expenses | 11,900 | 11,000 | $ 10,200 |
Operating Lease, Right-of-Use Asset | $ 12,426 | $ 14,421 | |
Natural Gas Operations | |||
Summary Of Accounting Policies [Line Items] | |||
Length of pipeline | mi | 26 | ||
Minimum [Member] | |||
Summary Of Accounting Policies [Line Items] | |||
Operating Lease, Liability | $ 11,000 | ||
Maximum | |||
Summary Of Accounting Policies [Line Items] | |||
Operating Lease, Liability | $ 13,000 |
Summary of Significant Accoun_6
Summary of Significant Accounting Policies - Average Depreciation Rates (Detail) | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Natural gas distribution | Delmarva | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 2.50% | 2.50% | 2.50% |
Natural gas distribution | Florida | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 2.20% | 2.50% | 2.50% |
Natural gas transmission | Delmarva | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 2.70% | 2.70% | 2.70% |
Natural gas transmission | Florida | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 2.40% | 2.40% | 2.30% |
Natural gas transmission | OHIO | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 5% | 5% | |
Electric distribution | Florida | |||
Property, Plant and Equipment [Line Items] | |||
Average depreciation rates | 2.40% | 2.80% | 2.80% |
Summary of Significant Accoun_7
Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail) | Dec. 31, 2023 |
Propane Distribution Mains [Member] | Minimum | |
Useful Life of Assets | 10 years |
Propane Distribution Mains [Member] | Maximum | |
Useful Life of Assets | 37 years |
Propane Bulk Plants And Tanks [Member] | Minimum | |
Useful Life of Assets | 10 years |
Propane Bulk Plants And Tanks [Member] | Maximum | |
Useful Life of Assets | 40 years |
Liquefied Petroleum Gas Equipment [Member] | Minimum | |
Useful Life of Assets | 5 years |
Liquefied Petroleum Gas Equipment [Member] | Maximum | |
Useful Life of Assets | 33 years |
Meters And Meter Installations [Member] | Minimum | |
Useful Life of Assets | 5 years |
Meters And Meter Installations [Member] | Maximum | |
Useful Life of Assets | 33 years |
Measuring And Regulating Station Equipment [Member] | Minimum | |
Useful Life of Assets | 5 years |
Measuring And Regulating Station Equipment [Member] | Maximum | |
Useful Life of Assets | 37 years |
Natural gas pipelines [Member] | Maximum | |
Useful Life of Assets | 45 years |
Natural gas processing equipment [Member] | Minimum | |
Useful Life of Assets | 20 years |
Natural gas processing equipment [Member] | Maximum | |
Useful Life of Assets | 25 years |
Office Furniture And Equipment [Member] | Minimum | |
Useful Life of Assets | 3 years |
Office Furniture And Equipment [Member] | Maximum | |
Useful Life of Assets | 10 years |
Transportation Equipment [Member] | Minimum | |
Useful Life of Assets | 4 years |
Transportation Equipment [Member] | Maximum | |
Useful Life of Assets | 20 years |
Structures And Improvements [Member] | Minimum | |
Useful Life of Assets | 5 years |
Structures And Improvements [Member] | Maximum | |
Useful Life of Assets | 45 years |
CHP plant | Maximum | |
Useful Life of Assets | 30 years |
Summary of Significant Accoun_8
Summary of Significant Accounting Policies Effects of New Accounting Pronouncements (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Accounting Policies [Abstract] | ||
Additions, Charged to Income | $ 2,340 | |
Additions, Other Accounts | 166 | |
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction | (2,684) | |
Accounts Receivable, Allowance for Credit Losses, Current, Disclosure | $ 2,699 | $ 2,877 |
Earnings Per Share - Calculatio
Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract] | |||
Income (Loss) from Continuing Operations, Per Basic Share | $ 4.75 | $ 5.07 | $ 4.75 |
Calculation of Basic Earnings Per Share: | |||
Net Income | $ 87,212 | $ 89,796 | $ 83,466 |
Weighted shares outstanding - Basic (in shares) | 18,370,758 | 17,722,227 | 17,558,078 |
Basic Earnings Per Share (in usd per share) | $ 4.75 | $ 5.07 | $ 4.75 |
Calculation of Diluted Earnings Per Share: | |||
Net Income | $ 87,212 | $ 89,796 | $ 83,466 |
Reconciliation of Denominator: | |||
Weighted shares outstanding - Basic (in shares) | 18,370,758 | 17,722,227 | 17,558,078 |
Share-based Compensation | 64,099 | 82,067 | 74,951 |
Adjusted denominator — Diluted | 18,434,857 | 17,804,294 | 17,633,029 |
Income (Loss) from Continuing Operations, Per Diluted Share | $ 4.73 | $ 5.04 | $ 4.73 |
Diluted (in usd per share) | $ 4.73 | $ 5.04 | $ 4.73 |
Acquisitions - Additional Infor
Acquisitions - Additional Information (Detail) | 12 Months Ended | ||
Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | |
Business Combination, Separately Recognized Transactions [Line Items] | |||
Equity Issued in Business Combination, Fair Value Disclosure | $ 366,400,000 | ||
Proceeds from Issuance of Senior Long-Term Debt | 550,000,000 | ||
Business Acquisition, Transaction Costs | 4,100,000 | ||
Business Combination, Acquisition Related Costs | 15,900,000 | ||
Revenues | 670,604,000 | $ 680,704,000 | $ 569,968,000 |
Operating Income | 150,803,000 | 142,933,000 | 131,112,000 |
Transaction-related expenses | 10,355,000 | 0 | 0 |
Regulated Energy [Member] | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Operating Income | 126,199,000 | $ 115,317,000 | $ 106,174,000 |
Common Stock [Member] | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Proceeds from Issuance of Senior Long-Term Debt | 4,400,000 | ||
Florida City Gas | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Business Combination, Consideration Transferred | $ 923,400,000 | ||
Number of customers acquired through acquisition | 120,000 | ||
Number of Miles of Distribution Mains | 3,800 | ||
Number of Miles of Transmission Pipe | 80 | ||
Business Combination, Integration Related Costs | $ 10,400,000 | ||
Transaction-related expenses | 7,500,000 | ||
Property, Plant and Equipment, Acquired During Period | 453,845,000 | ||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | 461,193,000 | ||
Florida City Gas | Regulated Energy [Member] | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Revenues | 12,100,000 | ||
Operating Income | (3,300,000) | ||
J.T. Lee and Son's | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Business Combination, Consideration Transferred | $ 3,900,000 | ||
Number of customers acquired through acquisition | 3,000 | ||
Business Combination, Contingent Consideration, Liability | $ 300,000 | ||
Gallons acquired through acquisition | 800,000 | ||
Bulk Plant Storage Acquired Through Acquisition | 60,000 | ||
Property, Plant and Equipment, Acquired During Period | $ 2,700,000 | ||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | 900,000 | ||
Business Combination, Working Capital | 200,000 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets | 100,000 | ||
Planet Found | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Business Combination, Consideration Transferred | 9,500,000 | ||
Business Combination, Contingent Consideration, Liability | 900,000 | ||
Property, Plant and Equipment, Acquired During Period | 4,000,000 | ||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | 1,100,000 | ||
Business Combination, Working Capital | 100,000 | ||
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Indefinite-Lived Intangible Assets | $ 4,400,000 | ||
Tons of Poultry Litter | 1,200 | ||
Davenport Energy | |||
Business Combination, Separately Recognized Transactions [Line Items] | |||
Business Combination, Consideration Transferred | $ 2,000,000 | ||
Number of customers acquired through acquisition | 850 | ||
Gallons acquired through acquisition | 400,000 | ||
Property, Plant and Equipment, Acquired During Period | $ 1,500,000 | ||
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | $ 500,000 |
Acquisitions - Summary of Purch
Acquisitions - Summary of Purchase Price Allocation (Details) - Florida City Gas $ in Thousands | Dec. 31, 2023 USD ($) |
Business Combination, Separately Recognized Transactions [Line Items] | |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory | $ 2,270 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables | 14,396 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets | 2,983 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other | 2,707 |
Property, Plant and Equipment, Acquired During Period | 453,845 |
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net | 461,193 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets Regulatory assets - noncurrent | 3,381 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets | 18,309 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets [Abstract] | 959,084 |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities | (20,954) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities | (14,137) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other | (548) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other | (35,639) |
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net | $ 923,445 |
Acquisitions - Schedule of Pro
Acquisitions - Schedule of Pro Forma Information (Details) - Regulated Energy [Member] - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Business Combination, Separately Recognized Transactions [Line Items] | ||
Business Acquisition, Pro Forma Information, Description | $ 786,473 | $ 798,355 |
Business Acquisition, Pro Forma Net Income (Loss) | $ 85,398 | $ 81,508 |
Revenue Recognition Contract Ba
Revenue Recognition Contract Balances (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Revenue from Contract with Customer [Abstract] | ||
Receivables from Customers | $ 67,741 | $ 61,687 |
Contract with Customer, Asset, Net, Noncurrent | 3,524 | 4,321 |
Contract with Customer, Liability, Current | 1,022 | 983 |
Increase (Decrease) in Receivables | 6,054 | |
Increase (Decrease) in Other Noncurrent Assets | (797) | |
Increase (Decrease) in Other Current Liabilities | 39 | |
Contract with Customer, Asset, after Allowance for Credit Loss, Current | 18 | $ 18 |
Increase (Decrease) in Other Current Assets | $ 0 |
Revenue Recognition Disaggregat
Revenue Recognition Disaggregation of Revenue (Details) - USD ($) $ in Thousands | 12 Months Ended | |||||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||||
Disaggregation of Revenue [Line Items] | ||||||
Revenues | $ 670,604 | $ 680,704 | $ 569,968 | |||
Revenue from Contract with Customer, Excluding Assessed Tax | 670,604 | [1] | 680,704 | [2] | 569,968 | [3] |
Other And Intersegment Eliminations | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (26,139) | [1] | (29,470) | [2] | (20,821) | [3] |
Other [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 182 | 308 | 527 | |||
Other [Member] | Corporate, Non-Segment | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 182 | 308 | 527 | |||
Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 148,940 | 163,489 | 141,891 | |||
Eliminations [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (85,653) | (84,825) | (75,903) | |||
Eliminations [Member] | Consolidation, Eliminations [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (26,321) | (29,778) | (21,348) | |||
Regulated Energy | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 473,595 | [1] | 429,424 | [2] | 383,920 | [3] |
Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 420,880 | 376,843 | 334,404 | |||
Regulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 111,801 | 107,264 | 103,728 | |||
Regulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (59,086) | (54,683) | (54,212) | |||
Unregulated Energy | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 223,148 | [1] | 280,750 | [2] | 206,869 | [3] |
Unregulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 37,139 | 56,225 | 38,163 | |||
Unregulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (246) | (364) | (343) | |||
Other [Member] | Regulated Energy | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenues | 1,200 | 500 | 200 | |||
Other [Member] | Unregulated Energy | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenues | 400 | 400 | 400 | |||
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 134,609 | |||||
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 83,882 | 82,176 | 71,195 | |||
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 99,474 | 81,714 | 78,300 | |||
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 168,360 | 155,870 | ||||
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 28,092 | 26,607 | 22,449 | |||
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 20,185 | 21,278 | 20,746 | |||
Aspire [Member] | Unregulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 37,139 | 56,225 | 38,163 | |||
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 79,923 | 78,624 | 76,911 | |||
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 30,400 | 27,263 | 26,630 | |||
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 19,207 | 25,318 | 18,652 | |||
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 154,748 | 188,412 | 142,082 | |||
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 12,300 | 11,159 | 8,315 | |||
Eliminations [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (85,471) | (84,517) | (75,376) | |||
Eliminations [Member] | Other And Intersegment Eliminations | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (26,139) | (29,470) | (20,821) | |||
Eliminations [Member] | Regulated Energy | Other And Intersegment Eliminations | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (59,086) | (54,683) | (54,212) | |||
Eliminations [Member] | Unregulated Energy | Other And Intersegment Eliminations | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | (246) | (364) | (343) | |||
Aspire Energy Express | Regulated Energy | Energy Transmission [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 1,478 | 1,377 | 187 | |||
Elkton Gas [Member] | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | 8,814 | $ 9,198 | $ 7,105 | |||
Florida City Gas | Regulated Energy | Energy Distribution [Member] | ||||||
Disaggregation of Revenue [Line Items] | ||||||
Revenue from Contract with Customer, Excluding Assessed Tax | $ 12,073 | |||||
[1]Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees[2]Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees[3] (1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division) have been consolidated and amounts above are now being presented on a consolidated basis consistent with the final rate order. (2) |
Revenue Recognition Remaining p
Revenue Recognition Remaining performance obligations (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 36,657 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 9,680 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 652 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 46,989 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 30,330 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 9,216 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 275 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 39,821 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 26,547 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 8,501 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 275 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 35,323 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 23,433 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 6,472 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 275 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 30,180 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 22,559 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 5,252 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 275 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | 1 year |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 28,086 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Eastern Shore and Peninsula Pipeline [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 149,124 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Natural gas distribution operations [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 28,428 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | FPU Electric Distribution [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 0 |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Period | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Total for Segments [Member] | |
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items] | |
Revenue, Remaining Performance Obligation, Amount | $ 177,552 |
Segment Information - Schedule
Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | $ 670,604,000 | $ 680,704,000 | $ 569,968,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 670,604,000 | 680,704,000 | 569,968,000 | |
Operating Income | ||||
Operating Income | 150,803,000 | 142,933,000 | 131,112,000 | |
Other income | 1,438,000 | 5,051,000 | 1,720,000 | |
Interest charges | 36,951,000 | 24,356,000 | 20,135,000 | |
Income Before Income taxes | 115,290,000 | 123,628,000 | 112,697,000 | |
Income taxes | 28,078,000 | 33,832,000 | 29,231,000 | |
Net Income | 87,212,000 | 89,796,000 | 83,466,000 | |
Depreciation and Amortization | ||||
Total depreciation and amortization | 65,501,000 | 68,973,000 | 62,661,000 | |
Identifiable Assets | ||||
Total identifiable assets | 3,304,704,000 | 2,215,037,000 | ||
RSAM Adjustment | 5,100,000 | |||
Florida City Gas | ||||
Identifiable Assets | ||||
Business Combination, Consideration Transferred | 923,400,000 | |||
Regulated Energy | ||||
Operating Income | ||||
Operating Income | 126,199,000 | 115,317,000 | 106,174,000 | |
Depreciation and Amortization | ||||
Total depreciation and amortization | 48,162,000 | 52,707,000 | 48,748,000 | |
Payments to Acquire Productive Assets | 1,095,871,000 | 97,554,000 | 139,733,000 | |
Regulated Energy | Florida City Gas | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 12,100,000 | |||
Intersegment Revenues (1) | ||||
Total intersegment revenues | 12,100,000 | |||
Operating Income | ||||
Operating Income | (3,300,000) | |||
Unregulated Energy | ||||
Operating Income | ||||
Operating Income | 24,426,000 | 27,350,000 | 24,427,000 | |
Depreciation and Amortization | ||||
Total depreciation and amortization | 17,347,000 | 16,257,000 | 13,869,000 | |
Payments to Acquire Productive Assets | 40,264,000 | 40,773,000 | 81,651,000 | |
Other | ||||
Operating Income | ||||
Operating Income | 178,000 | 266,000 | 511,000 | |
Depreciation and Amortization | ||||
Payments to Acquire Productive Assets | 1,762,000 | 2,355,000 | 6,425,000 | |
Other and eliminations | ||||
Depreciation and Amortization | ||||
Total depreciation and amortization | (8,000) | 9,000 | 44,000 | |
Total for Segments [Member] | ||||
Depreciation and Amortization | ||||
Payments to Acquire Productive Assets | 1,137,897,000 | 140,682,000 | 227,809,000 | |
Operating Segments | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 670,604,000 | 680,704,000 | 569,968,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 670,604,000 | 680,704,000 | 569,968,000 | |
Operating Segments | Regulated Energy | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 471,591,000 | 422,894,000 | 381,879,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 471,591,000 | 422,894,000 | 381,879,000 | |
Identifiable Assets | ||||
Total identifiable assets | 2,781,581,000 | 1,716,255,000 | ||
Operating Segments | Unregulated Energy | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 199,013,000 | 257,810,000 | 188,089,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 199,013,000 | 257,810,000 | 188,089,000 | |
Identifiable Assets | ||||
Total identifiable assets | 477,402,000 | 463,239,000 | ||
Intersegment Eliminations | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | [1] | 26,321,000 | 29,778,000 | 21,348,000 |
Intersegment Revenues (1) | ||||
Total intersegment revenues | [1] | 26,321,000 | 29,778,000 | 21,348,000 |
Intersegment Eliminations | Regulated Energy | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 2,004,000 | 6,530,000 | 2,041,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 2,004,000 | 6,530,000 | 2,041,000 | |
Intersegment Eliminations | Unregulated Energy | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 24,135,000 | 22,940,000 | 18,780,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 24,135,000 | 22,940,000 | 18,780,000 | |
Intersegment Eliminations | Other | ||||
Operating Revenues, Unaffiliated Customers | ||||
Total intersegment revenues | 182,000 | 308,000 | 527,000 | |
Intersegment Revenues (1) | ||||
Total intersegment revenues | 182,000 | 308,000 | $ 527,000 | |
Other And Intersegment Eliminations | ||||
Identifiable Assets | ||||
Total identifiable assets | $ 45,721,000 | $ 35,543,000 | ||
[1]All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (2) Depreciation and amortization in 2023 includes a $5.1 million RSAM adjustment. See Note 18 for additional details. (3) Capital expenditures in 2023 include our acquisition of FCG for $923.4 million. See Note 4 for additional details. |
Supplemental Cash Flow Disclo_3
Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract] | |||
Cash paid for interest | $ 30,525 | $ 24,267 | $ 20,809 |
Cash paid for income taxes | $ 21,920 | $ (4,963) | $ 8,395 |
Supplemental Cash Flow Disclo_4
Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure Supplemental Cash Flow Disclosures Noncash Investing And Financing Activities [Abstract] | |||
Capital property and equipment acquired on account, but not paid as of December 31 | $ 33,334 | $ 13,211 | $ 16,164 |
Non Cash Performance Incentive Plan DRP | 0 | 0 | 1,712 |
Performance Incentive Plan | $ 3,740 | $ 2,868 | $ 2,834 |
Derivative Instruments - Additi
Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Feb. 28, 2021 | Dec. 31, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Derivative [Line Items] | ||||||
Energy Marketing Contract Liabilities, Current | $ 354 | $ 585 | ||||
Unrealized Gain (Loss) on Derivatives | 584 | 3,517 | $ 6,586 | |||
Notional Amount of Nonderivative Instruments | $ 40,000 | $ 60,000 | 50,000 | |||
Fixed Swap Rate | 0.17% | |||||
Derivative assets, at fair value | $ 1,027 | 2,787 | ||||
Interest Rate Swap Rate, Low Range [Member] | ||||||
Derivative [Line Items] | ||||||
Fixed Swap Rate | 0.20% | |||||
Interest Rate Swap Rate, High Range [Member] | ||||||
Derivative [Line Items] | ||||||
Fixed Swap Rate | 3.98% | |||||
Not Designated as Hedging Instrument [Member] | Propane Swap Agreement | ||||||
Derivative [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | 56 | (1) | |||
Derivatives designated as fair value hedges | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | 523 | (47) | (40) | |||
Derivatives designated as fair value hedges | Put Or Call Option [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | 0 | 0 | (24) | |||
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Propane Swap Agreement | ||||||
Derivative [Line Items] | ||||||
Derivative assets, at fair value | [1] | 702 | 3,317 | |||
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Derivative assets, at fair value | [1] | 365 | 452 | |||
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement | ||||||
Derivative [Line Items] | ||||||
Energy Marketing Contract Liabilities, Current | [2] | 1,078 | 1,810 | |||
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Interest Rate Swap [Member] | ||||||
Derivative [Line Items] | ||||||
Energy Marketing Contract Liabilities, Current | [2] | 203 | 405 | |||
Sharp Energy Inc [Member] | ||||||
Derivative [Line Items] | ||||||
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | (300) | |||||
Other Payables to Broker-Dealers and Clearing Organizations | 2,100 | 100 | ||||
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement | ||||||
Derivative [Line Items] | ||||||
Derivative, Gain (Loss) on Derivative, Net | $ (1,160) | $ 3,881 | $ 7,187 | |||
[1] (1) (1) |
Derivative Instruments Fair Val
Derivative Instruments Fair Value Hedges (Details) - USD ($) $ in Thousands | 1 Months Ended | 3 Months Ended | 12 Months Ended | |
Feb. 28, 2021 | Dec. 31, 2021 | Dec. 31, 2023 | Dec. 31, 2022 | |
Derivative Instruments and Hedging Activities Disclosure [Abstract] | ||||
Derivative liabilities, at fair value | $ 354 | $ 585 | ||
Notional Amount of Nonderivative Instruments | $ 40,000 | $ 60,000 | $ 50,000 |
Derivative Instruments - Fair V
Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Derivatives, Fair Value [Line Items] | |||
Energy Marketing Contracts Assets, Current | $ 1,027 | $ 2,787 | |
Energy Marketing Contracts Assets, Total | 1,067 | 3,769 | |
Energy Marketing Contract Liabilities, Current | 354 | 585 | |
Energy Marketing Contract Liabilities, Total | 1,281 | 2,215 | |
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement | |||
Derivatives, Fair Value [Line Items] | |||
Energy Marketing Contract Liabilities, Current | [1] | 1,078 | 1,810 |
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Interest Rate Swap [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Energy Marketing Contract Liabilities, Current | [1] | 203 | 405 |
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement | |||
Derivatives, Fair Value [Line Items] | |||
Energy Marketing Contracts Assets, Current | [2] | 702 | 3,317 |
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Interest Rate Swap [Member] | |||
Derivatives, Fair Value [Line Items] | |||
Energy Marketing Contracts Assets, Current | [2] | $ 365 | $ 452 |
[1] (1) (1) |
Derivative Instruments - Effect
Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Energy Marketing Contract Liabilities, Current | $ 354 | $ 585 | ||
Gain (Loss) on derivatives | 584 | 3,517 | $ 6,586 | |
Derivatives not designated as hedging instruments | Propane Swap Agreement | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 56 | $ (1) | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Propane and natural gas costs | Propane and natural gas costs | Propane and natural gas costs | |
Derivatives designated as fair value hedges | Put Or Call Option [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 0 | $ 0 | $ (24) | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Propane and natural gas costs | Propane and natural gas costs | Propane and natural gas costs | |
Derivatives designated as fair value hedges | Propane Swap Agreement | Revenue | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 1,221 | $ (373) | $ (536) | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Revenues | Revenues | Revenues | |
Derivatives designated as fair value hedges | Propane Swap Agreement | Cost of Sales | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ (1,160) | $ 3,881 | $ 7,187 | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Propane and natural gas costs | |||
Derivatives designated as fair value hedges | Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Derivative, Gain (Loss) on Derivative, Net | $ 523 | $ (47) | $ (40) | |
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration] | Interest charges | Interest charges | Interest charges | |
Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Propane Swap Agreement | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Energy Marketing Contract Liabilities, Current | [1] | $ 1,078 | $ 1,810 | |
Mark To Market Energy Liabilities [Member] | Derivatives designated as fair value hedges | Interest Rate Swap [Member] | ||||
Derivative Instruments, Gain (Loss) [Line Items] | ||||
Energy Marketing Contract Liabilities, Current | [1] | $ 203 | $ 405 | |
[1] (1) |
Derivative Instruments Volume o
Derivative Instruments Volume of Derivative Activity (Details) - Sharp Energy Inc [Member] | 12 Months Ended |
Dec. 31, 2023 gal | |
Swap [Member] | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | 18,100,000 |
Swap Sales | |
Derivative [Line Items] | |
Derivative, Nonmonetary Notional Amount, Volume | 3,200,000 |
Fair Value of Financial Instr_3
Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions | Dec. 31, 2023 | Dec. 31, 2022 |
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract] | ||
Long-term debt including current maturities | $ 1,200 | $ 600.8 |
Fair value of long-term debt | $ 1,200 | $ 505 |
Fair Value of Financial Instr_4
Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Assets: | ||
Investments | $ 12,282 | $ 10,576 |
Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Assets, Fair Value Disclosure | 10,793 | 8,723 |
Fair Value, Inputs, Level 1 [Member] | Mark-to-market energy liabilities | ||
Liabilities: | ||
Mark-to-market energy liabilities | 0 | 0 |
Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Assets, Fair Value Disclosure | 1,067 | 3,769 |
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities | ||
Liabilities: | ||
Mark-to-market energy liabilities | 1,281 | 2,215 |
Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Assets, Fair Value Disclosure | 1,489 | 1,853 |
Significant Unobservable Inputs (Level 3) | Mark-to-market energy liabilities | ||
Liabilities: | ||
Mark-to-market energy liabilities | 0 | 0 |
Equity Securities [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Investments | 21 | 24 |
Equity Securities [Member] | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Investments | 0 | 0 |
Equity Securities [Member] | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Investments | 0 | 0 |
Guaranteed Income Fund [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Investments | 0 | 0 |
Guaranteed Income Fund [Member] | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Investments | 0 | 0 |
Guaranteed Income Fund [Member] | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Investments | 1,489 | 1,853 |
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Investments | 10,772 | 8,699 |
Other Investments [Member] | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Investments | 0 | 0 |
Other Investments [Member] | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Investments | 0 | 0 |
Investments [Member] | Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Investments | 10,793 | 8,723 |
Investments [Member] | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Investments | 0 | 0 |
Investments [Member] | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Investments | 1,489 | 1,853 |
Mark-to-market energy assets, including put option | Fair Value, Inputs, Level 1 [Member] | ||
Assets: | ||
Mark-to-market energy assets, including put option | 0 | 0 |
Mark-to-market energy assets, including put option | Significant Other Observable Inputs (Level 2) | ||
Assets: | ||
Mark-to-market energy assets, including put option | 1,067 | 3,769 |
Mark-to-market energy assets, including put option | Significant Unobservable Inputs (Level 3) | ||
Assets: | ||
Mark-to-market energy assets, including put option | 0 | 0 |
Fair Value | ||
Assets: | ||
Assets, Fair Value Disclosure | 13,349 | 14,345 |
Fair Value | Mark-to-market energy liabilities | ||
Liabilities: | ||
Mark-to-market energy liabilities | 1,281 | 2,215 |
Fair Value | Equity Securities [Member] | ||
Assets: | ||
Investments | 21 | 24 |
Fair Value | Guaranteed Income Fund [Member] | ||
Assets: | ||
Investments | 1,489 | 1,853 |
Fair Value | Other Investments [Member] | ||
Assets: | ||
Investments | 10,772 | 8,699 |
Fair Value | Investments [Member] | ||
Assets: | ||
Investments | 12,282 | 10,576 |
Fair Value | Mark-to-market energy assets, including put option | ||
Assets: | ||
Mark-to-market energy assets, including put option | $ 1,067 | $ 3,769 |
Goodwill and Other Intangible_3
Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 26,957 | $ 26,159 | |
Acquired finite-lived intangible assets, weighted average useful life | 14 years | ||
Goodwill | $ 508,174 | 46,213 | |
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months | 1,800 | ||
Amortization of intangible assets | 1,800 | 1,500 | $ 1,300 |
Finite-Lived Intangible Assets, Amortization Expense, Year Four | 1,500 | ||
Amortization of intangible assets, 2020 | 1,600 | ||
Amortization of intangible assets, 2022 | 1,300 | ||
Regulated Energy | |||
Goodwill [Line Items] | |||
Goodwill | 468,714 | 7,689 | |
Unregulated Energy | |||
Goodwill [Line Items] | |||
Goodwill | 39,460 | 38,524 | |
Customer list | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 17,004 | 16,965 | |
Customer list | Minimum [Member] | |||
Goodwill [Line Items] | |||
Amortized period of acquired intangible assets | 5 years | ||
Noncompete Agreements [Member] | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 3,125 | $ 3,105 |
Goodwill and Other Intangible_4
Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | $ 26,957 | $ 26,159 | |
Finite-Lived Intangible Assets, Accumulated Amortization | 10,092 | 8,300 | |
Goodwill | 508,174 | 46,213 | |
Goodwill, Transfers | [1] | 461,961 | |
Regulated Energy | |||
Goodwill [Line Items] | |||
Goodwill | 468,714 | 7,689 | |
Goodwill, Transfers | 461,025 | ||
Unregulated Energy | |||
Goodwill [Line Items] | |||
Goodwill | 39,460 | 38,524 | |
Goodwill, Transfers | 936 | ||
Customer Lists [Member] | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | 17,004 | 16,965 | |
Finite-Lived Intangible Assets, Accumulated Amortization | 7,146 | 6,131 | |
Noncompete Agreements [Member] | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | 3,125 | 3,105 | |
Finite-Lived Intangible Assets, Accumulated Amortization | 1,855 | 1,411 | |
Patents [Member] | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | [2] | 6,558 | 5,819 |
Finite-Lived Intangible Assets, Accumulated Amortization | [2] | 859 | 533 |
Other Intangible Assets [Member] | |||
Goodwill [Line Items] | |||
Finite-Lived Intangible Assets, Gross | 270 | 270 | |
Finite-Lived Intangible Assets, Accumulated Amortization | $ 232 | $ 225 | |
[1] (1) 2023 additions primarily attributable to goodwill from the November 2023 acquisition of FCG. See Note 4 for additional details. (1) |
Goodwill and Other Intangible_5
Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Finite-Lived Intangible Assets [Line Items] | |||
Gross Carrying Amount | $ 26,957 | $ 26,159 | |
Accumulated Amortization | 10,092 | 8,300 | |
Customer Lists [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Gross Carrying Amount | 17,004 | 16,965 | |
Accumulated Amortization | 7,146 | 6,131 | |
Noncompete Agreements [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Gross Carrying Amount | 3,125 | 3,105 | |
Accumulated Amortization | 1,855 | 1,411 | |
Patents [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Gross Carrying Amount | [1] | 6,558 | 5,819 |
Accumulated Amortization | [1] | 859 | 533 |
Other Intangible Assets [Member] | |||
Finite-Lived Intangible Assets [Line Items] | |||
Gross Carrying Amount | 270 | 270 | |
Accumulated Amortization | $ 232 | $ 225 | |
[1] (1) |
Income Taxes - Additional Infor
Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Operating Loss Carryforwards [Line Items] | |||
Deferred Tax Assets, Operating Loss Carryforwards | $ 1,847 | $ 1,488 | |
Net Operating Losses and Tax Carryback | 0 | 0 | $ 919 |
Deferred State and Local Income Tax Expense (Benefit) | $ 100 | 7,800 | 8,200 |
Net Operating Losses and Tax Carryback, Total | $ (900) | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | ||
Deferred Tax Assets, Operating Loss Carryforwards | $ 1,847 | 1,488 | |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | ||
State | |||
Operating Loss Carryforwards [Line Items] | |||
Federal net operating losses for income tax | $ 72,900 | $ 67,700 |
Income Taxes - Schedule of Inco
Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Current Income Tax Expense | ||||
Federal | $ 14,736 | $ 8,284 | $ 2,775 | |
State | 5,496 | 1,948 | (96) | |
Other | (47) | (47) | (47) | |
Total current income tax expense (benefit) | 20,185 | 10,185 | 2,632 | |
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | [1] | 7,893 | 23,647 | 26,599 |
Total Income Tax | 28,078 | 33,832 | 29,231 | |
Deferred State and Local Income Tax Expense (Benefit) | 100 | 7,800 | 8,200 | |
Property, plant and equipment | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | 17,797 | 14,968 | 24,074 | |
Deferred gas costs | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | (7,739) | 8,923 | 1,857 | |
Pensions and other employee benefits | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | (974) | 1,109 | (655) | |
FPU merger related premium cost and deferred gain | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | (351) | (351) | (351) | |
Net operating loss carryforwards | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | (370) | 2 | 97 | |
Other | ||||
Deferred Income Tax Expense (1) | ||||
Total deferred income tax expense | $ (470) | $ (1,004) | $ 1,577 | |
[1] (1) Includes less than $0.1 million, $7.8 million, and $8.2 million of deferred state income taxes for the years 2023, 2022 and 2021, respectively. |
Income Taxes - Summary of Recon
Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Thousands | 12 Months Ended | |||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | ||
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract] | ||||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | |||
Reconciliation of Effective Income Tax Rates Continuing Operations | ||||
Federal income tax expense (1) | [1] | $ 24,214 | $ 25,982 | $ 23,666 |
State income taxes, net of federal benefit | 4,377 | 7,714 | 6,371 | |
ESOP dividend deduction | (184) | (177) | (180) | |
Other | (329) | 313 | 293 | |
Total Income Tax | $ 28,078 | $ 33,832 | $ 29,231 | |
Effective Income Tax Rate | 24.35% | 27.34% | 25.94% | |
Net Operating Losses and Tax Carryback | $ 0 | $ 0 | $ (919) | |
[1]Federal income taxes were calculated at 21 percent for 2023, 2022, and 2021. |
Income Taxes - Schedule of Accu
Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract] | |||
Deferred State and Local Income Tax Expense (Benefit) | $ 100 | $ 7,800 | $ 8,200 |
Deferred income tax liabilities: | |||
Property, plant and equipment | 252,125 | 238,687 | |
Acquisition adjustment | 5,564 | 5,915 | |
Deferred Tax Liabilities Loss On Reacquired Debt | 145 | 164 | |
Deferred Income Tax Liability - Deferred Gas Costs | 3,550 | 11,288 | |
Deferred Income Tax Liability, Natural Gas Conversion Costs | 4,824 | 5,026 | |
Deferred Income Tax Liability, Storm Reserve | 5,797 | 5,791 | |
Other | 9,655 | 8,236 | |
Total deferred income tax liabilities | 281,660 | 275,107 | |
Deferred income tax assets: | |||
Pension and other employee benefits | 4,993 | 3,985 | |
Environmental costs | 951 | 1,052 | |
Net operating loss carryforwards | 1,847 | 1,488 | |
Storm reserve liability | 213 | 453 | |
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals | 3,335 | 9,007 | |
Other | 11,239 | 2,955 | |
Total deferred income tax assets | 22,578 | 18,940 | |
Deferred Income Tax Liabilities, Net | $ 259,082 | $ 256,167 |
Income Taxes - Schedule of In_2
Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract] | |||
Deferred state income taxes | $ 0.1 | $ 7.8 | $ 8.2 |
Components Of Income Tax Expense Benefit [Line Items] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | ||
Maximum [Member] | |||
Components Of Income Tax Expense Benefit [Line Items] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35% | ||
Minimum [Member] | |||
Components Of Income Tax Expense Benefit [Line Items] | |||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% |
Income Taxes - Summary of Rec_2
Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail) | 12 Months Ended |
Dec. 31, 2023 | |
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract] | |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% |
Income Taxes Federal Tax Reform
Income Taxes Federal Tax Reform (Details) | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2021 | |
Components Of Income Tax Expense Benefit [Line Items] | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | |
Maximum [Member] | ||
Components Of Income Tax Expense Benefit [Line Items] | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35% | |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 35% | |
Minimum [Member] | ||
Components Of Income Tax Expense Benefit [Line Items] | ||
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% | |
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent | 21% |
Long-Term Debt - Additional Inf
Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 6.54% | |
Debt Instrument, Unused Borrowing Capacity, Amount | $ 255,000 | |
Long-term debt including current maturities | 1,200,000 | $ 600,800 |
Long-term Debt and Lease Obligation | 1,205,580 | 599,871 |
Total long-term debt, net of current maturities | 1,187,075 | 578,388 |
Unamortized Debt Issuance Expense | (3,753) | (946) |
Long-term Debt and Lease Obligation, Current | (18,505) | (21,483) |
MetLife [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Unused Borrowing Capacity, Amount | 150,000 | |
Long-term debt including current maturities | 50,000 | |
MetLife [Member] | Maximum [Member] | ||
Debt Instrument [Line Items] | ||
Face amount | 200,000 | |
Prudential [Member] | ||
Debt Instrument [Line Items] | ||
Debt Instrument, Unused Borrowing Capacity, Amount | 105,000 | |
Long-term debt including current maturities | 300,000 | |
Prudential [Member] | Maximum [Member] | ||
Debt Instrument [Line Items] | ||
Face amount | $ 405,000 | |
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 5.68% | |
Long-term debt including current maturities | $ 8,700 | 11,600 |
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 2.98% | |
Long-term debt including current maturities | $ 70,000 | |
Uncollateralized Senior Note Due On May 2 Two Thousand Twenty Eight [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 6.43% | |
Long-term debt including current maturities | $ 3,500 | 4,200 |
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3.73% | |
Long-term debt including current maturities | $ 10,000 | 12,000 |
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3.88% | |
Long-term debt including current maturities | $ 30,000 | 35,000 |
Uncollateralized Senior Note Due On Two Thousand Twenty Three [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 5.93% | |
Long-term debt including current maturities | $ 0 | 3,000 |
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3.25% | |
Long-term debt including current maturities | $ 59,500 | 66,500 |
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3.48% | |
Long-term debt including current maturities | $ 50,000 | 50,000 |
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3.58% | |
Long-term debt including current maturities | $ 50,000 | 50,000 |
Uncollateralized Senior Note Due November Two Thousand Thirty Nine | ||
Debt Instrument [Line Items] | ||
Long-term debt including current maturities | $ 100,000 | 100,000 |
Uncollateralized Senior Note Due November Two Thousand Thirty Four | ||
Debt Instrument [Line Items] | ||
Long-term debt including current maturities | 70,000 | |
Uncollateralized Senior Note Due July Two Thousand Thirty Five | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 3% | |
Long-term debt including current maturities | $ 50,000 | 50,000 |
Uncollateralized Senior Note Due August Two Thousand Thirty Five | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 2.96% | |
Long-term debt including current maturities | $ 40,000 | 40,000 |
Uncollateralized Senior Note Due January Two Thousand Thirty Seven | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 2.49% | |
Long-term debt including current maturities | $ 50,000 | 50,000 |
Equipment Security Note | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 2.46% | |
Long-term debt including current maturities | $ 7,633 | 8,517 |
Uncollateralized Senior Note Due March 15, 2042 | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 2.95% | |
Long-term debt including current maturities | $ 50,000 | $ 50,000 |
Uncollateralized Senior Note Due March 14, 2038 | ||
Debt Instrument [Line Items] | ||
Long-term debt, interest percentage | 5.43% | |
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member] | ||
Debt Instrument [Line Items] | ||
Long-term debt including current maturities | $ 80,000 |
Long-Term Debt - Outstanding Lo
Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Debt Instrument [Line Items] | |||
Long-term Debt | $ 1,200,000 | $ 600,800 | |
Less: debt issuance costs | (3,753) | (946) | |
Long-term Debt and Lease Obligation | 1,205,580 | 599,871 | |
Less: current maturities | (18,505) | (21,483) | |
Total long-term debt, net of current maturities | $ 1,187,075 | 578,388 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.54% | ||
Proceeds from issuance of long-term debt | $ 627,011 | 49,859 | $ 59,478 |
Proceeds from Issuance of Senior Long-Term Debt | 550,000 | ||
Common Stock [Member] | |||
Debt Instrument [Line Items] | |||
Proceeds from Issuance of Senior Long-Term Debt | 4,400 | ||
Prudential [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | 300,000 | ||
5.93% note, due October 31, 2023 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 0 | 3,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.93% | ||
5.68% note, due June 30, 2026 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 8,700 | 11,600 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.68% | ||
6.43% note, due May 2, 2028 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 3,500 | 4,200 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.43% | ||
3.73% note, due December 16, 2028 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 10,000 | 12,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.73% | ||
3.88% note, due May 15, 2029 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 30,000 | 35,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.88% | ||
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 59,500 | 66,500 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.25% | ||
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 50,000 | 50,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.48% | ||
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 50,000 | 50,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 3.58% | ||
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Interest Rate, Stated Percentage | 3.98% | ||
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 70,000 | ||
Debt Instrument, Interest Rate, Stated Percentage | 2.98% | ||
Uncollateralized Senior Note Due March 15, 2042 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 50,000 | 50,000 | |
Debt Instrument, Interest Rate, Stated Percentage | 2.95% | ||
Uncollateralized Senior Note Due March 14, 2038 [Abstract] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 80,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 5.43% | ||
Uncollateralized Senior Note Due December 2026 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.39% | ||
Uncollateralized Senior Note Due December 2027 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.44% | ||
Uncollateralized Senior Note Due December 2028 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.45% | ||
Uncollateralized Senior Note Due December 2030 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.62% | ||
Uncollateralized Senior Note Due December 2033 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 100,000 | 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.71% | ||
Uncollateralized Senior Note Due December 2038 | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 50,000 | $ 0 | |
Debt Instrument, Interest Rate, Stated Percentage | 6.73% | ||
Uncollateralized Senior Note Due March 14, 2038 | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Interest Rate, Stated Percentage | 5.43% | ||
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member] | |||
Debt Instrument [Line Items] | |||
Long-term Debt | $ 80,000 |
Long-Term Debt - Outstanding _2
Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.54% | ||
Proceeds from issuance of long-term debt | $ 627,011 | $ 49,859 | $ 59,478 |
5.93% note, due October 31, 2023 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 5.93% | ||
Debt Instrument, Maturity Date | Oct. 31, 2023 | ||
5.68% note, due June 30, 2026 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 5.68% | ||
Debt Instrument, Maturity Date | Jun. 30, 2026 | ||
6.43% note, due May 2, 2028 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.43% | ||
Debt Instrument, Maturity Date | May 02, 2028 | ||
3.73% note, due December 16, 2028 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.73% | ||
Debt Instrument, Maturity Date | Dec. 16, 2028 | ||
3.88% note, due May 15, 2029 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.88% | ||
Debt Instrument, Maturity Date | May 15, 2029 | ||
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member] | |||
Debt Instrument [Line Items] | |||
Debt Instrument, Maturity Date | Apr. 30, 2032 | ||
Uncollateralized Senior Note Due May Two Thousand Thirty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.48% | ||
Debt Instrument, Maturity Date | May 31, 2038 | ||
Uncollateralized Senior Note Due November Two Thousand Thirty Eight [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.58% | ||
Debt Instrument, Maturity Date | Nov. 30, 2038 | ||
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.98% | ||
Debt Instrument, Maturity Date | Aug. 20, 2039 | ||
Uncollateralized Senior Note Due December Two Thousand Thirty Four [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 2.98% | ||
Debt Instrument, Maturity Date | Dec. 20, 2034 | ||
Uncollateralized Senior Note Due July Two Thousand Thirty Five | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3% | ||
Debt Instrument, Maturity Date | Jul. 15, 2035 | ||
Uncollateralized Senior Note Due August Two Thousand Thirty Five | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 2.96% | ||
Debt Instrument, Maturity Date | Aug. 15, 2035 | ||
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 3.25% | ||
Equipment Security Note | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 2.46% | ||
Debt Instrument, Maturity Date | Sep. 24, 2031 | ||
Uncollateralized Senior Note Due January Two Thousand Thirty Seven | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 2.49% | ||
Debt Instrument, Maturity Date | Jan. 25, 2037 | ||
Uncollateralized Senior Note Due March 15, 2042 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 2.95% | ||
Debt Instrument, Maturity Date | Mar. 15, 2042 | ||
Uncollateralized Senior Note Due March 14, 2038 [Abstract] | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 5.43% | ||
Debt Instrument, Maturity Date | Mar. 14, 2038 | ||
Uncollateralized Senior Note Due December 2026 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.39% | ||
Debt Instrument, Maturity Date | Dec. 31, 2026 | ||
Uncollateralized Senior Note Due December 2027 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.44% | ||
Debt Instrument, Maturity Date | Dec. 31, 2027 | ||
Uncollateralized Senior Note Due December 2028 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.45% | ||
Debt Instrument, Maturity Date | Dec. 31, 2028 | ||
Uncollateralized Senior Note Due December 2030 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.62% | ||
Debt Instrument, Maturity Date | Dec. 31, 2030 | ||
Uncollateralized Senior Note Due December 2033 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.71% | ||
Debt Instrument, Maturity Date | Dec. 31, 2033 | ||
Uncollateralized Senior Note Due December 2038 | |||
Debt Instrument [Line Items] | |||
Long-term debt, interest percentage | 6.73% | ||
Debt Instrument, Maturity Date | Dec. 31, 2038 |
Long-Term Debt Annual Maturitie
Long-Term Debt Annual Maturities (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Long Term Debt Annual Maturities [Abstract] | |
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months | $ 18,505 |
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two | 25,528 |
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Three | 134,551 |
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four | 131,674 |
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Five | 136,699 |
Long-term Debt, Maturities, Repayments of Principal in Rolling after Year Five | 762,376 |
Total Future Repayments | $ 1,209,333 |
Long-Term Debt Shelf Arrangemen
Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (1,200,000) | $ (600,800) |
Debt Instrument, Interest Rate, Stated Percentage | 6.54% | |
Debt Instrument, Unused Borrowing Capacity, Amount | $ 255,000 | |
Prudential [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | (300,000) | |
Debt Instrument, Unused Borrowing Capacity, Amount | 105,000 | |
MetLife [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | (50,000) | |
Debt Instrument, Unused Borrowing Capacity, Amount | 150,000 | |
Aggregate Shelf Agreements [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | (350,000) | |
Aggregated Unfunded Commitments [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | 0 | |
Aggregated Unfunded Commitments [Member] | Prudential [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | 0 | |
Aggregated Unfunded Commitments [Member] | MetLife [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | 0 | |
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (59,500) | (66,500) |
Debt Instrument, Interest Rate, Stated Percentage | 3.25% | |
Uncollateralized Senior Note Due August Two Thousand Thirty Nine [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 3.98% | |
Uncollateralized Senior Note Due July Two Thousand Thirty Five | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (50,000) | (50,000) |
Debt Instrument, Interest Rate, Stated Percentage | 3% | |
Uncollateralized Senior Note Due August Two Thousand Thirty Five | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (40,000) | $ (40,000) |
Debt Instrument, Interest Rate, Stated Percentage | 2.96% | |
Uncollateralized Senior Note Due March 14, 2038 | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Interest Rate, Stated Percentage | 5.43% | |
Uncollateralized Senior Note Due March 14, 2038 | Prudential [Member] | ||
Line of Credit Facility [Line Items] | ||
Long-term Debt | $ (80,000) | |
Maximum [Member] | Prudential [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Face Amount | 405,000 | |
Maximum [Member] | MetLife [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Face Amount | 200,000 | |
Maximum [Member] | Aggregate Shelf Agreements [Member] | ||
Line of Credit Facility [Line Items] | ||
Debt Instrument, Face Amount | $ 605,000 |
Short-Term Borrowing - Addition
Short-Term Borrowing - Additional Information (Detail) | 1 Months Ended | 3 Months Ended | 12 Months Ended | |||
Feb. 28, 2021 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2023 USD ($) | Oct. 31, 2023 | Sep. 30, 2023 | Dec. 31, 2022 USD ($) | |
Short-term Debt [Line Items] | ||||||
Short-term borrowings | $ 179,853,000 | $ 202,157,000 | ||||
Number Of Unsecured Bank Credit Facilities | 3 | |||||
Short-term Debt, Weighted Average Interest Rate, at Point in Time | 5.83% | 5.04% | ||||
Ratio of Indebtedness to Net Capital | 0.70 | 0.65 | ||||
Long-term debt including current maturities | $ 1,200,000,000 | $ 600,800,000 | ||||
Line of Credit Facility, Commitment Fee Percentage | 9,500% | |||||
Line of Credit Facility, Remaining Borrowing Capacity | $ 188,100,000 | |||||
Notional Amount of Nonderivative Instruments | $ 40,000,000 | $ 60,000,000 | $ 50,000,000 | |||
Fixed Swap Rate | 0.17% | |||||
Debt Instrument, Interest Rate, Stated Percentage | 6.54% | |||||
Amount of letter of credit to our current primary insurance company | $ 7,000,000 | |||||
Florida City Gas | Regulated Energy [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Bridge Loan | 965,000,000 | |||||
Revolving Credit Facility [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Line of Credit Facility, Aggregate Borrowing Capacity | $ 375,000,000 | |||||
Interest Rate Swap Rate, Low Range [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Fixed Swap Rate | 0.20% | |||||
Interest Rate Swap Rate, High Range [Member] | ||||||
Short-term Debt [Line Items] | ||||||
Fixed Swap Rate | 3.98% | |||||
Revolving Line of Credit, Short-term | ||||||
Short-term Debt [Line Items] | ||||||
Debt Instrument, Interest Rate, Stated Percentage | 7,500% | |||||
Debt Instrument, Fee | 9 | |||||
Aggregate Investment, Maximum | $ 175,000,000 | $ 150,000,000 | ||||
Ownership Interest | 0.50 | |||||
Interest Rate Credit Adjustment | 10 | |||||
Line Of Credit Facility Interest Rate Description 2 | $ 0.0005 | |||||
Line Of Credit Facility Interest Rate Description 1 | $ 0.01 | |||||
Line of Credit Facility, Interest Rate Description | 1.05 percent | |||||
Revolving Line of Credit, Long-term | ||||||
Short-term Debt [Line Items] | ||||||
Debt Instrument, Fee | 9 | |||||
Interest Rate Credit Adjustment | 10 |
Short-Term Borrowing Short-Term
Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) | 12 Months Ended | |
Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | |
Short-term Debt [Line Items] | ||
Line of Credit Facility, Remaining Borrowing Capacity | $ 188,100,000 | |
Short-term borrowing | $ 179,853,000 | $ 202,157,000 |
Number Of Unsecured Bank Credit Facilities | 3 | |
Revolving Credit Facility [Member] | ||
Short-term Debt [Line Items] | ||
Line of Credit Facility, Maximum Borrowing Capacity | $ 375,000,000 |
Leases Schedule of Future Minim
Leases Schedule of Future Minimum Rental Payment for Operating Leases (Details) $ in Thousands | Dec. 31, 2023 USD ($) | |
Leases [Abstract] | ||
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months | $ 2,771 | [1] |
Lessee Future Operating Lease Option Payments | 2,100 | |
Lessee, Operating Lease, Liability, Payments, Due Year Two | 2,288 | [1] |
Lessee, Operating Lease, Liability, Payments, Due Year Three | 1,774 | [1] |
Lessee, Operating Lease, Liability, Payments, Due Year Four | 1,583 | [1] |
Lessee, Operating Lease, Liability, Payments, Due Year Five | 1,205 | [1] |
Lessee, Operating Lease, Liability, Payments, Due after Year Five | 5,243 | [1] |
Lessee, Operating Lease, Liability, Payments, Due | 14,864 | [1] |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | (1,860) | |
Operating Lease, Liability | $ 13,004 | |
[1] (1) |
Leases Lease Cost Additional (D
Leases Lease Cost Additional (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Leases [Abstract] | |||
Operating Lease, Cost | $ 3,040 | $ 2,883 | [1] |
[1]1) Includes short-term leases and variable lease costs, which are immaterial |
Leases Leases - Right of Use As
Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
Operating Lease, Liability, Current, Statement of Financial Position [Extensible List] | Other accrued liabilities | Other accrued liabilities |
Operating Lease, Right-of-Use Asset | $ 12,426 | $ 14,421 |
Operating Lease, Liability, Current | 2,454 | 2,552 |
Operating Lease, Liability, Noncurrent | 10,550 | 12,392 |
Total Operating and Finance Lease Liabilities | $ 13,004 | $ 14,944 |
Leases Weighted Average Remaini
Leases Weighted Average Remaining Lease Term Additional Information (Details) | Dec. 31, 2023 | Dec. 31, 2022 |
Leases [Abstract] | ||
Operating Lease, Weighted Average Remaining Lease Term | 8 years 1 month 6 days | 8 years 6 months |
Operating Lease, Weighted Average Discount Rate, Percent | 3.50% | 3.40% |
Leases Lease Cash Flows Additio
Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Leases Cash Flows [Abstract] | ||
Operating Lease, Payments | $ 2,931 | $ 2,906 |
Lessee, Operating Lease, Liability, Undiscounted Excess Amount | $ (1,860) |
Stockholders' Equity Additional
Stockholders' Equity Additional Details (Details) - USD ($) | 6 Months Ended | 12 Months Ended | |||
Jun. 30, 2023 | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | Nov. 30, 2023 | |
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Preferred Stock, Shares Authorized | 2,000,000 | 2,000,000 | |||
Preferred Stock, Par or Stated Value Per Share | $ 0.01 | $ 0.01 | |||
Proceeds from issuance of common stock, net of expenses | $ 366,417,000 | $ 0 | $ 0 | ||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 100,000 | ||||
Stock Issued During Period, Value, Dividend Reinvestment Plan | $ 136.26 | ||||
Issuance of stock for Dividend Reinvestment Plan | $ 4,500,000 | ||||
Florida City Gas | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 4,438,596 | ||||
Common Stock [Member] | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Stock Issued During Period, Shares, Dividend Reinvestment Plan | 39,418 | ||||
Shares Issued, Price Per Share | $ 82.72 | ||||
Common Stock [Member] | Florida City Gas | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | 4,400,000 | ||||
Maximum [Member] | |||||
Accumulated Other Comprehensive Income (Loss) [Line Items] | |||||
Proceeds from Stock Plans | $ 75,000,000 |
Stockholders' Equity Accumulate
Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | $ (1,379) | $ 1,303 | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (959) | (229) | |
Amounts reclassified from accumulated other comprehensive income/(loss) | (400) | (2,453) | |
Net current-period other comprehensive income/(loss) | (1,359) | (2,682) | |
Accumulated other comprehensive loss at end of period | (2,738) | (1,379) | $ 1,303 |
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member] | |||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | (2,506) | (3,268) | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (110) | 705 | |
Amounts reclassified from accumulated other comprehensive income/(loss) | 32 | 57 | |
Net current-period other comprehensive income/(loss) | (78) | 762 | |
Accumulated other comprehensive loss at end of period | (2,584) | (2,506) | (3,268) |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | |||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | 1,092 | 4,571 | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (1,322) | (934) | |
Amounts reclassified from accumulated other comprehensive income/(loss) | (44) | (2,545) | (4,813) |
Net current-period other comprehensive income/(loss) | (1,366) | (3,479) | |
Accumulated other comprehensive loss at end of period | (274) | 1,092 | 4,571 |
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges | |||
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward] | |||
Accumulated other comprehensive loss at beginning of period | 35 | 0 | |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | 473 | 0 | |
Amounts reclassified from accumulated other comprehensive income/(loss) | (388) | 35 | |
Net current-period other comprehensive income/(loss) | 85 | 35 | |
Accumulated other comprehensive loss at end of period | $ 120 | $ 35 | $ 0 |
Stockholders' Equity Accumula_2
Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Amortization of defined benefit pension and postretirement plan items: | |||
Total before income taxes | $ 115,290 | $ 123,628 | $ 112,697 |
Income tax benefit | (28,078) | (33,832) | (29,231) |
Accumulated other comprehensive loss | (2,738) | (1,379) | 1,303 |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (959) | (229) | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (400) | (2,453) | |
Other Comprehensive Income (Loss), Net of Tax | (1,359) | (2,682) | |
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | |||
Amortization of defined benefit pension and postretirement plan items: | |||
Accumulated other comprehensive loss | (274) | 1,092 | 4,571 |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (1,322) | (934) | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (44) | (2,545) | (4,813) |
Other Comprehensive Income (Loss), Net of Tax | (1,366) | (3,479) | |
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges | |||
Amortization of defined benefit pension and postretirement plan items: | |||
Accumulated other comprehensive loss | 120 | 35 | 0 |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | 473 | 0 | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | (388) | 35 | |
Other Comprehensive Income (Loss), Net of Tax | 85 | 35 | |
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member] | |||
Amortization of defined benefit pension and postretirement plan items: | |||
Accumulated other comprehensive loss | (2,584) | (2,506) | $ (3,268) |
Other Comprehensive Income (Loss), before Reclassifications, before Tax | (110) | 705 | |
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax | 32 | 57 | |
Other Comprehensive Income (Loss), Net of Tax | $ (78) | $ 762 |
Employee Benefit Plans - Additi
Employee Benefit Plans - Additional Information (Detail) $ in Thousands | 12 Months Ended | ||||
Dec. 31, 2023 USD ($) shares | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | Dec. 31, 2018 | ||
Defined Benefit Plan Disclosure [Line Items] | |||||
Total unrecognized cost | $ 12,800 | ||||
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 200 | ||||
Required period of service for eligibility | 3 months | ||||
Percentage of eligible participants contribution to the plan | 100% | ||||
Employer matching contribution vested, percentage | 100% | ||||
Deferred Compensation Arrangement with Individual, Requisite Service Period | 2 years | ||||
Defined Benefit Plan, Benefit Obligation | 2 | ||||
Employee contribution age | 55 years | ||||
Deferral rate | 80% | ||||
Deferred Compensation Employer Matching Contribution Rate | 6% | ||||
Number Of Years to Collect Benefits | 20 years | ||||
Deferral rate increase, minimum | 1% | ||||
Employer contributions to pension plan | $ 6,600 | $ 6,200 | $ 5,900 | ||
Shares reserved to fund future contributions | shares | 798,586 | ||||
Investments, Fair Value Disclosure | $ 12,282 | 10,576 | |||
Deferred compensation obligation | $ 9,050 | 7,060 | |||
Pension Settlement Expense | $ 2,000 | ||||
Minimum | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Maximum percentage of eligible compensation | 3% | ||||
Maximum | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Maximum percentage of eligible compensation | 6% | 10% | |||
Number Of Years to Collect Benefits | 15 years | ||||
FPU Pension Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Total unrecognized cost | $ 10,800 | ||||
Expected contribution | [1] | 3,528 | |||
Chesapeake SERP | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Expected contribution | [2] | $ 151 | |||
Medical | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Health care inflation rate | 5% | ||||
Chesapeake Postretirement Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Total unrecognized cost | $ 1,200 | ||||
Unfunded accumulated benefit obligation | $ (1,100) | (600) | |||
Health care inflation rate | 6% | ||||
Expected contribution | [2] | $ 42 | |||
FPU Medical Plan | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Unfunded accumulated benefit obligation | $ (400) | (700) | |||
Health care inflation rate | 5% | ||||
Expected contribution | [2] | $ 35 | |||
FPU Medical Plan and Chesapeake OPRB [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Defined Benefit Plan, Number of Plans | 2 | ||||
Rabbi Trust Associated With Deferred Compensation Plan [Member] | |||||
Defined Benefit Plan Disclosure [Line Items] | |||||
Deferred compensation obligation | $ 12,300 | 10,600 | |||
Deferred Compensation Equity | $ 9,100 | $ 7,100 | |||
[1]The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.[2]Benefit payments are expected to be paid out of our general funds. |
Employee Benefit Plans - Schedu
Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Change in benefit obligation: | |||
Interest cost | $ 81 | $ 50 | $ 48 |
FPU Pension Plan | |||
Change in benefit obligation: | |||
Benefit obligation - beginning of year | 49,941 | 67,030 | |
Interest cost | 2,495 | 1,781 | 1,714 |
Actuarial loss | 454 | (15,713) | |
Benefits paid | (3,233) | (3,157) | |
Benefit obligation - end of year | 49,657 | 49,941 | 67,030 |
Change in plan assets: | |||
Balance, beginning of year | 46,203 | 58,712 | |
Actual return on plan assets | 6,462 | (9,552) | |
Employer contributions | 0 | 200 | |
Benefits paid | (3,233) | (3,157) | |
Balance, end of year | 49,432 | 46,203 | $ 58,712 |
Reconciliation: | |||
Accrued pension cost | $ (225) | $ (3,738) | |
Assumptions: | |||
Discount rate | 5% | 5.25% | |
Expected return on plan assets | 6% | 6% | 6% |
Chesapeake SERP | |||
Change in benefit obligation: | |||
Benefit obligation - beginning of year | $ 1,659 | $ 2,096 | |
Interest cost | 81 | 50 | |
Actuarial loss | 48 | (335) | |
Benefits paid | (152) | (152) | |
Benefit obligation - end of year | 1,636 | 1,659 | $ 2,096 |
Change in plan assets: | |||
Employer contributions | 152 | 152 | |
Benefits paid | (152) | (152) | |
Reconciliation: | |||
Accrued pension cost | $ (1,636) | $ (1,659) | |
Assumptions: | |||
Discount rate | 4.88% | 5% | |
Chesapeake Postretirement Plan | |||
Reconciliation: | |||
Funded status | $ (1,100) | $ (600) | |
FPU Medical Plan | |||
Reconciliation: | |||
Funded status | $ (400) | $ (700) |
Employee Benefit Plans - Sche_2
Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | $ 81 | $ 50 | $ 48 |
Accumulated other comprehensive loss pre-tax | (3,200) | ||
Total unrecognized cost | (12,800) | ||
FPU Pension Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | 2,495 | 1,781 | 1,714 |
Post-merger regulatory asset | (8,700) | ||
Total unrecognized cost | (10,800) | ||
Defined Benefit Plan, Expected Return (Loss) on Plan Assets | 2,670 | 3,430 | 3,306 |
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year | (407) | (466) | (612) |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) | $ 232 | $ (1,183) | $ (980) |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5.25% | 2.75% | 2.50% |
Expected return on plan assets | 6% | 6% | 6% |
Chesapeake SERP | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Interest cost | $ 81 | $ 50 | |
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year | (8) | (28) | $ (28) |
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) | $ 89 | $ 78 | $ 76 |
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate | 5% | 2.50% | 2.25% |
Chesapeake Postretirement Plan | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Total unrecognized cost | $ (1,200) |
Employee Benefit Plans - Sche_3
Employee Benefit Plans - Schedule of Assets by Investment Type (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Fair Value, Inputs, Level 1, 2 and 3 | ||||
Asset Category | ||||
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments | [1] | $ 49,432 | $ 41,257 | |
FPU Pension Plan | ||||
Asset Category | ||||
Percentage of assets by investment type | 100% | 100% | 100% | |
FPU Pension Plan | Investments in equity securities | ||||
Asset Category | ||||
Percentage of assets by investment type | 50% | 53% | 52% | |
FPU Pension Plan | Debt securities | ||||
Asset Category | ||||
Percentage of assets by investment type | 49% | 38% | 38% | |
FPU Pension Plan | Other | ||||
Asset Category | ||||
Percentage of assets by investment type | 1% | 9% | 10% | |
[1] (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3. |
Employee Benefit Plans - Sche_4
Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail) | Dec. 31, 2023 |
Minimum | Domestic Equities | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 33% |
Minimum | Foreign Equities | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 3% |
Minimum | Fixed Income | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 38% |
Minimum | Cash | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 0% |
Maximum | Domestic Equities | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 57% |
Maximum | Foreign Equities | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 7% |
Maximum | Fixed Income | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 58% |
Maximum | Cash | |
Debt and Equity Securities, FV-NI [Line Items] | |
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage | 5% |
Employee Benefit Plans - Summar
Employee Benefit Plans - Summary of Pension Plan Assets (Detail) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | |
Debt and Equity Securities, FV-NI [Line Items] | |||
Investments measured at net asset value | [1] | $ 0 | $ 4,946 |
Investments in equity securities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | 24,648 | 19,706 | |
Investments in equity securities | Us Large Cap Equity Securities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [2] | 15,360 | 3,413 |
Investments in equity securities | Us Mid Cap Equity Securities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [2] | 4,271 | 1,425 |
Investments in equity securities | United States Equity Small Cap | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [2] | 2,518 | 692 |
Investments in equity securities | International All Cap Equity | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [3] | 2,499 | 9,352 |
Investments in equity securities | Alternative Strategies | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [4] | 0 | 4,824 |
Debt securities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | 24,228 | 17,612 | |
Debt securities | Fixed Income | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [5] | 24,228 | 15,343 |
Debt securities | High Yield Asset Backed Securities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [5] | 0 | 2,269 |
Other | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | 556 | 3,939 | |
Other | Commodities | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [6] | 0 | 1,832 |
Other | Real Estate | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [7] | 0 | 1,709 |
Other | Guaranteed deposit | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | [8] | 556 | 398 |
Fair Value, Inputs, Level 1, 2 and 3 | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets, excluding investments measured at net asset value | [9] | 49,432 | 41,257 |
Fair Value Measured at Net Asset Value Per Share | |||
Debt and Equity Securities, FV-NI [Line Items] | |||
Total Pension Plan Assets | $ 49,432 | $ 46,203 | |
[1]Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.[2] Includes funds that invest primarily in United States common stocks. Includes investment in a group annuity product issued by an insurance company. (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3. |
Employee Benefit Plans - Summ_2
Employee Benefit Plans - Summary of Changes in Fair Value of Level 3 Investments (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | ||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Defined Benefit Plan, Alternative Investments, Fair Value of Plan Assets | [1] | $ 0 | $ 4,946 |
Fair Value, Inputs, Level 1, 2 and 3 | |||
Defined Benefit Plan Disclosure [Line Items] | |||
Defined Benefit Plan, Fair Value of Plan Assets, Excluding Net Asset Value Investments | [2] | 49,432 | 41,257 |
Fair Value Measured at Net Asset Value Per Share | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | 46,203 | ||
Balance, end of year | 49,432 | 46,203 | |
Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | 19,706 | ||
Balance, end of year | 24,648 | 19,706 | |
Debt securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | 17,612 | ||
Balance, end of year | 24,228 | 17,612 | |
Other Investments [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | 3,939 | ||
Balance, end of year | 556 | 3,939 | |
Us Large Cap Equity Securities | Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [3] | 3,413 | |
Balance, end of year | [3] | 15,360 | 3,413 |
Us Mid Cap Equity Securities | Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [3] | 1,425 | |
Balance, end of year | [3] | 4,271 | 1,425 |
United States Equity Small Cap | Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [3] | 692 | |
Balance, end of year | [3] | 2,518 | 692 |
International All Cap Equity | Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [4] | 9,352 | |
Balance, end of year | [4] | 2,499 | 9,352 |
Alternative Strategies | Investments in equity securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [5] | 4,824 | |
Balance, end of year | [5] | 0 | 4,824 |
Fixed Income Securities [Member] | Debt securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [6] | 15,343 | |
Balance, end of year | [6] | 24,228 | 15,343 |
High Yield Asset Backed Securities | Debt securities | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [6] | 2,269 | |
Balance, end of year | [6] | 0 | 2,269 |
Commodities | Other Investments [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [7] | 1,832 | |
Balance, end of year | [7] | 0 | 1,832 |
Real Estate [Member] | Other Investments [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [8] | 1,709 | |
Balance, end of year | [8] | 0 | 1,709 |
Guaranteed deposit | Other Investments [Member] | |||
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward] | |||
Balance, beginning of year | [9] | 398 | |
Balance, end of year | [9] | $ 556 | $ 398 |
[1]Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy. These amounts are presented to reconcile to total pension plan assets.[2] (8) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3. Includes funds that invest primarily in United States common stocks. Includes investment in a group annuity product issued by an insurance company. |
Employee Benefit Plans - Compon
Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Components of net periodic cost: | |||
Interest cost | $ 81 | $ 50 | $ 48 |
Chesapeake Postretirement Plan | |||
Assumptions | |||
Funded status | (1,100) | (600) | |
FPU Medical Plan | |||
Assumptions | |||
Funded status | (400) | (700) | |
Chesapeake SERP | |||
Components of net periodic cost: | |||
Interest cost | 81 | 50 | |
Actuarial (gain) loss | 8 | 28 | 28 |
Net periodic postretirement cost | $ 89 | $ 78 | $ 76 |
Assumptions | |||
Discount rate | 5% | 2.50% | 2.25% |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | $ 48 | $ (335) | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | (152) | (152) | |
Defined Benefit Plan, Plan Assets, Contributions by Employer | 152 | 152 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | (152) | (152) | |
Accrued pension cost | $ (1,636) | $ (1,659) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 4.88% | 5% | |
FPU Pension Plan | |||
Components of net periodic cost: | |||
Interest cost | $ 2,495 | $ 1,781 | $ 1,714 |
Expected return on assets | (2,670) | (3,430) | (3,306) |
Actuarial (gain) loss | 407 | 466 | 612 |
Net periodic postretirement cost | $ 232 | $ (1,183) | $ (980) |
Assumptions | |||
Discount rate | 5.25% | 2.75% | 2.50% |
Expected return on plan assets | 6% | 6% | 6% |
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss) | $ 454 | $ (15,713) | |
Defined Benefit Plan, Benefit Obligation, Benefits Paid | (3,233) | (3,157) | |
Defined Benefit Plan, Plan Assets, Amount | 49,432 | 46,203 | $ 58,712 |
Defined Benefit Plan, Plan Assets, Contributions by Employer | 0 | 200 | |
Defined Benefit Plan, Plan Assets, Benefits Paid | (3,233) | (3,157) | |
Accrued pension cost | $ (225) | $ (3,738) | |
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate | 5% | 5.25% |
Employee Benefit Plans - Sche_5
Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands | Dec. 31, 2023 USD ($) | |
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items] | ||
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year | $ 200 | |
FPU Pension Plan | ||
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items] | ||
2017 | 3,528 | [1] |
2018 | 3,603 | [1] |
2019 | 3,617 | [1] |
2020 | 3,616 | [1] |
2021 | 3,651 | [1] |
Years 2022 through 2026 | 17,951 | [1] |
Chesapeake SERP | ||
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items] | ||
2017 | 151 | [2] |
2018 | 164 | [2] |
2019 | 161 | [2] |
2020 | 158 | [2] |
2021 | 154 | [2] |
Years 2022 through 2026 | 689 | [2] |
Chesapeake Postretirement Plan | ||
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items] | ||
2017 | 42 | [2] |
2018 | 46 | [2] |
2019 | 45 | [2] |
2020 | 48 | [2] |
2021 | 49 | [2] |
Years 2022 through 2026 | 299 | [2] |
FPU Medical Plan | ||
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items] | ||
2017 | 35 | [2] |
2018 | 35 | [2] |
2019 | 34 | [2] |
2020 | 33 | [2] |
2021 | 32 | [2] |
Years 2022 through 2026 | $ 143 | [2] |
[1]The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.[2]Benefit payments are expected to be paid out of our general funds. |
Share-Based Compensation - Addi
Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares reserved for issuance | 798,586 | ||
Number of Shares, Granted | 765 | 652 | |
Number of shares withheld | 19,859 | 21,832 | 14,020 |
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount | $ 6.6 | ||
SICP Awards to Non-employee directors | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Unrecognized compensation expense related to the awards to Non employee directors | $ 0.3 | ||
Weighted average grant-date fair value of awards granted | $ 124.12 | $ 130.36 | |
SICP Awards to Key Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value | $ 91.59 | $ 90.60 | |
Number of Shares, Granted | 80,820 | 69,620 | |
Weighted average grant-date fair value of awards granted | $ 126.06 | $ 117.61 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested | $ 22.5 | $ 24.1 | $ 28.8 |
Stock and Incentive Compensation Plan | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Shares reserved for issuance | 561,115 |
Share-Based Compensation Plan_2
Share-Based Compensation Plans - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | $ 7,622 | $ 6,438 | $ 5,945 |
Less: tax benefit | (1,947) | (1,663) | (1,535) |
Share-Based Compensation amounts included in net income | 5,675 | 4,775 | 4,410 |
SICP Awards to Non-employee directors | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Total compensation expense | 906 | 959 | 782 |
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount | 300 | ||
SICP Awards to Key Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award [Line Items] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested | 22,500 | 24,100 | 28,800 |
Total compensation expense | $ 6,716 | $ 5,479 | $ 5,163 |
Share-Based Compensation Plan_3
Share-Based Compensation Plans - Summary of Stock Activity Non-employee directors (Detail) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | |
Dec. 31, 2023 | Dec. 31, 2022 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | ||
Number of Shares, Granted | 765 | 652 |
SICP Awards to Non-employee directors | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | ||
Weighted Average Grant Date Fair Value, Granted | $ 124.12 | $ 130.36 |
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount | $ 0.3 |
Share-Based Compensation Plan_4
Share-Based Compensation Plans - Summary of Stock Activity under SICP - Key employees (Detail) - USD ($) $ / shares in Units, $ in Millions | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Number of Shares, Granted | 765 | 652 | |
SICP Awards to Key Employees | |||
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward] | |||
Number of Shares, Outstanding Beginning Balance | 204,149 | 197,398 | |
Number of Shares, Granted | 80,820 | 69,620 | |
Number of Shares, Vested | (68,302) | (60,191) | |
Number of Shares, Outstanding Ending Balance | 213,124 | 204,149 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance | $ 103.17 | $ 94.15 | |
Weighted Average Grant Date Fair Value, Granted | 126.06 | 117.61 | |
Weighted Average Grant Date Fair Value, Vested | 91.59 | 90.60 | |
Weighted Average Grant Date Fair Value, Outstanding Ending Balance | $ 117.74 | $ 103.17 | |
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period | 1,490 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value | $ 113.44 | ||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested | $ 22.5 | $ 24.1 | $ 28.8 |
Accelerated Vested Shares [Member] | |||
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Abstract] | |||
Weighted Average Grant Date Fair Value, Vested | $ 94.64 | $ 91.42 | |
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number | 2,053 | 2,678 |
Share-Based Compensation Plan_5
Share-Based Compensation Plans Shares Withheld and Tax Benefits Associated With Share-Based Payments (Details) - USD ($) $ in Thousands | 12 Months Ended | ||
Dec. 31, 2023 | Dec. 31, 2022 | Dec. 31, 2021 | |
Share-Based Payment Arrangement [Abstract] | |||
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation | 19,859 | 21,832 | 14,020 |
Payment, Tax Withholding, Share-based Payment Arrangement | $ 2,455 | $ 2,838 | $ 1,478 |
Rates and Other Regulatory Ac_3
Rates and Other Regulatory Activities - Additional Information (Detail) | 12 Months Ended | |||
Dec. 31, 2023 USD ($) Dekatherm mi | Dec. 31, 2022 USD ($) | Dec. 31, 2021 USD ($) | ||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | $ 115,902,000 | $ 149,653,000 | ||
Revenues | 670,604,000 | 680,704,000 | $ 569,968,000 | |
Interim Rates | 7,700,000 | |||
Annual Rate Case Recovery | 17,200,000 | |||
COVID-19 Regulatory Asset | 200,000 | 1,200,000 | ||
RSAM | 25,000,000 | |||
Regulatory Liabilities | 208,998,000 | 148,020,000 | ||
Cost Recovery Storm Protection Plan | 13,600,000 | |||
Gas Utility Access and Replacement Directive Related Capital Expenditures | 205,000,000 | |||
Storm reserve | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [1] | 1,900,000 | 2,845,000 | |
Underrecovered purchased fuel costs | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [2] | 13,696,000 | $ 43,583,000 | |
Maryland Natural Gas Distribution Businesses [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Permanent Rates | 6,900,000 | |||
Florida Public Utilities Company [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
COVID-19 Settlement Amount | 2,100,000 | |||
West Palm Beach Florida | Minimum [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Environmental Exit Costs, Reasonably Possible Additional Loss | 1,900,000 | |||
West Palm Beach Florida | Maximum [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Environmental Exit Costs, Reasonably Possible Additional Loss | 3,200,000 | |||
Florida Natural Gas Distribution [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Permanent Rates | 24,100,000 | |||
Florida City Gas | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Total Base Revenue | 23,300,000 | |||
Rate Increase | 14,100,000 | |||
Base Rate Increase Base - SAFE investments transfer to base rates | 5,300,000 | |||
Base Rate Increase - liquefied natural gas facility | 3,800,000 | |||
Florida City Gas | Storm reserve | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | $ 800,000 | |||
Beachside Expansion | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 10,176 | |||
Number of Mainline Pipeline Miles | mi | 11.3 | |||
Twin Lakes Expansion | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 2,400 | |||
Ocean City Maryland Reinforcement | Maryland Natural Gas [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Number of Mainline Pipeline Miles | mi | 5.4 | |||
Lake Wales Pipeline Acquisition | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 9,000 | |||
Newberry Expansion | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 8,000 | |||
East Coast Reinforcement Projects: Boynton Beach | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 15,000 | |||
East Coast Reinforcement Projects: New Smyrna Beach | Peninsula Pipeline Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Additional Firm Natural Gas Transportation Deliverability | Dekatherm | 3,400 | |||
Elkton Gas [Member] | Regulated Energy [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Number of customers acquired through acquisition | 7,000 | |||
[1]We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.[2]We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023. |
Rates and Other Regulatory Ac_4
Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 | ||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | $ 115,902 | $ 149,653 | ||
Regulatory Liabilities | 208,998 | 148,020 | ||
Underrecovered Gas & Fuel Costs | 21,200 | |||
Self Insured Liabilities [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [1] | 521 | 339 | |
Overrecovered Gas And Fuel Costs [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [2] | 12,340 | 3,827 | |
Storm Reserve [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [1] | 1,900 | 2,845 | |
Accrued asset removal cost | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [3] | 86,534 | 50,261 | |
Deferred Income Tax Due to Rate Change [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [4] | 105,055 | 87,690 | |
Other Regulatory Liability [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | 1,611 | 1,851 | ||
Storm Cost Recovery, Interest | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | [5] | 536 | 1,207 | |
Over-recovered GRIP revenue | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Liabilities | 501 | 0 | ||
Underrecovered Gas And Fuel Costs [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [2] | 13,696 | 43,583 | |
Deferred Post Retirement Benefits [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [6] | 10,802 | 13,927 | |
Deferred Conversion And Development Costs [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [2] | 21,466 | 23,653 | |
Acquisition Adjustment [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [7] | 31,857 | 25,609 | |
Other Regulatory Asset [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | 15,573 | 12,256 | ||
COVID-19 Deferred Costs | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | 190 | [8] | 1,233 | |
Deferred Storm Costs | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [5] | 19,370 | 27,687 | |
Under-recovered GRIP Revenues | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | [9] | 1,777 | 1,705 | |
Deferred rate case expenses - current | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Regulatory Assets | 1,171 | $ 0 | ||
Florida Public Utilities Company [Member] | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Business Acquisition Premium Paid | 34,200 | |||
Indiantown Gas Company | ||||
Rates and Other Regulatory Activities [Line Items] | ||||
Business Acquisition Premium Paid | $ 700 | |||
[1]We have storm reserves in our Florida regulated energy operations and self-insurance for our regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.[2]We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets. (2) At December 31, 2022, includes $21.2 million being recovered over a three year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023. , Summary of Significant Accounting Policies, for additional information on our asset removal cost policies. We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes , for additional information. , Compensation - Retirement Benefits , related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16 , Employee Benefit Plans, for additional information. We deferred as regulatory assets the net incremental expense impact associated with the net expense impact of COVID-19 as authorized by the stated PSCs. |
Rates and Other Regulatory Ac_5
Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands | Dec. 31, 2023 | Dec. 31, 2022 |
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | $ 208,998 | $ 148,020 |
Eastern Shore Gas Company [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 34,190 | 34,190 |
Delaware natural gas division [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 12,038 | 12,230 |
Maryland Division [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 3,585 | 3,703 |
Sandpiper [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 3,487 | 3,597 |
Central Florida Gas Division [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 26,757 | 27,179 |
Elkton Gas [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | 1,027 | 1,059 |
FPU electric division [Member] | ||
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items] | ||
Regulatory Liabilities | $ 4,760 | $ 4,993 |
Environmental Commitments and_3
Environmental Commitments and Contingencies - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2023 USD ($) site | Dec. 31, 2022 USD ($) | |
Environmental Commitments And Contingencies [Line Items] | ||
Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site | 7 | |
Environmental liabilities | $ 2,607,000 | $ 3,272,000 |
Environmental Commitments and Contingencies | E NVIRONMENTAL C OMMITMENTS AND C ONTINGENCIES 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 December 31, 2023 and 2022, we had approximately $3.6 million and $4.3 million, respectively, in environmental liabilities, related to the former MGP sites. As of December 31, 2023 and 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs from customers. Specific to FPU's four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval for and has recovered, through a combination of insurance and customer rates, $14.0 million of its environmental costs related to its MGP sites as of December 31, 2023. 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 MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The Environmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a site. The remaining remediation expenses for the Sanford MGP site are immaterial. The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and construction of active remedial systems are expected to be completed in 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system on the West Parcel, five to ten years of operation, maintenance and monitoring, and final site work for closeout of the property, is estimated to be between $1.9 million and $3.2 million. | |
Manufactured Gas Plant | ||
Environmental Commitments And Contingencies [Line Items] | ||
Regulatory assets for future recovery of environmental costs | $ 500,000 | 800,000 |
West Palm Beach Florida | Maximum | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental Exit Costs, Reasonably Possible Additional Loss | 3,200,000 | |
West Palm Beach Florida | Minimum | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental Exit Costs, Reasonably Possible Additional Loss | 1,900,000 | |
Seaford | Maximum | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental Exit Costs, Reasonably Possible Additional Loss | 900,000 | |
Seaford | Minimum | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental Exit Costs, Reasonably Possible Additional Loss | 300,000 | |
Florida Natural Gas Distribution [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Permanent Rates | 24,100,000 | |
Maryland Natural Gas Distribution Businesses [Member] | ||
Environmental Commitments And Contingencies [Line Items] | ||
Permanent Rates | 6,900,000 | |
Florida City Gas | ||
Environmental Commitments And Contingencies [Line Items] | ||
Rate Increase | 14,100,000 | |
FPU | ||
Environmental Commitments And Contingencies [Line Items] | ||
Environmental liabilities | 3,600,000 | $ 4,300,000 |
Approval of recovery of environmental costs | $ 14,000,000 |
Other Commitments and Conting_3
Other Commitments and Contingencies - Additional Information (Detail) | 12 Months Ended | |
Dec. 31, 2023 USD ($) | Dec. 31, 2022 USD ($) | |
Subsequent Event [Line Items] | ||
Intercompany Agreements, Description | three years | |
Debt Service Coverage Ratio | 1.25 | |
Time to cure ratio | 5 days | |
Ratio based on average number of prior quarters | 6 | |
Funds from operations interest coverage ratio minimum times | 2 | |
Total debt to capital maximum | 65 | |
Number Of Years to Collect Benefits | 20 years | |
Total purchase obligations for 2018 | $ 86,040,000 | |
Total purchase obligations for 2019 - 2020 | 105,082,000 | |
Total purchase obligations for 2021 - 2022 | 83,851,000 | |
Total purchase obligations thereafter | 141,287,000 | |
Aggregate guaranteed amount | 35,000,000 | |
Guarantor Obligations, Current Carrying Value | 24,300,000 | |
Amount of letter of credit to our current primary insurance company | 7,000,000 | |
Loss Contingencies [Line Items] | ||
Environmental liabilities | $ 2,607,000 | $ 3,272,000 |
Maximum [Member] | ||
Subsequent Event [Line Items] | ||
Number Of Years to Collect Benefits | 15 years | |
Maximum [Member] | Seaford | ||
Loss Contingencies [Line Items] | ||
Environmental Exit Costs, Reasonably Possible Additional Loss | $ 900,000 | |
Specific Purpose | ||
Subsequent Event [Line Items] | ||
Guarantor Obligations, Current Carrying Value | 4,000,000 | |
Florida Public Utilities Company [Member] | ||
Loss Contingencies [Line Items] | ||
Environmental liabilities | $ 3,600,000 | $ 4,300,000 |
Other Commitments and Conting_4
Other Commitments and Contingencies Purchase Obligations (Details) $ in Thousands | Dec. 31, 2023 USD ($) |
Long-term Purchase Commitment [Line Items] | |
Purchase Obligation, Due in Next Twelve Months | $ 86,040 |
Purchase Obligation, Due in Second and Third Year | 105,082 |
Purchase Obligation, Due in Fourth and Fifth Year | 83,851 |
Purchase Obligation, Due after Fifth Year | 141,287 |
Purchase Obligation | $ 416,260 |
Schedule II - Valuation and Qua
Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands | 12 Months Ended | |
Dec. 31, 2022 | Dec. 31, 2021 | |
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward] | ||
Balance at Beginning of Year | $ 3,141 | $ 4,785 |
Additions, Charged to Income | 1,550 | 134 |
Additions, Other Accounts | 172 | (125) |
Deductions | (1,986) | (1,653) |
Balance at End of Year | $ 2,877 | $ 3,141 |