Chesapeake Utilities (CPK) 10-K 26 Feb 25 2024 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2024	Feb. 24, 2025	Jun. 30, 2024
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2024
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			$ 2.3
Entity Common Stock, Shares Outstanding		22,982,417
Documents Incorporated by Reference	Portions of the Chesapeake Utilities Corporation Proxy Statement for the 2025 Annual Meeting of Stockholders 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	2024
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, 2024
Auditor Information [Abstract]
Auditor Name	Baker Tilly US, LLP
Auditor Location	Philadelphia, Pennsylvania
Auditor Firm ID	23

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) shares in Thousands, $ in Thousands		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Revenues
Regulated Energy		$ 583,400	$ 473,600	$ 429,400
Unregulated Energy		228,400	223,100	280,800
Other		(24,600)	(26,100)	(29,500)
Total operating revenues		787,200	670,600	680,700
Operating Expenses
Natural gas and electricity costs		144,200	140,000	127,200
Propane and natural gas costs		75,600	76,500	133,300
Operations		210,100	178,400	164,500
Maintenance		22,500	20,400	18,200
Depreciation and amortization		65,700	65,500	69,000
Other taxes		36,900	28,600	25,600
Total operating expenses		559,000	519,800	537,800
Operating Income		228,200	150,800	142,900
Other income, net		2,000	1,400	5,100
Interest charges		68,400	36,900	24,400
Income Before Income Taxes		161,800	115,300	123,600
Income taxes		43,200	28,100	33,800
Net Income (Loss) Attributable to Parent		$ 118,600	$ 87,200	$ 89,800
Weighted Average Common Shares Outstanding:
Basic (in shares)	[1]	22,469	18,371	17,722
Diluted (in shares)	[1]	22,531	18,435	17,804
Earnings Per Share of Common Stock:
Income (Loss) from Continuing Operations, Per Basic Share		$ 5.28	$ 4.75	$ 5.07
Basic (in usd per share)		5.28	4.75	5.07
Earnings Per Share, Diluted [Abstract]
Income (Loss) from Continuing Operations, Per Diluted Share		5.26	4.73	5.04
Diluted (in usd per share)		$ 5.26	$ 4.73	$ 5.04
Transaction-related expenses		$ 4,000	$ 10,400	$ 0
[1]) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Net Income	$ 118.6	$ 87.2	$ 89.8
Employee Benefits:
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	(0.5)	0.1	(0.7)
Cash Flow Hedges, net of tax:
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent		0.5	0
Total Other Comprehensive Income (Loss)	1.1	(1.4)	(2.7)
Comprehensive Income	119.7	85.8	87.1
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(1.3)	(0.4)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1.3	0.4
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, after Tax	(0.5)	0.1	(0.7)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	2.4	(1)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), after Reclassification and Tax, Parent		0.5	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	(0.6)	(0.4)	0
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.6	0.4	0
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Cash Flow Hedges, net of tax:
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax		(1.4)	(0.9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.7)	0	(2.5)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.7	0	2.5
Other Comprehensive Income (Loss), before Reclassifications, before Tax	1.4	(1.4)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Net of Tax		(1.4)	$ (0.9)
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	(0.6)	(0.4)
Accumulated Other Comprehensive Income (Loss) [Line Items]
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0.6	0.4
Other Comprehensive Income (Loss), before Reclassifications, before Tax	$ 0.5	$ 0.5

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	$ 0	$ 0	$ 0
Tax expense recognized on the net gain (loss)	0.1	0	0.2
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	0.2	0.2	0
Accumulated Other Comprehensive Income (Loss) [Line Items]
Tax expense recognized on the amortization of prior service cost	0	0	0
Other Comprehensive Income (Loss), Defined Benefit Plan, Gain (Loss), Reclassification Adjustment from AOCI, Tax	(0.1)	0	(0.2)
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Interest Rate Swaps During Period, Tax	0.2	0.2	0
Unrealized Gain (Loss) On Cash Flow Hedging Instruments, Tax	0.6	(0.5)	(0.4)
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	(0.3)	0	(1)
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	$ (0.2)	$ (0.1)	$ 0

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Activities
Net Income	$ 118.6	$ 87.2	$ 89.8
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	65.7	65.5	69
Depreciation and accretion included in operations expenses	15.8	11.9	11
Deferred income taxes, net	36.4	3.4	23.7
Realized (loss) on sale of assets/commodity contracts	(4.4)	(0.8)	(7.5)
Unrealized loss (gain) on investments/commodity contracts	(1.8)	(1.9)	1.8
Employee benefits and compensation	0	0.3	(1.1)
Share-based compensation	8.4	7.6	6.4
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(10.3)	2.3	(11.2)
Propane inventory, storage gas and other inventory	3.3	0.3	(7.8)
Regulatory assets/liabilities, net	0.2	20.1	(38.6)
Prepaid expenses and other current assets	0.4	18.7	9.1
Accounts payable and other accrued liabilities	0.4	(16.8)	2.7
Income taxes receivable	(2.9)	(1.3)	14.9
Customer deposits and refunds	(0.7)	3.9	0.7
Accrued compensation	7	1.5	(1.2)
Other assets and liabilities, net	5.7	(2.3)	(2.8)
Net cash provided by operating activities	239.4	203.5	158.9
Investing Activities
Property, plant and equipment expenditures	(355.3)	(188.6)	(128.3)
Proceeds from sale of assets	5.2	2.9	3.9
Acquisitions, net of cash acquired	0.6	(925)	(11.8)
Environmental expenditures	(0.4)	(0.7)	(0.3)
Net cash used in investing activities	(349.9)	(1,111.4)	(136.5)
Financing Activities
Common stock dividends	(54.2)	(40)	(35.2)
Payment, Tax Withholding, Share-based Payment Arrangement	(1.5)	(2.5)	(2.8)
Change in cash overdrafts due to outstanding checks	1.5	(0.3)	1
Net borrowings (repayments) under line of credit agreements	14.1	(22.5)	(20.6)
Proceeds from issuance of long-term debt	99.5	627	49.9
Repayment of long-term debt and finance lease obligation	(18.5)	(21.5)	(18)
Net cash provided by (used in) financing activities	113.5	906.6	(21.2)
Net (Decrease) Increase in Cash and Cash Equivalents	3	(1.3)	1.2
Other Operating Activities, Cash Flow Statement	(0.2)	0.2	0
Cash and Cash Equivalents — Beginning of Period	4.9	6.2	5
Cash and Cash Equivalents — End of Period	7.9	4.9	6.2
Increase (Decrease) in Interest Payable, Net	(2.2)	3.7	0
Proceeds from Issuance or Sale of Equity	72.6	366.4	4.5
Net Cash Provided by (Used in) Financing Activities	113.5	906.6	(21.2)
Net Cash Provided by (Used in) Investing Activities	(349.9)	(1,111.4)	(136.5)
Net Cash Provided by (Used in) Operating Activities	239.4	203.5	158.9
Cash and Cash Equivalents, Period Increase (Decrease)	3	(1.3)	1.2
Cash and cash equivalents	$ 7.9	$ 4.9	$ 6.2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Property, Plant and Equipment
Regulated Energy	$ 2,661.8	$ 2,418.5
Unregulated Energy	463.7	410.8
Other businesses	29.9	30.3
Total property, plant and equipment	3,155.4	2,859.6
Accumulated depreciation	567.6	516.4
Construction Work in Progress	148.1	113.2
Net property, plant and equipment	2,735.9	2,456.4
Current Assets
Cash and cash equivalents	7.9	4.9
Accounts Receivable, before Allowance for Credit Loss, Current	80	74.5
Allowance for uncollectible accounts	3.3	2.7
Trade and other receivables, net	76.7	71.8
Accrued Revenue	37.8	32.6
Propane inventory, at average cost	8.9	9.3
Other inventory, at average cost	18	19.9
Regulatory assets	23.9	19.5
Storage gas prepayments	3.8	4.7
Income taxes receivable	6.8	3.8
Prepaid expenses	17.3	15.4
Derivative assets, at fair value	0.6	1
Other current assets	2.6	2.8
Total current assets	204.3	185.7
Deferred Charges and Other Assets
Goodwill	507.7	508.2
Other intangible assets, net	15	16.9
Investments, Fair Value Disclosure	14.4	12.3
Operating Lease, Right-of-Use Asset	10.5	12.4
Regulatory assets	77.4	96.4
Receivables and other deferred charges	11.7	16.4
Total deferred charges and other assets	636.8	662.6
Total Assets	3,577	3,304.7
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)	11.1	10.8
Additional paid-in capital	830.5	749.4
Retained earnings	550.3	488.7
Accumulated other comprehensive loss	(1.7)	(2.8)
Deferred compensation obligation	9.8	9.1
Treasury Stock, Value	(9.8)	(9.1)
Total stockholders’ equity	1,390.2	1,246.1
Long-term debt, net of current maturities	1,261.7	1,187.1
Total capitalization	2,651.9	2,433.2
Current Liabilities
Current portion of long-term debt	25.5	18.5
Short-term borrowing	196.5	179.9
Accounts payable	78.3	77.5
Customer deposits and refunds	45.7	46.4
Accrued interest	4.8	7
Dividends payable	14.7	13.1
Accrued compensation	23.9	16.5
Regulatory liabilities	16.1	13.7
Derivative liabilities, at fair value	0	0.4
Other accrued liabilities	13.9	13.4
Total current liabilities	419.4	386.4
Deferred Credits and Other Liabilities
Deferred income taxes	296.1	259.1
Regulatory liabilities	184	195.3
Environmental liabilities	2.2	2.6
Other pension and benefit costs	13.2	15.3
Operating Lease, Liability, Noncurrent	8.7	10.6
Deferred investment tax credits and other liabilities	1.4	1.3
Total deferred credits and other liabilities	505.7	485.1
Commitments and Contingencies
Total Capitalization and Liabilities	3,577	3,304.7
Regulated Energy	2,661.8	2,418.5
Unregulated Energy	463.7	410.8
Other businesses	29.9	30.3
Total property, plant and equipment	3,155.4	2,859.6
Accumulated depreciation	567.6	516.4
Construction Work in Progress	148.1	113.2
Net property, plant and equipment	2,735.9	2,456.4
Cash and cash equivalents	7.9	4.9
Accounts Receivable, before Allowance for Credit Loss, Current	80	74.5
Allowance for uncollectible accounts	3.3	2.7
Trade and other receivables, net	76.7	71.8
Accrued Revenue	37.8	32.6
Propane inventory, at average cost	8.9	9.3
Other inventory, at average cost	18	19.9
Regulatory assets	23.9	19.5
Storage gas prepayments	3.8	4.7
Income taxes receivable	6.8	3.8
Prepaid expenses	17.3	15.4
Derivative assets, at fair value	0.6	1
Other current assets	2.6	2.8
Disposal Group, Including Discontinued Operation, Assets, Current	204.3	185.7
Goodwill	507.7	508.2
Other intangible assets, net	15	16.9
Investments, Fair Value Disclosure	14.4	12.3
Energy Marketing Contracts Assets, Noncurrent	0.1	0
Operating Lease, Right-of-Use Asset	10.5	12.4
Regulatory assets	77.4	96.4
Receivables and other deferred charges	11.7	16.4
Deferred Charges And Other Assets	636.8	662.6
Total identifiable assets	3,577	3,304.7
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)	11.1	10.8
Additional paid-in capital	830.5	749.4
Retained earnings	550.3	488.7
Accumulated other comprehensive loss	(1.7)	(2.8)
Deferred compensation obligation	9.8	9.1
Treasury Stock, Value	9.8	9.1
Stockholders' Equity Attributable to Parent	1,390.2	1,246.1
Long-term debt, net of current maturities	1,261.7	1,187.1
Total capitalization	2,651.9	2,433.2
Current portion of long-term debt	25.5	18.5
Short-term borrowing	196.5	179.9
Accounts payable	78.3	77.5
Customer deposits and refunds	45.7	46.4
Accrued interest	4.8	7
Dividends payable	14.7	13.1
Accrued compensation	23.9	16.5
Regulatory liabilities	16.1	13.7
Derivative liabilities, at fair value	0	0.4
Other accrued liabilities	13.9	13.4
Liabilities, Current	419.4	386.4
Deferred income taxes	296.1	259.1
Regulatory liabilities	184	195.3
Environmental liabilities	2.2	2.6
Other pension and benefit costs	13.2	15.3
Energy Marketing Contract Liabilities, Noncurrent	0.1	0.9
Operating Lease, Liability, Noncurrent	8.7	10.6
Deferred investment tax credits and other liabilities	1.4	1.3
Deferred Credits and Other Liabilities	505.7	485.1
Liabilities and Equity	3,577	3,304.7
Allowance for uncollectible accounts	3.3	2.7
Operating Lease, Liability, Noncurrent	$ 8.7	$ 10.6

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 3.3	$ 2.7
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	$ 10	$ 10

Consolidated Statements of Stoc

Consolidated Statements of Stockholders' Equity - USD ($) $ in Millions		Total		Florida City Gas	Common Stock [Member]		Common Stock [Member] Florida City Gas	[1]	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]				17,655,000
Stockholders' Equity Attributable to Parent		$ 774.2	[2]		$ 8.6	[1]			$ 371.2		$ 393.1	$ 1.3	$ 7.2	$ (7.2)
Net Income		89.8									89.8
Other comprehensive loss		(2.7)										(2.7)
Dividends		(37.4)									(37.4)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan	[1],[3]				$ 0
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan	[1],[2],[3]				39,000
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan	[3]	5.3							5.3
Share-based compensation, shares	[1],[2],[4],[5]				47,000
Share-based compensation	[4],[5]	3.5			$ 0	[1]			3.5					0
Treasury stock activities	[2]	$ 0											(0.1)	0.1
Common Stock, Dividends, Per Share, Declared		$ 2.0850
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		22,000
Shares, Issued	[1],[2]				17,741,000
Stockholders' Equity Attributable to Parent		$ 832.7	[2]		$ 8.6	[1]			380		445.5	(1.4)	7.1	(7.1)
Net Income		87.2									87.2
Stock Issued During Period, Value, Acquisitions				$ 366.5			$ 2.2			$ 364.3
Other comprehensive loss		(1.4)										(1.4)
Dividends		(44)									(44)
Share-based compensation, shares	[1],[2],[4],[5]				55,000
Share-based compensation	[4],[5]	5.1			$ 0	[1]			5.1
Treasury stock activities	[2]	$ 0											2	(2)
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	[1],[2]			4,439,000
Common Stock, Dividends, Per Share, Declared		$ 2.3050
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		20,000
Shares, Issued	[1],[2]				22,235,000
Stockholders' Equity Attributable to Parent		$ 1,246.1			$ 10.8	[1]			749.4		488.7	(2.8)	9.1	(9.1)
Preferred Stock, Shares Authorized		2,000,000
Net Income		$ 118.6									118.6
Other comprehensive loss		1.1										1.1
Dividends		(57)									(57)
Stock Issued, Value, During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan	[3]	74.5			$ 0.3	[1]			74.2
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan	[1],[2],[3]				627,000
Share-based compensation, shares	[1],[2],[4],[5]				37,000
Share-based compensation	[4],[5]	6.9			$ 0	[1]			6.9
Treasury stock activities	[2]	$ 0											0.7	(0.7)
Common Stock, Dividends, Per Share, Declared		$ 2.5100
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation		14,000
Shares, Issued	[1],[2]				22,899,000
Stockholders' Equity Attributable to Parent		$ 1,390.2			$ 11.1	[1]			$ 830.5		$ 550.3	$ (1.7)	$ 9.8	$ (9.8)
Preferred Stock, Shares Authorized		2,000,000
[1] 2.0 million shares of preferred stock at $0.01 par value per share have been authorized. No preferred shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity. Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM, as applicable. Includes amounts for shares issued for directors’ compensation. The shares issued under the SICP are net of shares withheld for employee taxes. For 2024, 2023 and 2022, we withheld 14 thousand, 20 thousand and 22 thousand shares, respectively, for taxes.

Consolidated Statements of St_2

Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Statement of Stockholders' Equity [Abstract]
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 10	$ 10
Shares Held In Trust For Deferred Compensation Plan	114,000	108,000	108,000
Dividends Declared	$ 2.5100	$ 2.3050	$ 2.0850

Summary of Significant Accounti

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2024
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 within 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, 2024 and 2023 is provided in the following table: As of December 31, (in millions) 2024 2023 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida $ 1,679.3 $ 1,486.8 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 819.5 788.2 Electric distribution 163.0 143.5 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 201.6 194.9 Natural gas transmission and supply – Ohio 139.2 134.2 Electricity and steam generation 37.4 37.1 Mobile CNG and pipeline solutions 52.8 40.6 Sustainable energy investments, including renewable natural gas related investments 32.7 4.0 Other 29.9 30.3 Total property, plant and equipment 3,155.4 2,859.6 Less: Accumulated depreciation and amortization (567.6) (516.4) Plus: Construction work in progress 148.1 113.2 Net property, plant and equipment $ 2,735.9 $ 2,456.4 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, 2024 and 2023, the non-refundable contributions totaled $5.9 million and $4.2 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 year ended December 31, 2024, AFUDC was $1.4 million and was reflected as a reduction of interest expense. For the years ended December 31, 2023 and 2022, AFUDC was not material. 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, 2024, 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 $2.8 million and $2.2 million at December 31, 2024 and 2023, 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, 2024, 2023 and 2022, we reported $15.8 million, $11.9 million and $11.0 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, 2024, 2023 and 2022: 2024 2023 2022 Natural gas distribution – Delmarva Peninsula (1) 2.1% 2.5% 2.5% Natural gas distribution – Florida (2) (3) 2.7% 2.2% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.4% Natural gas transmission – Ohio (4) 2.3% 5.0% 5.0% Electric distribution 2.4% 2.4% 2.8% (1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper. (2) Includes the impact of FCG beginning in 2024. (3) 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. (4) 2024 rate excludes the impact of cumulative adjustments related to a change in useful lives of certain assets. Such adjustments were not material to the Company's results of operations for the year ended December 31, 2024. 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, 2024: (in millions) Balance at December 31, 2023 $ 2.7 Additions: Provision for credit losses 2.1 Recoveries 0.4 Deductions: Write offs (1.9) Balance at December 31, 2024 $ 3.3 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, 2024, 2023 or 2022. 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, 2024, 2023 and 2022. 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 when it is more likely than not that such income tax benefits will be realized. Valuation allowances may be recorded if it is determined that some deferred tax assets will not 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. Recently Adopted Accounting Standards 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. We adopted ASU 2023-07 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, did not have an impact on our financial position or results of operations. Recent Accounting Standards Yet to be Adopted FASB Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2025. ASU 2023-09 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations. Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-04, Disaggregation of Income Statement Expenses, which require disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-04 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations. SEC Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed and sought review of the final ruling in multiple courts of appeals. At this time, it is uncertain as to when the review will be completed, the final outcome of the review, and the timing of required disclosure.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2024
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, 2024 2023 2022 (dollars in millions, shares in thousands (except per share data)) Calculation of Basic Earnings Per Share: Net Income $ 118.6 $ 87.2 $ 89.8 Weighted average shares outstanding (1) 22,469 18,371 17,722 Basic Earnings Per Share $ 5.28 $ 4.75 $ 5.07 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted average shares outstanding — Basic (1) 22,469 18,371 17,722 Effect of dilutive securities — Share-based compensation 62 64 82 Adjusted denominator — Diluted (1) 22,531 18,435 17,804 Diluted Earnings Per Share $ 5.26 $ 4.73 $ 5.04 (1) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.

Acquisitions

Acquisitions	12 Months Ended
	Dec. 31, 2024
Business Combinations [Abstract]
Acquisitions	4. A CQUISITIONS Acquisition of Florida City Gas On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement that were settled during the first quarter of 2024, pursuant to the 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 serves approximately 123,000 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 3,982 miles of distribution mains 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 . The excess of the purchase price for FCG over the fair value of the assets acquired and liabilities assumed was 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 is deductible for income tax purposes. The components of the purchase price allocation are as follows: (in millions) Assets acquired: Acquisition Date Fair Value Cash $ 2.3 Accounts receivable, net 14.1 Regulatory assets - current 3.0 Other current assets 2.0 Property, plant and equipment 454.4 Goodwill 460.9 Regulatory assets - non-current 3.4 Other deferred charges and other assets 18.3 Total assets acquired 958.4 Liabilities assumed: Current liabilities (20.9) Regulatory liabilities (14.1) Other deferred credits and other liabilities (0.6) Total liabilities assumed (35.6) Net purchase price $ 922.8 Direct transaction and transition-related costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction and transition-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges included $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, were deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate, as of December 31, 2023. For the year ended December 31, 2024, the Company’s consolidated results include $140.3 million of operating revenue and net income of $13.5 million attributable to FCG which includes $4.0 million of transaction and transition-related expenses. 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 and transition-related expenses described above. 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 was subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Upon the expiration of the first anniversary of the transaction, this liability was settled. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Diversified Energy. 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.
Acquisitions Florida City Gas Pro forma

Revenue Recognition Revenue Rec

Revenue Recognition Revenue Recognition (Notes)	12 Months Ended
	Dec. 31, 2024
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 tables display revenue by major source based on product and service type for the years ended December 31, 2024, 2023 and 2022: For the Year Ended December 31, 2024 (in millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 76.9 $ — $ — $ 76.9 Florida Natural Gas distribution 170.3 — — 170.3 Florida City Gas 140.3 — — 140.3 FPU electric distribution 92.6 — — 92.6 Maryland natural gas division 24.6 — — 24.6 Sandpiper natural gas/propane operations 20.0 — — 20.0 Elkton Gas 7.3 — — 7.3 Total energy distribution 532.0 — — 532.0 Energy transmission Aspire Energy — 35.2 — 35.2 Aspire Energy Express 1.5 — — 1.5 Eastern Shore 81.7 — — 81.7 Peninsula Pipeline 34.5 — — 34.5 Total energy transmission 117.7 35.2 — 152.9 Energy generation Eight Flags — 18.0 — 18.0 Propane operations Propane distribution operations — 157.9 — 157.9 CNG / RNG Marlin Gas Services — 16.6 — 16.6 Other RNG 1.0 1.0 Total CNG / RNG Services — 17.6 — 17.6 Other and eliminations Eliminations (66.3) (0.3) (24.8) (91.4) Other — 0.2 0.2 Total other and eliminations (66.3) (0.3) (24.6) (91.2) Total operating revenues (1) $ 583.4 $ 228.4 $ (24.6) $ 787.2 (1) Total operating revenues for the year ended December 31, 2024, include other revenue (revenues from sources other than contracts with customers) of $1.6 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, 2023 (in millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 83.9 $ — $ — $ 83.9 Florida Natural Gas distribution 168.4 — — 168.4 Florida City Gas (1) 12.1 — — 12.1 FPU electric distribution 99.5 — — 99.5 Maryland natural gas division 28.1 — — 28.1 Sandpiper natural gas/propane operations 20.2 — — 20.2 Elkton Gas 8.8 — — 8.8 Total energy distribution 421.0 — — 421.0 Energy transmission Aspire Energy — 37.1 — 37.1 Aspire Energy Express 1.5 — — 1.5 Eastern Shore 79.9 — — 79.9 Peninsula Pipeline 30.4 — — 30.4 Total energy transmission 111.8 37.1 — 148.9 Energy generation Eight Flags — 19.2 — 19.2 Propane operations Propane distribution operations — 154.7 — 154.7 Compressed Natural Gas Services Marlin Gas Services — 12.3 — 12.3 Other and eliminations Eliminations (59.2) (0.2) (26.3) (85.7) Other — — 0.2 0.2 Total other and eliminations (59.2) (0.2) (26.1) (85.5) Total operating revenues (2) $ 473.6 $ 223.1 $ (26.1) $ 670.6 (1) 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. (2) 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 millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 82.2 $ — $ — $ 82.2 Florida Natural Gas distribution 155.9 — — 155.9 FPU electric distribution 81.7 — — 81.7 Maryland natural gas division 26.6 — — 26.6 Sandpiper natural gas/propane operations 21.3 — — 21.3 Elkton Gas 9.2 — — 9.2 Total energy distribution 376.9 — — 376.9 Energy transmission Aspire Energy — 56.2 — 56.2 Aspire Energy Express 1.4 — — 1.4 Eastern Shore 78.6 — — 78.6 Peninsula Pipeline 27.3 — — 27.3 Total energy transmission 107.3 56.2 — 163.5 Energy generation Eight Flags — 25.3 — 25.3 Propane operations Propane distribution operations — 188.4 — 188.4 Compressed Natural Gas Services Marlin Gas Services — 11.2 — 11.2 Other and eliminations Eliminations (54.8) (0.3) (29.8) (84.9) Other — — 0.3 0.3 Total other and eliminations (54.8) (0.3) (29.5) (84.6) Total operating revenues (1) $ 429.4 $ 280.8 $ (29.5) $ 680.7 (1) 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. 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 Station 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 continues to actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to also serve LNG and RNG market needs. 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 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, 2024 and 2023 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Noncurrent) Contract Liabilities (Current) (in millions) Balance at 12/31/2023 $ 67.7 $ — $ 3.5 $ 1.0 Balance at 12/31/2024 66.2 — 3.0 1.2 Increase (decrease) $ (1.5) $ — $ (0.5) $ 0.2 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 sheets 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, 2024 and 2023, the amount of contract liabilities 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, 2024 are expected to be recognized as follows: (in millions) 2025 2026 2027 2028 2029 2030 and thereafter Eastern Shore and Peninsula Pipeline $ 37.5 $ 34.5 $ 30.8 $ 28.6 $ 26.3 $ 130.6 Natural gas distribution operations 11.7 11.5 10.0 10.0 10.0 33.6 FPU electric distribution 0.7 0.4 0.4 0.4 — — Total revenue contracts with remaining performance obligations $ 49.9 $ 46.4 $ 41.2 $ 39.0 $ 36.3 $ 164.2

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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 operating decision maker, our President and Chief Executive Officer, in order to make decisions about resources and to assess performance. Our operations are entirely domestic and are comprised of two reportable segments: • Regulated Energy . Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore. • Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas related investments. 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 the Company, 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, 2024 2023 (in millions) Regulated Unregulated Other and Eliminations (1) Total Regulated Unregulated Other and Eliminations (1) Total Operating revenues, unaffiliated customers $ 578.3 $ 208.9 $ 0.2 $ 787.4 $ 471.6 $ 199.0 $ 0.2 $ 670.8 Intersegment revenues (2) 5.1 19.5 (24.8) (0.2) 2.0 24.1 (26.3) (0.2) 583.4 228.4 (24.6) 787.2 473.6 223.1 (26.1) 670.6 Less: Natural gas, propane and electric costs 144.2 100.2 (24.6) 219.8 140.0 102.5 (26.0) 216.5 Operations and maintenance expenses 158.5 74.4 (0.3) 232.6 125.3 73.8 (0.3) 198.8 Depreciation and amortization 48.8 16.9 — 65.7 48.2 17.3 — 65.5 Other segment items (3) 35.7 5.2 — 40.9 33.9 5.1 — 39.0 Segment operating income $ 196.2 $ 31.7 $ 0.3 $ 228.2 $ 126.2 $ 24.4 $ 0.2 $ 150.8 Other income, net 2.0 1.4 Interest charges 68.4 36.9 Income before income taxes 161.8 115.3 Income taxes 43.2 28.1 Net Income $ 118.6 $ 87.2 Capital expenditures (4) $ 320.2 $ 33.9 $ 1.7 $ 355.8 $ 1,095.9 $ 40.3 $ 1.8 $ 1,138.0 (1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company. (2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (3) Other segment items for each reportable segment include: Regulated - Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated - Other taxes. (4) Regulated capital expenditures in 2023 include our acquisition of FCG for $922.8 million. See Note 4 for additional details. For the Year Ended December 31, 2022 (in millions) Regulated Unregulated Other and Eliminations (1) Total Operating revenues, unaffiliated customers $ 422.9 $ 257.8 $ 0.3 $ 681.0 Intersegment revenues (2) 6.5 23.0 (29.8) (0.3) 429.4 280.8 (29.5) 680.7 Less: Natural gas, propane and electric costs 127.2 162.7 (29.4) 260.5 Operations and maintenance expenses 113.0 70.0 (0.3) 182.7 Depreciation and amortization 52.7 16.3 — 69.0 Other segment items (3) 21.2 4.3 0.1 25.6 Segment operating income $ 115.3 $ 27.5 $ 0.1 $ 142.9 Other income, net 5.1 Interest charges 24.4 Income before income taxes 123.6 Income taxes 33.8 Net Income $ 89.8 Capital expenditures $ 97.6 $ 40.8 $ 2.4 $ 140.8 (1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company. (2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (3) Other segment items for each reportable segment include: Regulated - Other taxes; Unregulated - Other taxes. As of December 31, (in millions) 2024 2023 Identifiable Assets Regulated Energy segment $ 3,042.9 $ 2,781.6 Unregulated Energy segment 486.4 477.4 Other businesses and eliminations 47.7 45.7 Total identifiable assets $ 3,577.0 $ 3,304.7

Supplemental Cash Flow Disclosu

Supplemental Cash Flow Disclosures	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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, 2024, 2023, and 2022 were as follows: For the Year Ended December 31, 2024 2023 2022 (in millions) Cash paid for interest $ 73.0 $ 30.5 $ 24.3 Cash (received) paid for income taxes, net of refunds $ 9.4 $ 21.9 $ (5.0) Non-cash investing and financing activities during the years ended December 31, 2024, 2023, and 2022 were as follows: For the Year Ended December 31, 2024 2023 2022 (in millions) Capital property and equipment acquired on account, but not paid for as of December 31, $ 34.0 $ 33.3 $ 13.2 Common stock issued for the Retirement Savings Plan $ 1.2 $ — $ — Common stock issued under the SICP $ 4.9 $ 3.7 $ 2.9

Derivative Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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, 2024 and 2023, our natural gas and electric distribution operations did not have any outstanding derivative contracts. Volume of Derivative Activity As of December 31, 2024, 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 10.8 Cash flow hedges March 2027 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 2024 through March 2027) 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 flow 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 $0.5 million of unrealized gains related to our propane derivatives 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 August 2024, we entered into an additional interest rate swap through August 2029, at a notional amount of $50.0 million and pricing of 3.97 percent. Our interest rate swaps are cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate. We designate and account for interest rate swaps as cash flow 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, 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 sheets which had a balance of $1.9 million and $2.1 million as of December 31, 2024 and December 31, 2023, respectively. 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, 2024 and 2023 are as follows: Derivative Assets Fair Value as of (in millions) Balance Sheet Location December 31, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value $ 0.6 $ 0.7 Interest rate swap agreements Derivative assets, at fair value 0.1 0.3 Total Derivative Assets (1) $ 0.7 $ 1.0 (1) Derivative assets, at fair value included $0.6 million and $1.0 million in current assets in the consolidated balance sheets at December 31, 2024 and 2023, respectively, with the remainder of the balance classified as long-term. Derivative Liabilities Fair Value as of (in millions) Balance Sheet Location December 31, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value $ — $ 1.1 Interest rate swap agreements Derivative liabilities, at fair value 0.1 0.2 Total Derivative Liabilities (1) $ 0.1 $ 1.3 (1) There were no current derivative liabilities at December 31, 2024. At December 31, 2023, current derivative liabilities amounted to $0.4 million 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 millions) 2024 2023 2022 Derivatives not designated as hedging instruments Propane swap agreements Propane and natural gas costs $ — $ — $ 0.1 Derivatives designated as cash flow hedges Propane swap agreements Revenues (0.3) 1.2 (0.4) Propane swap agreements Propane and natural gas costs 1.3 (1.1) 3.8 Interest rate swap agreements Interest expense 0.8 0.5 — Total $ 1.8 $ 0.6 $ 3.5

Fair Value of Financial Instrum

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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, 2024 and 2023, respectively: Fair Value Measurements Using: As of December 31, 2024 Fair Value Quoted Prices in Significant Other Significant (in millions) Assets: Investments—equity securities $ — $ — $ — $ — Investments—guaranteed income fund 1.1 — — 1.1 Investments—mutual funds and other 13.3 13.3 — — Total investments 14.4 13.3 — 1.1 Derivative assets 0.7 — 0.7 — Total assets $ 15.1 $ 13.3 $ 0.7 $ 1.1 Liabilities: Derivative liabilities $ 0.1 $ — $ 0.1 $ — Fair Value Measurements Using: As of December 31, 2023 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Significant (in millions) Assets: Investments—equity securities $ — $ — $ — $ — Investments—guaranteed income fund 1.5 — — 1.5 Investments—mutual funds and other 10.8 10.8 — — Total investments 12.3 10.8 — 1.5 Derivative assets 1.0 — 1.0 — Total assets $ 13.3 $ 10.8 $ 1.0 $ 1.5 Liabilities: Derivative liabilities $ 1.3 $ — $ 1.3 $ — The changes in the fair value of our Level 3 investments for the years ended December 31, 2024 and 2023 were not material. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income. At December 31, 2024 and 2023, 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, 2024, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.3 billion, compared to the estimated fair value of $1.2 billion. At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance costs, had both a carrying value and estimated fair value of $1.2 billion. 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, 2024
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, 2024 and 2023 was as follows: (in millions) Regulated Energy Unregulated Energy Total Goodwill Balance at December 31, 2023 $ 468.7 $ 39.5 $ 508.2 Reductions (1) (0.4) (0.1) (0.5) Balance at December 31, 2024 $ 468.3 $ 39.4 $ 507.7 (1) Adjustments to goodwill in our Regulated Energy segment attributable to purchase accounting adjustments related to our acquisition of FCG in November 2023. Adjustments in the Unregulated Energy segment relate to the sale of certain assets in our propane distribution business during 2024. See Note 4 for additional details. There were no goodwill impairments recognized during the three-year period ended December 31, 2024. The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2024 and 2023 were as follows: As of December 31, 2024 2023 (in millions) Gross Accumulated Gross Accumulated Customer relationships $ 17.0 $ 8.2 $ 17.0 $ 7.1 Non-Compete agreements 3.1 2.3 3.1 1.9 Patents (1) 6.6 1.2 6.6 0.9 Other 0.3 0.3 0.3 0.2 Total $ 27.0 $ 12.0 $ 27.0 $ 10.1 (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, 2024, 2023 and 2022 w as $1.9 million, $1.8 million and $1.5 million , respectively.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2024
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, 2024, 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 $99.3 million and $72.9 million as of December 31, 2024 and 2023, respectively, almost all of which will expire in 2040. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.1 million and $1.8 million related to state NOL carry-forwards at December 31, 2024 and 2023, 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 December 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 2024, 2023, and 2022; (b) the reconciliation between the statutory federal income tax rate and the Company's effective income tax rate for 2024, 2023, and 2022; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2024 and 2023. For the Year Ended December 31, 2024 2023 2022 (in millions) Current Income Tax Expense Federal $ 3.7 $ 14.7 $ 8.3 State 2.7 5.5 1.9 Other (0.4) — — Total current income tax expense 6.0 20.2 10.2 Deferred Income Tax Expense (1) Property, plant and equipment 33.2 17.8 15.0 Amortization of FCG goodwill 7.8 — — Deferred gas costs (1.0) (7.7) 8.9 Pensions and other employee benefits (0.3) (1.0) 1.1 Net operating loss carryforwards (2.5) (0.4) — Other — (0.8) (1.4) Total deferred income tax expense 37.2 7.9 23.6 Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8 (1) Includes $7.9 million, less than $0.1 million, and $7.8 million of deferred state income taxes for the years 2024, 2023, and 2022, respectively. For the Year Ended December 31, 2024 2023 2022 (in millions) Reconciliation of Effective Income Tax Rates Federal income tax expense (1) $ 34.0 $ 24.2 $ 26.0 State income taxes, net of federal benefit (2) 8.4 4.4 7.7 Other 0.8 (0.5) 0.1 Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8 Effective Income Tax Rate 26.71 % 24.35 % 27.34 % (1) Federal income taxes were calculated at 21 percent for 2024, 2023, and 2022. (2) 2023 includes the impact of the one-time benefit associated with the reduction in the Pennsylvania state tax rate. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for an additional information. As of December 31, 2024 2023 (in millions) Deferred Income Taxes Deferred income tax liabilities: Property, plant and equipment $ 289.7 $ 252.1 Acquisition adjustment 5.2 5.6 Deferred gas costs 2.5 3.6 Natural gas conversion costs 4.6 4.8 Storm reserve liability 5.8 5.8 Intangible assets 6.4 — Other 8.4 9.7 Total deferred income tax liabilities 322.6 281.6 Deferred income tax assets: Pension and other employee benefits 5.1 5.0 Net operating loss carryforwards 1.1 1.8 Accrued expenses 4.0 3.3 Regulatory asset 6.0 4.1 Intangible assets — 2.8 Other 10.3 5.5 Total deferred income tax assets 26.5 22.5 Deferred Income Taxes $ 296.1 $ 259.1

Long-Term Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
Long-Term Debt	L ONG - TERM D EBT Our outstanding long-term debt is shown below: As of December 31, (in millions) 2024 2023 Uncollateralized senior notes: 5.68% notes, due June 2026 $ 5.8 $ 8.7 6.39% notes, due December 2026 100.0 100.0 6.44% notes, due December 2027 100.0 100.0 6.43% notes, due May 2028 2.8 3.5 3.73% notes, due December 2028 8.0 10.0 6.45% notes, due December 2028 100.0 100.0 3.88% notes, due May 2029 25.0 30.0 5.20% notes, due October 2029 100.0 — 6.62% notes, due December 2030 100.0 100.0 3.25% notes, due April 2032 52.5 59.5 6.71% notes, due December 2033 100.0 100.0 2.98% notes, due December 2034 70.0 70.0 3.00% notes, due July 2035 50.0 50.0 2.96% notes, due August 2035 40.0 40.0 2.49% notes, due January 2037 50.0 50.0 5.43% notes, due March 2038 80.0 80.0 3.48% notes, due May 2038 50.0 50.0 3.58% notes, due November 2038 50.0 50.0 6.73% notes, due December 2038 50.0 50.0 3.98% notes, due August 2039 100.0 100.0 2.95% notes, due March 2042 50.0 50.0 Equipment security note 2.46% note, due September 2031 6.7 7.6 Less: debt issuance costs (3.6) (3.7) Total long-term debt 1,287.2 1,205.6 Less: current maturities (25.5) (18.5) Total long-term debt, net of current maturities $ 1,261.7 $ 1,187.1 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 1, 2024, we issued 5.20 percent Senior Notes due in November 2029 in the aggregate principal amount of $100.0 million. The proceeds received were used 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 semi-annual interest payments due on May 1 and November 1 of each year beginning in 2025. 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. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes (net of annual payments on the 6.73 percent notes which begin in 2029) 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 in March 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 2025 2026 2027 2028 2029 Thereafter Total (in millions) Payments $ 25.5 $ 134.6 $ 131.7 $ 136.7 $ 157.0 $ 705.3 $ 1,290.8 Shelf Agreements We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026, however neither of such lenders have any obligation to purchase debt thereunder. At December 31, 2024, a total of $255.0 million of borrowing capacity was available under these agreements.

Short-Term Borrowing

Short-Term Borrowing	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
Short-Term Borrowing	S HORT - TERM B ORROWINGS As of December 31, 2024, we are authorized by our Board of Directors to borrow up to $450.0 million of short-term debt, as required. At December 31, 2024 and 2023, we had $196.5 million and $179.9 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.06 percent and 5.83 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2024. In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche which now expires in August 2025 and $200.0 million available under the five-year tranche which now expires in August 2029. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be 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. The 364-day tranche continues to 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. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 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. We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 8, Derivative Instruments . 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 of no greater than 65 percent. As of December 31, 2024, we are in compliance with this covenant. Our total available credit under the Revolver at December 31, 2024 was $250.0 million. As of December 31, 2024, we had issued $6.9 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 .

Leases

Leases	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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, 2024, 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, 2024, 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 millions) Classification 2024 2023 2022 Operating lease cost (1) Operations expense $ 3.0 $ 3.0 $ 2.9 (1) Includes short-term leases and variable lease costs, which are not material. 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, 2024 and 2023: (in millions) Balance sheet classification December 31, 2024 December 31, 2023 Assets Operating lease assets Operating lease right-of-use assets $ 10.5 $ 12.4 Liabilities Current Operating lease liabilities Other accrued liabilities $ 2.4 $ 2.4 Noncurrent Operating lease liabilities Operating lease - liabilities 8.7 10.6 Total lease liabilities $ 11.1 $ 13.0 The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2024 and 2023: December 31, 2024 December 31, 2023 Weighted-average remaining lease term ( in years ) Operating leases 7.7 8.1 Weighted-average discount rate Operating leases 3.5 % 3.5 % 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, 2024, 2023 and 2022: Year Ended December 31, (in millions) 2024 2023 2022 Operating cash flows from operating leases $ 2.9 $ 2.9 $ 2.9 The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2024 and for each of the next five years and thereafter: (in millions) Operating Leases (1) 2025 $ 2.6 2026 1.9 2027 1.6 2028 1.2 2029 1.1 Thereafter 4.1 Total lease payments 12.5 Less: Interest (1.4) Present value of lease liabilities $ 11.1 (1) Operating lease payments include $2.0 million related to options to extend lease terms that are reasonably certain of being exercised.

Stockholders' Equity

Stockholders' Equity	12 Months Ended
	Dec. 31, 2024
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 other plans. Depending on our capital needs and subject to market conditions, we may issue additional shares under the direct stock purchase component of the DRIP in addition to other possible debt and equity offerings. For the year ended December 31, 2024, we received net proceeds of $72.5 million associated with shares issued under the direct stock purchase and waiver components of the DRIP. There were no issuances under the DRIP in 2023. In November 2024, we established a new ATM program under which we may sell shares of our common stock up to an aggregate offering price of $100.0 million. This current ATM program is active through November 2027 and there were no issuances under the program in 2024. Our previous ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $75.0 million, expired in June 2023. 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, 2024 and 2023. 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 millions) As of December 31, 2022 $ (2.5) $ 1.1 $ — $ (1.4) Other comprehensive income (loss) before reclassifications (0.1) (1.4) 0.5 (1.0) Amounts reclassified from accumulated other comprehensive income (loss) — — (0.4) (0.4) Net current-period other comprehensive income (loss) (0.1) (1.4) 0.1 (1.4) As of December 31, 2023 (2.6) (0.3) 0.1 (2.8) Other comprehensive income (loss) before reclassifications 0.5 1.4 0.5 2.4 Amounts reclassified from accumulated other comprehensive income (loss) — (0.7) (0.6) (1.3) Net current-period other comprehensive income (loss) 0.5 0.7 (0.1) 1.1 As of December 31, 2024 $ (2.1) $ 0.4 $ — $ (1.7) Deferred gains or losses for our commodity contract and interest rate swap cash flow hedges are recognized in earnings upon settlement and are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments , for additional details. Amortization of the net loss related to the defined benefit pension plan and postretirement plans is included in the computation of net periodic costs (benefits). See Note 16, Employee Benefit Plans

Employee Benefit Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
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, 2024 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. 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, 2024 and 2023, 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, 2024 and 2023 and the net periodic cost (benefit) for the years ended December 31, 2024, 2023 and 2022 for the FPU Pension Plan and the Chesapeake SERP: FPU Chesapeake 2024 2023 2024 2023 (in millions) Change in benefit obligation: Benefit obligation — beginning of year $ 49.7 $ 49.9 $ 1.6 $ 1.7 Interest cost 2.4 2.5 0.1 0.1 Actuarial (gain) loss (2.0) 0.5 — — Benefits paid (4.6) (3.2) (0.2) (0.2) Benefit obligation — end of year 45.5 49.7 1.5 1.6 Change in plan assets: Fair value of plan assets — beginning of year 49.5 46.2 — — Actual return on plan assets 4.2 6.5 — — Employer contributions — — 0.2 0.2 Benefits paid (4.6) (3.2) (0.2) (0.2) Fair value of plan assets — end of year 49.1 49.5 — — Accrued pension funded status $ 3.6 $ (0.2) $ (1.5) $ (1.6) Assumptions: Discount rate 5.50 % 5.00 % 5.40 % 4.88 % Expected return on plan assets 6.00 % 6.00 % — % — % FPU Chesapeake For the Years Ended December 31, 2024 2023 2022 2024 2023 2022 (in millions) Components of net periodic pension (benefit) cost: Interest cost $ 2.4 $ 2.5 $ 1.8 $ 0.1 $ 0.1 $ 0.1 Expected return on assets (2.9) (2.7) (3.4) — — — Amortization of actuarial loss 0.3 0.4 0.5 — — — Total periodic (benefit) cost $ (0.2) $ 0.2 $ (1.1) $ 0.1 $ 0.1 $ 0.1 Assumptions: Discount rate 5.00 % 5.25 % 2.75 % 4.88 % 5.00 % 2.50 % Expected return on plan assets 6.00 % 6.00 % 6.00 % — % — % — % 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 allocation of assets of the FPU Pension Plan, by investment type, at December 31, 2024, 2023 and 2022: FPU Pension Plan At December 31, 2024 2023 2022 Asset Category Equity securities 31 % 50 % 53 % Debt securities 67 49 38 Other 2 1 9 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 target allocation 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 Target Range (+/-) Domestic Equities (Large Cap, Mid Cap and Small Cap) 27 % 7 % Fixed Income (Inflation Bond and Taxable Fixed) 68 % 4 % Foreign Equities (Developed and Emerging Markets) 3 % 1 % Cash 2 % 2 % 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, 2024 and 2023, the assets of the FPU Pension Plan were comprised of the following investments: As of December 31, Asset Category 2024 2023 (in millions) Mutual Funds - Equity securities U.S. Large Cap (1) $ 10.6 $ 15.4 U.S. Mid Cap (1) 3.2 4.3 U.S. Small Cap (1) — 2.5 International (2) 1.3 2.5 15.1 24.7 Mutual Funds - Debt securities Fixed income (3) 32.8 24.2 32.8 24.2 Mutual Funds - Other Guaranteed deposit (4) 1.2 0.6 1.2 0.6 Total Pension Plan Assets at fair value (5) $ 49.1 $ 49.5 (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 invest in fixed income securities. (4) Includes investment in a group annuity product issued by an insurance company. (5) 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. At December 31, 2024 and 2023, 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, 2024 and 2023 were not material. Other Postretirement Benefits Plans We sponsor two unfunded defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. At December 31, 2024 and 2023, the total obligation of the Chesapeake Postretirement Plan was $0.9 million and $1.1 million, respectively. The total obligation of the FPU Medical Plan was $0.3 million and $0.4 million as of December 31, 2024 and 2023, 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, 2024, 2023, and 2022. Amounts Not Yet Reflected in Periodic Benefit Cost As of December 31, 2024, there was $9.2 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 $7.1 million and $1.3 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $2.6 million recorded in accumulated other comprehensive income (loss) and $5.8 million recorded as a regulatory asset at December 31, 2024. 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 2024, 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 2024 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 2025, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.3 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 the FPU Pension Plan. Estimated payments related to the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan are not material. FPU Pension Plan (1) (in millions) 2025 $ 3.6 2026 $ 3.7 2027 $ 3.6 2028 $ 3.7 2029 $ 3.6 Years 2030 through 2034 $ 17.6 (1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets. 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 $8.4 million, $6.6 million, and $6.2 million for the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024, there were 788,495 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 sheets, had a fair value of $14.4 million and $12.3 million at December 31, 2024 and 2023, 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, 2024
Text Block [Abstract]
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, which has awards outstanding under the current 2023 plan and the previous 2013 plan. 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 expected to be issued at the end of the service period. We have 524,579 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, 2024, 2023 and 2022: For the Year Ended December 31, 2024 2023 2022 (in millions) Awards to key employees $ 7.5 $ 6.7 $ 5.5 Awards to non-employee directors 0.9 0.9 1.0 Total compensation expense 8.4 7.6 6.5 Less: tax benefit (2.2) (1.9) (1.7) Share-based compensation expense included in net income $ 6.2 $ 5.7 $ 4.8 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 awards under various 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 and key employees: (in thousands, except per share data) Number of Weighted Average Outstanding — December 31, 2022 204 $ 103.17 Granted 81 126.06 Vested (68) 91.59 Expired (2) 94.64 Forfeited (2) 113.44 Outstanding — December 31, 2023 213 117.74 Granted 110 105.21 Vested (43) 103.95 Expired (27) 86.24 Forfeited — — Outstanding — December 31, 2024 253 $ 117.96 During the year ended December 31, 2024, we granted awards of 110 thousand shares of common stock to officers and key employees under the SICP, including awards granted in February 2024. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2026. The aggregate intrinsic value of the SICP awards granted was $30.8 million, $22.5 million, and $24.1 million at December 31, 2024, 2023 and 2022, respectively. At December 31, 2024, there was $6.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2026. In March 2024, 2023 and 2022, 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 2024, 2023 and 2022 for the performance periods ended December 31, 2023, 2022, and 2021. 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, 2024 2023 2022 (dollars in millions, shares in thousands) Shares withheld to satisfy tax obligations 14 20 22 Amounts remitted to tax authorities to satisfy obligations $ 1.5 $ 2.5 $ 2.8

Rates and Other Regulatory Acti

Rates and Other Regulatory Activities	12 Months Ended
	Dec. 31, 2024
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. Delaware 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 which customers can participate (and allow for recovery), including Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and a standard Offer Program. In April 2024, all programs, with the exception of the Offer Program, were approved by the PSC and rates became effective May 1, 2024. Delaware Natural Gas Rate Case: In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective in October 2024. The hearing for the proceeding has been scheduled for May 2025, and the outcome of the application is subject to review and approval by the Delaware PSC. Maryland 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 sought approval of the following: (i) permanent rate relief of approximately $6.9 million with a ROE of 11.5 percent; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses (CUC-Maryland Division, Sandpiper Energy, and Elkton Gas) 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. In August 2024, the Maryland natural gas distribution businesses, the Maryland Office of Peoples' Counsel ("OPC") and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million increase in annual base rates was approved and the Company filed the Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The hearing has been scheduled for March 2025 and 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. A settlement agreement between the Company, PSC staff and the OPC was reached and the final order approving the settlement agreement went into effect in July 2024, with new depreciation rates effective as of January 1, 2023. The approved depreciation resulted in an annual reduction in depreciation expense of approximately $1.2 million. 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 enables 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. 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 Florida PSC 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. In June 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied in September 2023. In July 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief in January 2024 with answer briefs filed in April 2024. Oral arguments in the case were held in December 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 month 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, 2024 and 2023, the Company recorded decreases to asset removal costs and depreciation expense of $15.5 million and $5.1 million, respectively, as a result of the RSAM adjustment. At December 31, 2024, the RSAM reserve had been completely utilized. In February 2025, FCG filed a depreciation study with the Florida PSC. The application is requesting approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. The outcome of the application is subject to review and approval by the Florida PSC. Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which requires 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 Florida PSC voted to approve the projections in November 2023. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs of $20.4 million for both capital and operating expenses. 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. FCG SAFE Program : In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the Florida PSC approved a replacement of 160 miles of pipe that was used in the 1970s and 1980s and shown through industry research to exhibit premature failure in the form of cracking. The program includes projected capital expenditures of $205.0 million over a 10-year period. In April 2024, FCG filed a petition with the Florida PSC to more closely align the SAFE Program with FPU's GUARD program. Specifically, the requested modifications will enable FCG to accelerate remediation related to problematic pipes and facilities consisting of obsolete and exposed pipes. These efforts will serve to improve the safety and reliability of service to FCG's customers and the modifications will increase the total projected capital expenditures to $50.0 million in capital expenditures associated with the SAFE Program, which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024. 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 existing Company owned propane community gas systems in Newberry was made in November 2023. The Florida PSC approved it in April 2024, and conversions of the community gas systems commenced in the second quarter of 2024. 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 are experiencing significant 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/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. Construction is projected to be complete in the second and fourth quarters of 2025 for New Smyrna Beach and Boynton Beach, respectively. Central Florida Reinforcement Projects : In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida. The projects are driven by the need for increased supply to communities in central Florida that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU's distribution system around the Plant City and Lake Mattie areas of Florida with an additional 5,000 Dts/d and 8,700 Dts/d, respectively. The Florida PSC approved the projects in May 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project is projected to be completed during the fourth quarter of 2025. Renewable Natural Gas Supply Projects : In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition at its July 2024 meeting with the projects estimated to be completed in the first half of 2025. St. Cloud Project Amendment : In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to its Transportation Service Agreement with FPU for a project that will support additional supply to communities in the St. Cloud, Florida area. The project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the fourth quarter of 2025. Pioneer Supply Header Pipeline Project : In March 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Firm Transportation Service Agreements with both FCG and FPU for a project that will support greater supply growth of natural gas service in southeast Florida. The project consists of the transfer of a pipeline asset from FCG to Peninsula Pipeline. Peninsula Pipeline will proceed to provide transportation service to both FCG and FPU using the pipeline asset, which supports continued customer growth and system reinforcement of these distribution systems. The Florida PSC approved the petition in July 2024 and the project was completed in September 2024. Miami Inner Loop Projects: In September 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of the Transportation Service Agreement with FCG for a series of projects that will enhance the infrastructure in Miami-Dade County. The proposed expansion consists of the development of several pipeline projects to support growth and support FCG's distribution system in the area and also enhance FCG's ability to obtain gas from various access points in the Miami-Dade County area. The project was approved in February 2025. FPU Electric Rate Case : In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million, were approved with an effective date of November 1, 2024. The outcome of the application is subject to review and approval by the Florida PSC. The hearings for the approval of the revenue requirement and rates are scheduled to occur in March 2025. Eastern Shore 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. In January 2025, the FERC approved the project, and construction is expected to be complete in the third quarter of 2025. Capital Cost Surcharge: In December 2024, 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 because of mandated highway relocation projects as well as compliance with a 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 in December 2024. The combined revised surcharge became effective January 1, 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. Implementation of the CIS began during the first quarter of 2023 and went into service during the fourth quarter of 2024. TCJA In connection with the TCJA, which was signed into law in December 2017, customer rates for our regulated businesses were adjusted as applicable as approved by the regulators. Regulatory liabilities related to accumulated deferred income taxes (“ADIT”) associated with the TCJA amounted to $84.6 million and $85.8 million at December 31, 2024 and 2023, respectively. With the exception of the ADIT balance of $34.2 million attributable to Eastern Shore, such amounts are being amortized in accordance with approvals received from the Delaware, Maryland, and Florida PSCs in 2018 and 2019. The ADIT balance attributable to Eastern Shore will be addressed in its next rate case filing. Regulatory Assets and Liabilities At December 31, 2024 and 2023, 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, 2024 2023 (in millions) Regulatory Assets Under-recovered purchased fuel, electric, gas and conservation cost recovery (1) (2) $ 9.7 $ 13.7 Under-recovered GRIP revenue (3) 1.6 1.8 Deferred postretirement benefits (4) 7.7 10.8 Deferred conversion and development costs (1) 20.6 21.5 Acquisition adjustment (5) 29.6 31.9 Deferred storm costs (6) 11.1 19.4 Deferred rate case expenses - current 1.2 1.2 Other 19.8 15.6 Total Regulatory Assets $ 101.3 $ 115.9 Regulatory Liabilities Over-recovered purchased fuel and conservation cost recovery (1) $ 15.5 $ 12.3 Storm reserve (7) 2.1 1.9 Accrued asset removal cost (8) 77.9 86.5 Deferred income taxes due to rate change (9) 102.6 105.1 Other 2.0 3.2 Total Regulatory Liabilities $ 200.1 $ 209.0 (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) Includes amounts 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 gas distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution operations, 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) 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. (7) We have storm reserves in our Florida 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. (8) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies. (9) 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, 2024
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, 2024 and 2023, we had approximately $3.2 million and $3.6 million, respectively, in environmental liabilities, related to the former MGP sites, and related regulatory assets of $0.3 million and $0.5 million at the respective balance sheet dates for future recovery of environmental costs from customers. Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware. The remaining clean-up costs are estimated to range from $0.3 million to $0.8 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 not material. 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 actions have been initiated on the site's west parcel, and construction of the systems required to remediate the site are now complete with remediation activities underway at December 31, 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system start-up on the West Parcel, and continued operation and maintenance, are estimated to take between five and fifteen years of operation, maintenance and monitoring, and final site work for closeout of the property is estimated to be between $2.8 million and $5.2 million.

Other Commitments and Contingen

Other Commitments and Contingencies	12 Months Ended
	Dec. 31, 2024
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 in April 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. 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 standard, it must provide an Adequate Assurance of Performance which can include an irrevocable letter of credit, a prepayment, a security interest in an asset, or a performance bond or guaranty. As of December 31, 2024, 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 2025 2026-2027 2028-2029 Beyond 2029 Total (in millions) Purchase Obligations $ 90.2 $ 103.6 $ 73.7 $ 119.4 $ 386.9 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, 2024 was $38.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2024 was approximately $28.4 million with the guarantees expiring on various dates through November 2025. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2024 was $5.2 million.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2024
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 within 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, 2024 and 2023 is provided in the following table: As of December 31, (in millions) 2024 2023 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida $ 1,679.3 $ 1,486.8 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 819.5 788.2 Electric distribution 163.0 143.5 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 201.6 194.9 Natural gas transmission and supply – Ohio 139.2 134.2 Electricity and steam generation 37.4 37.1 Mobile CNG and pipeline solutions 52.8 40.6 Sustainable energy investments, including renewable natural gas related investments 32.7 4.0 Other 29.9 30.3 Total property, plant and equipment 3,155.4 2,859.6 Less: Accumulated depreciation and amortization (567.6) (516.4) Plus: Construction work in progress 148.1 113.2 Net property, plant and equipment $ 2,735.9 $ 2,456.4 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, 2024 and 2023, the non-refundable contributions totaled $5.9 million and $4.2 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 year ended December 31, 2024, AFUDC was $1.4 million and was reflected as a reduction of interest expense. For the years ended December 31, 2023 and 2022, AFUDC was not material. 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, 2024, 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 $2.8 million and $2.2 million at December 31, 2024 and 2023, 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, 2024, 2023 and 2022, we reported $15.8 million, $11.9 million and $11.0 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, 2024, 2023 and 2022: 2024 2023 2022 Natural gas distribution – Delmarva Peninsula (1) 2.1% 2.5% 2.5% Natural gas distribution – Florida (2) (3) 2.7% 2.2% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.4% Natural gas transmission – Ohio (4) 2.3% 5.0% 5.0% Electric distribution 2.4% 2.4% 2.8% (1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper. (2) Includes the impact of FCG beginning in 2024. (3) 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. (4) 2024 rate excludes the impact of cumulative adjustments related to a change in useful lives of certain assets. Such adjustments were not material to the Company's results of operations for the year ended December 31, 2024. 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, 2024: (in millions) Balance at December 31, 2023 $ 2.7 Additions: Provision for credit losses 2.1 Recoveries 0.4 Deductions: Write offs (1.9) Balance at December 31, 2024 $ 3.3
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, 2024, 2023 or 2022.
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 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
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 when it is more likely than not that such income tax benefits will be realized. Valuation allowances may be recorded if it is determined that some deferred tax assets will not 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]	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. We adopted ASU 2023-07 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, did not have an impact on our financial position or results of operations. Recent Accounting Standards Yet to be Adopted FASB Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2025. ASU 2023-09 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations. Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-04, Disaggregation of Income Statement Expenses, which require disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-04 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations. SEC Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed and sought review of the final ruling in multiple courts of appeals. At this time, it is uncertain as to when the review will be completed, the final outcome of the review, and the timing of required disclosure.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2024
Accounting Policies [Abstract]
Property, Plant and Equipment [Table Text Block]	A summary of property, plant and equipment by classification as of December 31, 2024 and 2023 is provided in the following table: As of December 31, (in millions) 2024 2023 Property, plant and equipment Regulated Energy Natural gas distribution - Delmarva Peninsula and Florida $ 1,679.3 $ 1,486.8 Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 819.5 788.2 Electric distribution 163.0 143.5 Unregulated Energy Propane operations – Mid-Atlantic, North Carolina, South Carolina and Florida 201.6 194.9 Natural gas transmission and supply – Ohio 139.2 134.2 Electricity and steam generation 37.4 37.1 Mobile CNG and pipeline solutions 52.8 40.6 Sustainable energy investments, including renewable natural gas related investments 32.7 4.0 Other 29.9 30.3 Total property, plant and equipment 3,155.4 2,859.6 Less: Accumulated depreciation and amortization (567.6) (516.4) Plus: Construction work in progress 148.1 113.2 Net property, plant and equipment $ 2,735.9 $ 2,456.4
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, 2024, 2023 and 2022, we reported $15.8 million, $11.9 million and $11.0 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, 2024, 2023 and 2022: 2024 2023 2022 Natural gas distribution – Delmarva Peninsula (1) 2.1% 2.5% 2.5% Natural gas distribution – Florida (2) (3) 2.7% 2.2% 2.5% Natural gas transmission – Delmarva Peninsula 2.7% 2.7% 2.7% Natural gas transmission – Florida 2.4% 2.4% 2.4% Natural gas transmission – Ohio (4) 2.3% 5.0% 5.0% Electric distribution 2.4% 2.4% 2.8% (1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper. (2) Includes the impact of FCG beginning in 2024. (3) 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. (4)
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, 2024
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, 2024 2023 2022 (dollars in millions, shares in thousands (except per share data)) Calculation of Basic Earnings Per Share: Net Income $ 118.6 $ 87.2 $ 89.8 Weighted average shares outstanding (1) 22,469 18,371 17,722 Basic Earnings Per Share $ 5.28 $ 4.75 $ 5.07 Calculation of Diluted Earnings Per Share: Reconciliation of Denominator: Weighted average shares outstanding — Basic (1) 22,469 18,371 17,722 Effect of dilutive securities — Share-based compensation 62 64 82 Adjusted denominator — Diluted (1) 22,531 18,435 17,804 Diluted Earnings Per Share $ 5.26 $ 4.73 $ 5.04 (1) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.

Acquisitions (Tables)

Acquisitions (Tables)	12 Months Ended
	Dec. 31, 2024
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Acquisitions Florida City Gas Pro forma
Florida City Gas Purchas Price Allocation	(in millions) Assets acquired: Acquisition Date Fair Value Cash $ 2.3 Accounts receivable, net 14.1 Regulatory assets - current 3.0 Other current assets 2.0 Property, plant and equipment 454.4 Goodwill 460.9 Regulatory assets - non-current 3.4 Other deferred charges and other assets 18.3 Total assets acquired 958.4 Liabilities assumed: Current liabilities (20.9) Regulatory liabilities (14.1) Other deferred credits and other liabilities (0.6) Total liabilities assumed (35.6) Net purchase price $ 922.8

Revenue Recognition Revenue R_2

Revenue Recognition Revenue Recognition (Tables)	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	for the years ended December 31, 2024, 2023 and 2022: For the Year Ended December 31, 2024 (in millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 76.9 $ — $ — $ 76.9 Florida Natural Gas distribution 170.3 — — 170.3 Florida City Gas 140.3 — — 140.3 FPU electric distribution 92.6 — — 92.6 Maryland natural gas division 24.6 — — 24.6 Sandpiper natural gas/propane operations 20.0 — — 20.0 Elkton Gas 7.3 — — 7.3 Total energy distribution 532.0 — — 532.0 Energy transmission Aspire Energy — 35.2 — 35.2 Aspire Energy Express 1.5 — — 1.5 Eastern Shore 81.7 — — 81.7 Peninsula Pipeline 34.5 — — 34.5 Total energy transmission 117.7 35.2 — 152.9 Energy generation Eight Flags — 18.0 — 18.0 Propane operations Propane distribution operations — 157.9 — 157.9 CNG / RNG Marlin Gas Services — 16.6 — 16.6 Other RNG 1.0 1.0 Total CNG / RNG Services — 17.6 — 17.6 Other and eliminations Eliminations (66.3) (0.3) (24.8) (91.4) Other — 0.2 0.2 Total other and eliminations (66.3) (0.3) (24.6) (91.2) Total operating revenues (1) $ 583.4 $ 228.4 $ (24.6) $ 787.2 (1) Total operating revenues for the year ended December 31, 2024, include other revenue (revenues from sources other than contracts with customers) of $1.6 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, 2023 (in millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 83.9 $ — $ — $ 83.9 Florida Natural Gas distribution 168.4 — — 168.4 Florida City Gas (1) 12.1 — — 12.1 FPU electric distribution 99.5 — — 99.5 Maryland natural gas division 28.1 — — 28.1 Sandpiper natural gas/propane operations 20.2 — — 20.2 Elkton Gas 8.8 — — 8.8 Total energy distribution 421.0 — — 421.0 Energy transmission Aspire Energy — 37.1 — 37.1 Aspire Energy Express 1.5 — — 1.5 Eastern Shore 79.9 — — 79.9 Peninsula Pipeline 30.4 — — 30.4 Total energy transmission 111.8 37.1 — 148.9 Energy generation Eight Flags — 19.2 — 19.2 Propane operations Propane distribution operations — 154.7 — 154.7 Compressed Natural Gas Services Marlin Gas Services — 12.3 — 12.3 Other and eliminations Eliminations (59.2) (0.2) (26.3) (85.7) Other — — 0.2 0.2 Total other and eliminations (59.2) (0.2) (26.1) (85.5) Total operating revenues (2) $ 473.6 $ 223.1 $ (26.1) $ 670.6 (1) 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. (2)	For the Year Ended December 31, 2022 (in millions) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Delaware natural gas division $ 82.2 $ — $ — $ 82.2 Florida Natural Gas distribution 155.9 — — 155.9 FPU electric distribution 81.7 — — 81.7 Maryland natural gas division 26.6 — — 26.6 Sandpiper natural gas/propane operations 21.3 — — 21.3 Elkton Gas 9.2 — — 9.2 Total energy distribution 376.9 — — 376.9 Energy transmission Aspire Energy — 56.2 — 56.2 Aspire Energy Express 1.4 — — 1.4 Eastern Shore 78.6 — — 78.6 Peninsula Pipeline 27.3 — — 27.3 Total energy transmission 107.3 56.2 — 163.5 Energy generation Eight Flags — 25.3 — 25.3 Propane operations Propane distribution operations — 188.4 — 188.4 Compressed Natural Gas Services Marlin Gas Services — 11.2 — 11.2 Other and eliminations Eliminations (54.8) (0.3) (29.8) (84.9) Other — — 0.3 0.3 Total other and eliminations (54.8) (0.3) (29.5) (84.6) Total operating revenues (1) $ 429.4 $ 280.8 $ (29.5) $ 680.7 (1) 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.
Contract with Customer, Asset and Liability [Table Text Block]	The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2024 and 2023 were as follows: Trade Receivables Contract Assets (Current) Contract Assets (Noncurrent) Contract Liabilities (Current) (in millions) Balance at 12/31/2023 $ 67.7 $ — $ 3.5 $ 1.0 Balance at 12/31/2024 66.2 — 3.0 1.2 Increase (decrease) $ (1.5) $ — $ (0.5) $ 0.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Table Text Block]	Revenue for these businesses for the remaining performance obligations at December 31, 2024 are expected to be recognized as follows: (in millions) 2025 2026 2027 2028 2029 2030 and thereafter Eastern Shore and Peninsula Pipeline $ 37.5 $ 34.5 $ 30.8 $ 28.6 $ 26.3 $ 130.6 Natural gas distribution operations 11.7 11.5 10.0 10.0 10.0 33.6 FPU electric distribution 0.7 0.4 0.4 0.4 — — Total revenue contracts with remaining performance obligations $ 49.9 $ 46.4 $ 41.2 $ 39.0 $ 36.3 $ 164.2

Segment Information Segment Inf

Segment Information Segment Information (Tables)	12 Months Ended
	Dec. 31, 2024
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment	: For the Year Ended December 31, 2024 2023 (in millions) Regulated Unregulated Other and Eliminations (1) Total Regulated Unregulated Other and Eliminations (1) Total Operating revenues, unaffiliated customers $ 578.3 $ 208.9 $ 0.2 $ 787.4 $ 471.6 $ 199.0 $ 0.2 $ 670.8 Intersegment revenues (2) 5.1 19.5 (24.8) (0.2) 2.0 24.1 (26.3) (0.2) 583.4 228.4 (24.6) 787.2 473.6 223.1 (26.1) 670.6 Less: Natural gas, propane and electric costs 144.2 100.2 (24.6) 219.8 140.0 102.5 (26.0) 216.5 Operations and maintenance expenses 158.5 74.4 (0.3) 232.6 125.3 73.8 (0.3) 198.8 Depreciation and amortization 48.8 16.9 — 65.7 48.2 17.3 — 65.5 Other segment items (3) 35.7 5.2 — 40.9 33.9 5.1 — 39.0 Segment operating income $ 196.2 $ 31.7 $ 0.3 $ 228.2 $ 126.2 $ 24.4 $ 0.2 $ 150.8 Other income, net 2.0 1.4 Interest charges 68.4 36.9 Income before income taxes 161.8 115.3 Income taxes 43.2 28.1 Net Income $ 118.6 $ 87.2 Capital expenditures (4) $ 320.2 $ 33.9 $ 1.7 $ 355.8 $ 1,095.9 $ 40.3 $ 1.8 $ 1,138.0 (1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company. (2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (3) Other segment items for each reportable segment include: Regulated - Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated - Other taxes. (4) Regulated capital expenditures in 2023 include our acquisition of FCG for $922.8 million. See Note 4 for additional details. For the Year Ended December 31, 2022 (in millions) Regulated Unregulated Other and Eliminations (1) Total Operating revenues, unaffiliated customers $ 422.9 $ 257.8 $ 0.3 $ 681.0 Intersegment revenues (2) 6.5 23.0 (29.8) (0.3) 429.4 280.8 (29.5) 680.7 Less: Natural gas, propane and electric costs 127.2 162.7 (29.4) 260.5 Operations and maintenance expenses 113.0 70.0 (0.3) 182.7 Depreciation and amortization 52.7 16.3 — 69.0 Other segment items (3) 21.2 4.3 0.1 25.6 Segment operating income $ 115.3 $ 27.5 $ 0.1 $ 142.9 Other income, net 5.1 Interest charges 24.4 Income before income taxes 123.6 Income taxes 33.8 Net Income $ 89.8 Capital expenditures $ 97.6 $ 40.8 $ 2.4 $ 140.8 (1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company. (2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues. (3) Other segment items for each reportable segment include: Regulated - Other taxes; Unregulated - Other taxes. As of December 31, (in millions) 2024 2023 Identifiable Assets Regulated Energy segment $ 3,042.9 $ 2,781.6 Unregulated Energy segment 486.4 477.4 Other businesses and eliminations 47.7 45.7 Total identifiable assets $ 3,577.0 $ 3,304.7

Supplemental Cash Flow Disclo_2

Supplemental Cash Flow Disclosures (Tables)	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
Cash Paid for Interest and Income Taxes	Cash paid for interest and income taxes during the years ended December 31, 2024, 2023, and 2022 were as follows: For the Year Ended December 31, 2024 2023 2022 (in millions) Cash paid for interest $ 73.0 $ 30.5 $ 24.3 Cash (received) paid for income taxes, net of refunds $ 9.4 $ 21.9 $ (5.0)
Non-Cash Investing and Financing Activities	Non-cash investing and financing activities during the years ended December 31, 2024, 2023, and 2022 were as follows: For the Year Ended December 31, 2024 2023 2022 (in millions) Capital property and equipment acquired on account, but not paid for as of December 31, $ 34.0 $ 33.3 $ 13.2 Common stock issued for the Retirement Savings Plan $ 1.2 $ — $ — Common stock issued under the SICP $ 4.9 $ 3.7 $ 2.9

Derivative Instruments (Tables)

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
Schedule of Derivative Instruments [Table Text Block]	As of December 31, 2024, 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 10.8 Cash flow hedges March 2027
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, 2024 and 2023 are as follows: Derivative Assets Fair Value as of (in millions) Balance Sheet Location December 31, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative assets, at fair value $ 0.6 $ 0.7 Interest rate swap agreements Derivative assets, at fair value 0.1 0.3 Total Derivative Assets (1) $ 0.7 $ 1.0 (1) Derivative assets, at fair value included $0.6 million and $1.0 million in current assets in the consolidated balance sheets at December 31, 2024 and 2023, respectively, with the remainder of the balance classified as long-term. Derivative Liabilities Fair Value as of (in millions) Balance Sheet Location December 31, 2024 December 31, 2023 Derivatives designated as cash flow hedges Propane swap agreements Derivative liabilities, at fair value $ — $ 1.1 Interest rate swap agreements Derivative liabilities, at fair value 0.1 0.2 Total Derivative Liabilities (1) $ 0.1 $ 1.3 (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 millions) 2024 2023 2022 Derivatives not designated as hedging instruments Propane swap agreements Propane and natural gas costs $ — $ — $ 0.1 Derivatives designated as cash flow hedges Propane swap agreements Revenues (0.3) 1.2 (0.4) Propane swap agreements Propane and natural gas costs 1.3 (1.1) 3.8 Interest rate swap agreements Interest expense 0.8 0.5 — Total $ 1.8 $ 0.6 $ 3.5

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024 and 2023, respectively: Fair Value Measurements Using: As of December 31, 2024 Fair Value Quoted Prices in Significant Other Significant (in millions) Assets: Investments—equity securities $ — $ — $ — $ — Investments—guaranteed income fund 1.1 — — 1.1 Investments—mutual funds and other 13.3 13.3 — — Total investments 14.4 13.3 — 1.1 Derivative assets 0.7 — 0.7 — Total assets $ 15.1 $ 13.3 $ 0.7 $ 1.1 Liabilities: Derivative liabilities $ 0.1 $ — $ 0.1 $ — Fair Value Measurements Using: As of December 31, 2023 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Significant (in millions) Assets: Investments—equity securities $ — $ — $ — $ — Investments—guaranteed income fund 1.5 — — 1.5 Investments—mutual funds and other 10.8 10.8 — — Total investments 12.3 10.8 — 1.5 Derivative assets 1.0 — 1.0 — Total assets $ 13.3 $ 10.8 $ 1.0 $ 1.5 Liabilities: Derivative liabilities $ 1.3 $ — $ 1.3 $ —
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, 2024 and 2023 were not material. 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, 2024
Text Block [Abstract]
Schedule of Carrying Value of Goodwill	The carrying value of goodwill as of December 31, 2024 and 2023 was as follows: (in millions) Regulated Energy Unregulated Energy Total Goodwill Balance at December 31, 2023 $ 468.7 $ 39.5 $ 508.2 Reductions (1) (0.4) (0.1) (0.5) Balance at December 31, 2024 $ 468.3 $ 39.4 $ 507.7 (1) Adjustments to goodwill in our Regulated Energy segment attributable to purchase accounting adjustments related to our acquisition of FCG in November 2023. Adjustments in the Unregulated Energy segment relate to the sale of certain assets in our propane distribution business during 2024. See Note 4 for additional details.
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, 2024 and 2023 were as follows: As of December 31, 2024 2023 (in millions) Gross Accumulated Gross Accumulated Customer relationships $ 17.0 $ 8.2 $ 17.0 $ 7.1 Non-Compete agreements 3.1 2.3 3.1 1.9 Patents (1) 6.6 1.2 6.6 0.9 Other 0.3 0.3 0.3 0.2 Total $ 27.0 $ 12.0 $ 27.0 $ 10.1

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2024
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	The following tables provide: (a) the components of income tax expense in 2024, 2023, and 2022; (b) the reconciliation between the statutory federal income tax rate and the Company's effective income tax rate for 2024, 2023, and 2022; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2024 and 2023. For the Year Ended December 31, 2024 2023 2022 (in millions) Current Income Tax Expense Federal $ 3.7 $ 14.7 $ 8.3 State 2.7 5.5 1.9 Other (0.4) — — Total current income tax expense 6.0 20.2 10.2 Deferred Income Tax Expense (1) Property, plant and equipment 33.2 17.8 15.0 Amortization of FCG goodwill 7.8 — — Deferred gas costs (1.0) (7.7) 8.9 Pensions and other employee benefits (0.3) (1.0) 1.1 Net operating loss carryforwards (2.5) (0.4) — Other — (0.8) (1.4) Total deferred income tax expense 37.2 7.9 23.6 Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8 (1) Includes $7.9 million, less than $0.1 million, and $7.8 million of deferred state income taxes for the years 2024, 2023, and 2022, respectively.
Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates	For the Year Ended December 31, 2024 2023 2022 (in millions) Reconciliation of Effective Income Tax Rates Federal income tax expense (1) $ 34.0 $ 24.2 $ 26.0 State income taxes, net of federal benefit (2) 8.4 4.4 7.7 Other 0.8 (0.5) 0.1 Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8 Effective Income Tax Rate 26.71 % 24.35 % 27.34 % (1) Federal income taxes were calculated at 21 percent for 2024, 2023, and 2022. (2) 2023 includes the impact of the one-time benefit associated with the reduction in the Pennsylvania state tax rate. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations
Schedule of Accumulated Deferred Income Tax Assets and Liabilities	As of December 31, 2024 2023 (in millions) Deferred Income Taxes Deferred income tax liabilities: Property, plant and equipment $ 289.7 $ 252.1 Acquisition adjustment 5.2 5.6 Deferred gas costs 2.5 3.6 Natural gas conversion costs 4.6 4.8 Storm reserve liability 5.8 5.8 Intangible assets 6.4 — Other 8.4 9.7 Total deferred income tax liabilities 322.6 281.6 Deferred income tax assets: Pension and other employee benefits 5.1 5.0 Net operating loss carryforwards 1.1 1.8 Accrued expenses 4.0 3.3 Regulatory asset 6.0 4.1 Intangible assets — 2.8 Other 10.3 5.5 Total deferred income tax assets 26.5 22.5 Deferred Income Taxes $ 296.1 $ 259.1

Long-Term Debt (Tables)

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2024
Text Block [Abstract]
Outstanding Long-Term Debt	Our outstanding long-term debt is shown below: As of December 31, (in millions) 2024 2023 Uncollateralized senior notes: 5.68% notes, due June 2026 $ 5.8 $ 8.7 6.39% notes, due December 2026 100.0 100.0 6.44% notes, due December 2027 100.0 100.0 6.43% notes, due May 2028 2.8 3.5 3.73% notes, due December 2028 8.0 10.0 6.45% notes, due December 2028 100.0 100.0 3.88% notes, due May 2029 25.0 30.0 5.20% notes, due October 2029 100.0 — 6.62% notes, due December 2030 100.0 100.0 3.25% notes, due April 2032 52.5 59.5 6.71% notes, due December 2033 100.0 100.0 2.98% notes, due December 2034 70.0 70.0 3.00% notes, due July 2035 50.0 50.0 2.96% notes, due August 2035 40.0 40.0 2.49% notes, due January 2037 50.0 50.0 5.43% notes, due March 2038 80.0 80.0 3.48% notes, due May 2038 50.0 50.0 3.58% notes, due November 2038 50.0 50.0 6.73% notes, due December 2038 50.0 50.0 3.98% notes, due August 2039 100.0 100.0 2.95% notes, due March 2042 50.0 50.0 Equipment security note 2.46% note, due September 2031 6.7 7.6 Less: debt issuance costs (3.6) (3.7) Total long-term debt 1,287.2 1,205.6 Less: current maturities (25.5) (18.5) Total long-term debt, net of current maturities $ 1,261.7 $ 1,187.1
Line of Credit Facility [Line Items]
Schedule of Line of Credit Facilities [Table Text Block]

Leases Leases (Tables)

Leases Leases (Tables)	12 Months Ended
	Dec. 31, 2024
Leases [Abstract]
Lease, Cost [Table Text Block]	Year Ended December 31, (in millions) Classification 2024 2023 2022 Operating lease cost (1) Operations expense $ 3.0 $ 3.0 $ 2.9 (1) Includes short-term leases and variable lease costs, which are not material.
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, 2024 and 2023: (in millions) Balance sheet classification December 31, 2024 December 31, 2023 Assets Operating lease assets Operating lease right-of-use assets $ 10.5 $ 12.4 Liabilities Current Operating lease liabilities Other accrued liabilities $ 2.4 $ 2.4 Noncurrent Operating lease liabilities Operating lease - liabilities 8.7 10.6 Total lease liabilities $ 11.1 $ 13.0
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, 2024 and 2023: December 31, 2024 December 31, 2023 Weighted-average remaining lease term ( in years ) Operating leases 7.7 8.1 Weighted-average discount rate Operating leases 3.5 % 3.5 %
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, 2024, 2023 and 2022: Year Ended December 31, (in millions) 2024 2023 2022 Operating cash flows from operating leases $ 2.9 $ 2.9 $ 2.9
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, 2024 and for each of the next five years and thereafter: (in millions) Operating Leases (1) 2025 $ 2.6 2026 1.9 2027 1.6 2028 1.2 2029 1.1 Thereafter 4.1 Total lease payments 12.5 Less: Interest (1.4) Present value of lease liabilities $ 11.1 (1) Operating lease payments include $2.0 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, 2024
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, 2024 and 2023. 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 millions) As of December 31, 2022 $ (2.5) $ 1.1 $ — $ (1.4) Other comprehensive income (loss) before reclassifications (0.1) (1.4) 0.5 (1.0) Amounts reclassified from accumulated other comprehensive income (loss) — — (0.4) (0.4) Net current-period other comprehensive income (loss) (0.1) (1.4) 0.1 (1.4) As of December 31, 2023 (2.6) (0.3) 0.1 (2.8) Other comprehensive income (loss) before reclassifications 0.5 1.4 0.5 2.4 Amounts reclassified from accumulated other comprehensive income (loss) — (0.7) (0.6) (1.3) Net current-period other comprehensive income (loss) 0.5 0.7 (0.1) 1.1 As of December 31, 2024 $ (2.1) $ 0.4 $ — $ (1.7)
Reclassification out of Accumulated Other Comprehensive Income	D

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2024
Schedule of Assets by Investment Type	The following schedule summarizes the allocation of assets of the FPU Pension Plan, by investment type, at December 31, 2024, 2023 and 2022: FPU Pension Plan At December 31, 2024 2023 2022 Asset Category Equity securities 31 % 50 % 53 % Debt securities 67 49 38 Other 2 1 9 Total 100 % 100 % 100 %
Schedule of Asset Allocation Strategy	The following target allocation 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 Target Range (+/-) Domestic Equities (Large Cap, Mid Cap and Small Cap) 27 % 7 % Fixed Income (Inflation Bond and Taxable Fixed) 68 % 4 % Foreign Equities (Developed and Emerging Markets) 3 % 1 % Cash 2 % 2 %
Summary of Pension Plan Assets	At December 31, 2024 and 2023, the assets of the FPU Pension Plan were comprised of the following investments: As of December 31, Asset Category 2024 2023 (in millions) Mutual Funds - Equity securities U.S. Large Cap (1) $ 10.6 $ 15.4 U.S. Mid Cap (1) 3.2 4.3 U.S. Small Cap (1) — 2.5 International (2) 1.3 2.5 15.1 24.7 Mutual Funds - Debt securities Fixed income (3) 32.8 24.2 32.8 24.2 Mutual Funds - Other Guaranteed deposit (4) 1.2 0.6 1.2 0.6 Total Pension Plan Assets at fair value (5) $ 49.1 $ 49.5
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, 2024 and 2023 were not material.
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, 2024, there was $9.2 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 $7.1 million and $1.3 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $2.6 million recorded in accumulated other comprehensive income (loss) and $5.8 million recorded as a regulatory asset at December 31, 2024.
Schedule of Estimated Future Benefit Payments	The schedule below shows the estimated future benefit payments for the FPU Pension Plan. Estimated payments related to the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan are not material. FPU Pension Plan (1) (in millions) 2025 $ 3.6 2026 $ 3.7 2027 $ 3.6 2028 $ 3.7 2029 $ 3.6 Years 2030 through 2034 $ 17.6 (1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
Pension benefit
Schedule of Funded Status of Benefit Obligation and Plan Assets	The following schedules set forth the funded status at December 31, 2024 and 2023 and the net periodic cost (benefit) for the years ended December 31, 2024, 2023 and 2022 for the FPU Pension Plan and the Chesapeake SERP: FPU Chesapeake 2024 2023 2024 2023 (in millions) Change in benefit obligation: Benefit obligation — beginning of year $ 49.7 $ 49.9 $ 1.6 $ 1.7 Interest cost 2.4 2.5 0.1 0.1 Actuarial (gain) loss (2.0) 0.5 — — Benefits paid (4.6) (3.2) (0.2) (0.2) Benefit obligation — end of year 45.5 49.7 1.5 1.6 Change in plan assets: Fair value of plan assets — beginning of year 49.5 46.2 — — Actual return on plan assets 4.2 6.5 — — Employer contributions — — 0.2 0.2 Benefits paid (4.6) (3.2) (0.2) (0.2) Fair value of plan assets — end of year 49.1 49.5 — — Accrued pension funded status $ 3.6 $ (0.2) $ (1.5) $ (1.6) Assumptions: Discount rate 5.50 % 5.00 % 5.40 % 4.88 % Expected return on plan assets 6.00 % 6.00 % — % — %
Component of Net Periodic Pension Cost (Benefit)	FPU Chesapeake For the Years Ended December 31, 2024 2023 2022 2024 2023 2022 (in millions) Components of net periodic pension (benefit) cost: Interest cost $ 2.4 $ 2.5 $ 1.8 $ 0.1 $ 0.1 $ 0.1 Expected return on assets (2.9) (2.7) (3.4) — — — Amortization of actuarial loss 0.3 0.4 0.5 — — — Total periodic (benefit) cost $ (0.2) $ 0.2 $ (1.1) $ 0.1 $ 0.1 $ 0.1 Assumptions: Discount rate 5.00 % 5.25 % 2.75 % 4.88 % 5.00 % 2.50 % 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, 2024, 2023, and 2022. Amounts Not Yet Reflected in Periodic Benefit Cost

Share-Based Compensation Plans

Share-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2024
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, 2024, 2023 and 2022: For the Year Ended December 31, 2024 2023 2022 (in millions) Awards to key employees $ 7.5 $ 6.7 $ 5.5 Awards to non-employee directors 0.9 0.9 1.0 Total compensation expense 8.4 7.6 6.5 Less: tax benefit (2.2) (1.9) (1.7) Share-based compensation expense included in net income $ 6.2 $ 5.7 $ 4.8
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, 2024 2023 2022 (dollars in millions, shares in thousands) Shares withheld to satisfy tax obligations 14 20 22 Amounts remitted to tax authorities to satisfy obligations $ 1.5 $ 2.5 $ 2.8
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 and key employees: (in thousands, except per share data) Number of Weighted Average Outstanding — December 31, 2022 204 $ 103.17 Granted 81 126.06 Vested (68) 91.59 Expired (2) 94.64 Forfeited (2) 113.44 Outstanding — December 31, 2023 213 117.74 Granted 110 105.21 Vested (43) 103.95 Expired (27) 86.24 Forfeited — — Outstanding — December 31, 2024 253 $ 117.96

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, 2024
Summary of Effects of Federal Tax Reform on Regulated Businesses [Abstract]
Schedule of Regulatory Assets [Table Text Block]	At December 31, 2024 and 2023, 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, 2024 2023 (in millions) Regulatory Assets Under-recovered purchased fuel, electric, gas and conservation cost recovery (1) (2) $ 9.7 $ 13.7 Under-recovered GRIP revenue (3) 1.6 1.8 Deferred postretirement benefits (4) 7.7 10.8 Deferred conversion and development costs (1) 20.6 21.5 Acquisition adjustment (5) 29.6 31.9 Deferred storm costs (6) 11.1 19.4 Deferred rate case expenses - current 1.2 1.2 Other 19.8 15.6 Total Regulatory Assets $ 101.3 $ 115.9 Regulatory Liabilities Over-recovered purchased fuel and conservation cost recovery (1) $ 15.5 $ 12.3 Storm reserve (7) 2.1 1.9 Accrued asset removal cost (8) 77.9 86.5 Deferred income taxes due to rate change (9) 102.6 105.1 Other 2.0 3.2 Total Regulatory Liabilities $ 200.1 $ 209.0 (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) Includes amounts 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 gas distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution operations, 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) 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. (7) We have storm reserves in our Florida 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. (8) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies. (9) 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, 2024
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 actions have been initiated on the site's west parcel, and construction of the systems required to remediate the site are now complete with remediation activities underway at December 31, 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system start-up on the West Parcel, and continued operation and maintenance, are estimated to take between five and fifteen years of operation, maintenance and monitoring, and final site work for closeout of the property is estimated to be between $2.8 million and $5.2 million.

Other Commitments and Conting_2

Other Commitments and Contingencies Other Commitments and Contingencies (Tables)	12 Months Ended
	Dec. 31, 2024
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 2025 2026-2027 2028-2029 Beyond 2029 Total (in millions) Purchase Obligations $ 90.2 $ 103.6 $ 73.7 $ 119.4 $ 386.9

Summary of Significant Accoun_4

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($) mi	Dec. 31, 2023 USD ($)
Property, Plant and Equipment [Line Items]
Contributions in Aid of Construction	$ 5.9	$ 4.2
Public Utilities, Allowance for Funds Used During Construction, Description	$ 1.4
Number of Months to Establish ROU Asset and Liability	12 months
Property, plant and equipment
Total property, plant and equipment	$ 3,155.4	2,859.6
Less: Accumulated depreciation and amortization	(567.6)	(516.4)
Net property, plant and equipment	2,735.9	2,456.4
Construction Work in Progress	148.1	113.2
Jointly Owned Pipeline [Member]
Property, plant and equipment
Net property, plant and equipment	28.4
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	2.8	2.2
Natural Gas Distribution [Member] | Delmarva and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	1,679.3	1,486.8
Natural Gas Transmission [Member] | Delmarva Peninsula, Pennsylvania and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	819.5	788.2
Natural Gas Transmission [Member] | OHIO
Property, plant and equipment
Total property, plant and equipment	139.2	134.2
Electric distribution | Florida
Property, plant and equipment
Total property, plant and equipment	163	143.5
Propane Operations [Member] | Mid-Atlantic and Florida [Member]
Property, plant and equipment
Total property, plant and equipment	201.6	194.9
Electricity and Steam Generation [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	37.4	37.1
Mobile CNG Utility and Pipeline Solutions [Member] | Florida
Property, plant and equipment
Total property, plant and equipment	52.8	40.6
Other
Property, plant and equipment
Total property, plant and equipment	29.9	30.3
Other unregulated energy | Other [Member]
Property, plant and equipment
Total property, plant and equipment	$ 32.7	$ 4
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 Millions	12 Months Ended
	Dec. 31, 2024 USD ($) mi	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Summary Of Accounting Policies [Line Items]
Number of Months to Establish ROU Asset and Liability	12 months
Operating Lease, Liability	$ 11.1
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	$ 5.9	$ 4.2
Net property, plant and equipment	2,735.9	2,456.4
Accumulated depreciation	567.6	516.4
Depreciation and accretion reported in operations expenses	15.8	11.9	$ 11
Operating Lease, Right-of-Use Asset	10.5	12.4
Jointly Owned Pipeline [Member]
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	28.4
Accumulated Depreciation, Depletion and Amortization, Sale or Disposal of Property, Plant and Equipment	$ 2.8	$ 2.2
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
Maximum
Summary Of Accounting Policies [Line Items]
Operating Lease, Liability	$ 13

Summary of Significant Accoun_6

Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Natural gas distribution | Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	[1]	2.10%	2.50%	2.50%
Natural gas distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	[2],[3]	2.70%	2.20%	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%	2.40%
Natural gas transmission | OHIO
Property, Plant and Equipment [Line Items]
Average depreciation rates	[4]	2.30%	5%	5%
Electric distribution | Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates		2.40%	2.40%	2.80%
[1] (1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper. (2) Includes the impact of FCG beginning in 2024. (3) 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. (4)

Summary of Significant Accoun_7

Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	Dec. 31, 2024
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 Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Accounting Policies [Abstract]
Additions, Charged to Income	$ 2.1
Additions, Other Accounts	0.4
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	(1.9)
Accounts Receivable, Allowance for Credit Losses, Current, Disclosure	$ 3.3	$ 2.7

Earnings Per Share - Calculatio

Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, shares in Thousands, $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disclosure Earnings Per Share Calculations Of Basic And Diluted Earnings Per Share [Abstract]
Income (Loss) from Continuing Operations, Per Basic Share		$ 5.28	$ 4.75	$ 5.07
Calculation of Basic Earnings Per Share:
Net Income		$ 118.6	$ 87.2	$ 89.8
Weighted shares outstanding - Basic (in shares)	[1]	22,469	18,371	17,722
Basic Earnings Per Share (in usd per share)		$ 5.28	$ 4.75	$ 5.07
Calculation of Diluted Earnings Per Share:
Net Income		$ 118.6	$ 87.2	$ 89.8
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)	[1]	22,469	18,371	17,722
Share-based Compensation		62	64	82
Adjusted denominator — Diluted	[1]	22,531	18,435	17,804
Income (Loss) from Continuing Operations, Per Diluted Share		$ 5.26	$ 4.73	$ 5.04
Diluted (in usd per share)		$ 5.26	$ 4.73	$ 5.04
[1]) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.

Acquisitions - Additional Infor

Acquisitions - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
Number of Miles of Distribution Mains	150	160
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	787,200,000	$ 670,600,000	$ 680,700,000
Operating Income	228,200,000	150,800,000	142,900,000
Transaction-related expenses	4,000,000	10,400,000	0
Regulated Energy [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Revenues	583,400,000	473,600,000	429,400,000
Operating Income	196,200,000	126,200,000	$ 115,300,000
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	$ 922,800,000
Number of customers acquired through acquisition	123,000
Number of Miles of Distribution Mains	3,982
Number of Miles of Transmission Pipe	80
Business Combination, Integration Related Costs		10,400,000
Transaction-related expenses	$ 4,000,000	7,500,000
Property, Plant and Equipment, Acquired During Period	454,400,000
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	460,900,000
Florida City Gas | Regulated Energy [Member]
Business Combination, Separately Recognized Transactions [Line Items]
Revenues	140,300,000	12,100,000
Operating Income	13,500,000	$ (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

Acquisitions - Summary of Purch

Acquisitions - Summary of Purchase Price Allocation (Details) - Florida City Gas $ in Millions	Dec. 31, 2024 USD ($)
Business Combination, Separately Recognized Transactions [Line Items]
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory	$ 2.3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Receivables	14.1
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets	3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets, Other	2
Property, Plant and Equipment, Acquired During Period	454.4
Business Combination, Recognized Identifiable Assets Acquired, Goodwill, and Liabilities Assumed, Net	460.9
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets Regulatory assets - noncurrent	3.4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Other Noncurrent Assets	18.3
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Assets [Abstract]	958.4
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities	(20.9)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Liabilities	(14.1)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	(0.6)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Noncurrent Liabilities, Other	(35.6)
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net	$ 922.8

Revenue Recognition Contract Ba

Revenue Recognition Contract Balances (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Receivable from Customer in Brokerage	$ 66.2	$ 67.7
Contract with Customer, Asset, Net, Noncurrent	3	3.5
Contract with Customer, Liability, Current	1.2	1
Increase (Decrease) in Receivables	(1.5)
Increase (Decrease) in Other Noncurrent Assets	(0.5)
Increase (Decrease) in Other Current Liabilities	0.2
Contract with Customer, Asset, after Allowance for Credit Loss, Current	0	$ 0
Increase (Decrease) in Other Current Assets	$ 0

Revenue Recognition Disaggregat

Revenue Recognition Disaggregation of Revenue (Details) - USD ($)	12 Months Ended
	Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Revenues	$ 787,200,000		$ 670,600,000		$ 680,700,000
Revenue from Contract with Customer, Excluding Assessed Tax	787,200,000	[1]	670,600,000	[2]	680,700,000	[3]
Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(24,600,000)	[1]	(26,100,000)	[2]	(29,500,000)	[3]
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	200,000		200,000		300,000
Other [Member] | Segment Reporting, Reconciling Item, Corporate Nonsegment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	200,000		200,000		300,000
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	152,900,000		148,900,000		163,500,000
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(91,400,000)		(85,700,000)		(84,900,000)
Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(24,800,000)		(26,300,000)		(29,800,000)
Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues	583,400,000		473,600,000		429,400,000
Revenue from Contract with Customer, Excluding Assessed Tax	583,400,000	[1]	473,600,000	[2]	429,400,000	[3]
Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	532,000,000		421,000,000		376,900,000
Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	117,700,000		111,800,000		107,300,000
Regulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(66,300,000)		(59,200,000)		(54,800,000)
Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues	228,400,000		223,100,000		280,800,000
Revenue from Contract with Customer, Excluding Assessed Tax	228,400,000	[1]	223,100,000	[2]	280,800,000	[3]
Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	35,200,000		37,100,000		56,200,000
Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	17,600,000
Unregulated Energy | Eliminations [Member] | Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(300,000)		(200,000)		(300,000)
Other [Member] | Regulated Energy
Disaggregation of Revenue [Line Items]
Revenues	1,600,000		1,200,000		500,000
Other [Member] | Unregulated Energy
Disaggregation of Revenue [Line Items]
Revenues	400,000				400,000
Florida Natural Gas Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax					155,900,000
Delaware natural gas division [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	76,900,000		83,900,000		82,200,000
FPU Electric Distribution [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	92,600,000		99,500,000		81,700,000
Florida Public Utilities Company [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	170,300,000		168,400,000
Maryland Natural Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	24,600,000		28,100,000		26,600,000
Sandpiper [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	20,000,000		20,200,000		21,300,000
Aspire [Member] | Unregulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	35,200,000		37,100,000		56,200,000
Eastern Shore Gas Company [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	81,700,000		79,900,000		78,600,000
Peninsula Pipeline [Member] | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34,500,000		30,400,000		27,300,000
Eight Flags [Member] | Unregulated Energy | Energy Generation [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,000,000		19,200,000		25,300,000
Florida Propane [Member] | Unregulated Energy | Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	157,900,000		154,700,000		188,400,000
Marlin Gas Services [Member] | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	16,600,000		12,300,000		11,200,000
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(91,200,000)		(85,500,000)		(84,600,000)
Eliminations [Member] | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(24,600,000)		(26,100,000)		(29,500,000)
Eliminations [Member] | Regulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(66,300,000)		(59,200,000)		(54,800,000)
Eliminations [Member] | Unregulated Energy | Other And Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(300,000)		(200,000)		(300,000)
Aspire Energy Express | Regulated Energy | Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,500,000		1,500,000		1,400,000
Elkton Gas [Member] | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7,300,000		8,800,000		$ 9,200,000
Florida City Gas | Regulated Energy | Energy Distribution [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	140,300,000		$ 12,100,000	[4]
Other RNG | Unregulated Energy | Energy Services [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 1,000,000
[1]Total operating revenues for the year ended December 31, 2024, include other revenue (revenues from sources other than contracts with customers) of $1.6 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, 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[3] (1) Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

Revenue Recognition Remaining p

Revenue Recognition Remaining performance obligations (Details) $ in Millions	Dec. 31, 2024 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, 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, 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, Expected Timing of Satisfaction, Period	1 year
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	$ 37.5
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	$ 11.7
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	$ 0.7
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	$ 49.9
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	$ 34.5
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	$ 11.5
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	$ 0.4
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	$ 46.4
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	$ 30.8
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	$ 10
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	$ 0.4
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	$ 41.2
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	$ 28.6
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	$ 10
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	$ 0.4
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	$ 39
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	$ 26.3
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	$ 10
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	$ 36.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Eastern Shore and Peninsula Pipeline [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	130.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Natural gas distribution operations [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	33.6
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | 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, Start Date [Axis]: 2030-01-01 | Total for Segments [Member]
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, Remaining Performance Obligation, Amount	$ 164.2

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2024		Dec. 31, 2023		Dec. 31, 2022
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		$ 787,200,000		$ 670,600,000		$ 680,700,000
Other Cost of Sales	[1]	(24,600,000)		(26,000,000)		(29,400,000)
Unregulated Energy Cost of Sales		100,200,000		102,500,000		162,700,000
Cost of Sales		219,800,000		216,500,000		260,500,000
Intersegment Revenues (1)
Total intersegment revenues		787,200,000		670,600,000		680,700,000
Operating Income
Operating Income		228,200,000		150,800,000		142,900,000
Other income		2,000,000		1,400,000		5,100,000
Interest charges		68,400,000		36,900,000		24,400,000
Income taxes		43,200,000		28,100,000		33,800,000
Net Income		118,600,000		87,200,000		89,800,000
Depreciation and Amortization
Total depreciation and amortization		65,700,000		65,500,000		69,000,000
Segment Reporting, Other Segment Item, Amount	[2]	40,900,000		39,000,000		25,600,000
Payments to Acquire Productive Assets		355,800,000	[3]	1,138,000,000	[3]	140,800,000
Identifiable Assets
Total identifiable assets		3,577,000,000		3,304,700,000
RSAM Adjustment		15,500,000		5,100,000
Natural gas and electricity costs		144,200,000		140,000,000		127,200,000
Utilities Operating Expense, Maintenance and Operations		232,600,000		198,800,000		182,700,000
Total before income taxes		161,800,000		115,300,000		123,600,000
Florida City Gas
Identifiable Assets
Business Combination, Consideration Transferred		922,800,000
Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		583,400,000		473,600,000		429,400,000
Intersegment Revenues (1)
Total intersegment revenues		583,400,000		473,600,000		429,400,000
Operating Income
Operating Income		196,200,000		126,200,000		115,300,000
Depreciation and Amortization
Total depreciation and amortization		48,800,000		48,200,000		52,700,000
Segment Reporting, Other Segment Item, Amount	[2]	35,700,000		33,900,000		21,200,000
Payments to Acquire Productive Assets		320,200,000	[3]	1,095,900,000	[3]	97,600,000
Identifiable Assets
Utilities Operating Expense, Maintenance and Operations		158,500,000		125,300,000		113,000,000
Regulated Energy | Florida City Gas
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		140,300,000		12,100,000
Intersegment Revenues (1)
Total intersegment revenues		140,300,000		12,100,000
Operating Income
Operating Income		13,500,000		(3,300,000)
Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		228,400,000		223,100,000		280,800,000
Intersegment Revenues (1)
Total intersegment revenues		228,400,000		223,100,000		280,800,000
Operating Income
Operating Income		31,700,000		24,400,000		27,500,000
Depreciation and Amortization
Total depreciation and amortization		16,900,000		17,300,000		16,300,000
Segment Reporting, Other Segment Item, Amount	[2]	5,200,000		5,100,000		4,300,000
Payments to Acquire Productive Assets		33,900,000	[3]	40,300,000	[3]	40,800,000
Identifiable Assets
Utilities Operating Expense, Maintenance and Operations		74,400,000		73,800,000		70,000,000
Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]	(24,600,000)		(26,100,000)		(29,500,000)
Intersegment Revenues (1)
Total intersegment revenues	[1]	(24,600,000)		(26,100,000)		(29,500,000)
Depreciation and Amortization
Segment Reporting, Other Segment Item, Amount	[1],[2]					100,000
Payments to Acquire Productive Assets		1,700,000	[3]	1,800,000	[3]	2,400,000
Identifiable Assets
Utilities Operating Expense, Maintenance and Operations	[1]	(300,000)		(300,000)		(300,000)
Other and eliminations
Operating Income
Operating Income	[1]	300,000		200,000		100,000
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		787,400,000		670,800,000		681,000,000
Intersegment Revenues (1)
Total intersegment revenues		787,400,000		670,800,000		681,000,000
Operating Segments | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		578,300,000		471,600,000		422,900,000
Intersegment Revenues (1)
Total intersegment revenues		578,300,000		471,600,000		422,900,000
Identifiable Assets
Total identifiable assets		3,042,900,000		2,781,600,000
Operating Segments | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues		208,900,000		199,000,000		257,800,000
Intersegment Revenues (1)
Total intersegment revenues		208,900,000		199,000,000		257,800,000
Identifiable Assets
Total identifiable assets		486,400,000		477,400,000
Operating Segments | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1]	200,000		200,000		300,000
Intersegment Revenues (1)
Total intersegment revenues	[1]	200,000		200,000		300,000
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[4]	(200,000)		(200,000)		(300,000)
Intersegment Revenues (1)
Total intersegment revenues	[4]	(200,000)		(200,000)		(300,000)
Intersegment Eliminations | Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[4]	5,100,000		2,000,000		6,500,000
Intersegment Revenues (1)
Total intersegment revenues	[4]	5,100,000		2,000,000		6,500,000
Intersegment Eliminations | Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[4]	19,500,000		24,100,000		23,000,000
Intersegment Revenues (1)
Total intersegment revenues	[4]	19,500,000		24,100,000		23,000,000
Intersegment Eliminations | Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	[1],[4]	(24,800,000)		(26,300,000)		(29,800,000)
Intersegment Revenues (1)
Total intersegment revenues	[1],[4]	(24,800,000)		(26,300,000)		$ (29,800,000)
Other And Intersegment Eliminations
Identifiable Assets
Total identifiable assets		$ 47,700,000		$ 45,700,000
[1]Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.[2]Other segment items for each reportable segment include: Regulated - Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated - Other taxes[3] Regulated capital expenditures in 2023 include our acquisition of FCG for $922.8 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 Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$ 73	$ 30.5	$ 24.3
Cash paid for income taxes	$ 9.4	$ 21.9	$ (5)

Supplemental Cash Flow Disclo_4

Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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	$ 34	$ 33.3	$ 13.2
Non Cash Performance Incentive Plan DRP	1.2	0	0
Performance Incentive Plan	$ 4.9	$ 3.7	$ 2.9

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 0	$ 0	$ 400
Unrealized Gain (Loss) on Derivatives		1,800	600	$ 3,500
Notional Amount of Nonderivative Instruments	50,000	50,000
Derivative assets, at fair value	$ 600	$ 600	1,000
Interest Rate Swap Rate, High Range [Member]
Derivative [Line Items]
Fixed Swap Rate	3.97%	3.98%
Not Designated as Hedging Instrument [Member] | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 0	0	100
Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net		800	500	0
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Propane Swap Agreement
Derivative [Line Items]
Derivative assets, at fair value	$ 600	600	700
Derivatives designated as fair value hedges | Mark To Market Energy Assets | Interest Rate Swap [Member]
Derivative [Line Items]
Derivative assets, at fair value	100	100	300
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	0	0	1,100
Derivatives designated as fair value hedges | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	100	100	200
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months		500
Other Payables to Broker-Dealers and Clearing Organizations	$ 1,900	1,900	2,100
Cost of Sales | Derivatives designated as fair value hedges | Propane Swap Agreement
Derivative [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 1,300	$ (1,100)	$ 3,800

Derivative Instruments Fair Val

Derivative Instruments Fair Value Hedges (Details) - USD ($) $ in Millions	3 Months Ended	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative liabilities, at fair value	$ 0	$ 0	$ 0.4
Notional Amount of Nonderivative Instruments	$ 50	$ 50

Derivative Instruments - Fair V

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		$ 0.6	$ 1
Energy Marketing Contracts Assets, Total	[1]	0.7	1
Energy Marketing Contract Liabilities, Current		0	0.4
Energy Marketing Contract Liabilities, Total	[2]	0.1	1.3
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current		0	1.1
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current		0.1	0.2
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		0.6	0.7
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets | Interest Rate Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		$ 0.1	$ 0.3
[1] (1) (1)

Derivative Instruments - Effect

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments, Gain (Loss) [Line Items]
Energy Marketing Contract Liabilities, Current	$ 0	$ 0.4
Gain (Loss) on derivatives	1.8	0.6	$ 3.5
Derivatives not designated as hedging instruments | Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	0.1
Derivatives designated as fair value hedges | Propane Swap Agreement | Revenue
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(0.3)	1.2	(0.4)
Derivatives designated as fair value hedges | Propane Swap Agreement | Cost of Sales
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	1.3	(1.1)	3.8
Derivatives designated as fair value hedges | Interest Rate Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0.8	0.5	$ 0
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	0	1.1
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	$ 0.1	$ 0.2

Derivative Instruments Volume o

Derivative Instruments Volume of Derivative Activity (Details) gal in Millions	12 Months Ended
	Dec. 31, 2024 gal
Sharp Energy Inc [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	10.8

Fair Value of Financial Instr_3

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Billions	Dec. 31, 2024	Dec. 31, 2023
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Long-term debt including current maturities	$ 1.3
Fair value of long-term debt	$ 1.2	$ 1.2

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 Millions	Dec. 31, 2024	Dec. 31, 2023
Assets:
Investments	$ 14.4	$ 12.3
Fair Value, Inputs, Level 1 [Member]
Assets:
Assets, Fair Value Disclosure	13.3	10.8
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	0.7	1
Significant Other Observable Inputs (Level 2) | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0.1	1.3
Significant Unobservable Inputs (Level 3)
Assets:
Assets, Fair Value Disclosure	1.1	1.5
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	0	0
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	1.1	1.5
Other Investments [Member] | Fair Value, Inputs, Level 1 [Member]
Assets:
Investments	13.3	10.8
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	13.3	10.8
Investments [Member] | Significant Other Observable Inputs (Level 2)
Assets:
Investments	0	0
Investments [Member] | Significant Unobservable Inputs (Level 3)
Assets:
Investments	1.1	1.5
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	0.7	1
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	15.1	13.3
Fair Value | Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0.1	1.3
Fair Value | Equity Securities [Member]
Assets:
Investments	0	0
Fair Value | Guaranteed Income Fund [Member]
Assets:
Investments	1.1	1.5
Fair Value | Other Investments [Member]
Assets:
Investments	13.3	10.8
Fair Value | Investments [Member]
Assets:
Investments	14.4	12.3
Fair Value | Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$ 0.7	$ 1

Goodwill and Other Intangible_3

Goodwill and Other Intangible Assets - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2022	Dec. 31, 2023
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	$ 27		$ 27
Acquired finite-lived intangible assets, weighted average useful life	14 years
Goodwill	$ 507.7		508.2
Finite-Lived Intangible Assets, Amortization Expense, Next Twelve Months	1.9		1.8
Amortization of intangible assets		$ 1.5
Finite-Lived Intangible Assets, Amortization Expense, Year Four	1.5
Amortization of intangible assets, 2020	1.6
Amortization of intangible assets, 2022	1.3
Amortization of intangible assets, 2019	1.8
Regulated Energy
Goodwill [Line Items]
Goodwill	468.3		468.7
Unregulated Energy
Goodwill [Line Items]
Goodwill	39.4		39.5
Customer list
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	$ 17		17
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	$ 3.1		$ 3.1

Goodwill and Other Intangible_4

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		$ 27	$ 27
Finite-Lived Intangible Assets, Accumulated Amortization		12	10.1
Goodwill		507.7	508.2
Goodwill, Transfers	[1]	(0.5)
Regulated Energy
Goodwill [Line Items]
Goodwill		468.3	468.7
Goodwill, Transfers		(0.4)
Unregulated Energy
Goodwill [Line Items]
Goodwill		39.4	39.5
Goodwill, Transfers		(0.1)
Customer Lists [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		17	17
Finite-Lived Intangible Assets, Accumulated Amortization		8.2	7.1
Noncompete Agreements [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		3.1	3.1
Finite-Lived Intangible Assets, Accumulated Amortization		2.3	1.9
Patents [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross	[2]	6.6	6.6
Finite-Lived Intangible Assets, Accumulated Amortization	[2]	1.2	0.9
Other Intangible Assets [Member]
Goodwill [Line Items]
Finite-Lived Intangible Assets, Gross		0.3	0.3
Finite-Lived Intangible Assets, Accumulated Amortization		$ 0.3	$ 0.2
[1] (1) Adjustments to goodwill in our Regulated Energy segment attributable to purchase accounting adjustments related to our acquisition of FCG in November 2023. Adjustments in the Unregulated Energy segment relate to the sale of certain assets in our propane distribution business during 2024. 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 Millions		Dec. 31, 2024	Dec. 31, 2023
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		$ 27	$ 27
Accumulated Amortization		12	10.1
Customer Lists [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		17	17
Accumulated Amortization		8.2	7.1
Noncompete Agreements [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		3.1	3.1
Accumulated Amortization		2.3	1.9
Patents [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	[1]	6.6	6.6
Accumulated Amortization	[1]	1.2	0.9
Other Intangible Assets [Member]
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount		0.3	0.3
Accumulated Amortization		$ 0.3	$ 0.2
[1] (1)

Income Taxes - Additional Infor

Income Taxes - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Operating Loss Carryforwards [Line Items]
Deferred Tax Assets, Operating Loss Carryforwards	$ 1.1	$ 1.8
Deferred State and Local Income Tax Expense (Benefit)	$ 7.9	0.1	$ 7.8
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21%
Deferred Tax Assets, Operating Loss Carryforwards	$ 1.1	1.8
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	$ 99.3	$ 72.9

Income Taxes - Schedule of Inco

Income Taxes - Schedule of Income Tax Expense (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Current Income Tax Expense
Federal		$ 3.7	$ 14.7	$ 8.3
State		2.7	5.5	1.9
Other		(0.4)	0	0
Total current income tax expense		6	20.2	10.2
Deferred Income Tax Expense (1)
Total deferred income tax expense	[1]	37.2	7.9	23.6
Total Income Tax Expense		43.2	28.1	33.8
Deferred State and Local Income Tax Expense (Benefit)		7.9	0.1	7.8
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense		33.2	17.8	15
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense		(1)	(7.7)	8.9
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense		(0.3)	(1)	1.1
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense		(2.5)	(0.4)	0
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense		0	$ (0.8)	$ (1.4)
Florida City Gas Goodwill Amortization
Deferred Income Tax Expense (1)
Total deferred income tax expense		$ 7.8
[1] (1) Includes $7.9 million, less than $0.1 million, and $7.8 million of deferred state income taxes for the years 2024, 2023, and 2022, respectively.

Income Taxes - Summary of Recon

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
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]	$ 34	$ 24.2	$ 26
State income taxes, net of federal benefit (2)	[2]	8.4	4.4	7.7
Other		0.8	(0.5)	0.1
Total Income Tax Expense		$ 43.2	$ 28.1	$ 33.8
Effective Income Tax Rate		26.71%	24.35%	27.34%
[1]1) Federal income taxes were calculated at 21 percent for 2024, 2023, and 2022. (2) 2023 includes the impact of the one-time benefit associated with the reduction in the Pennsylvania state tax rate. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations

Income Taxes - Schedule of Accu

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disclosure Income Taxes Schedule Of Accumulated Deferred Income Tax Assets And Liabilities [Abstract]
Deferred State and Local Income Tax Expense (Benefit)	$ 7.9	$ 0.1	$ 7.8
Deferred income tax liabilities:
Property, plant and equipment	289.7	252.1
Acquisition adjustment	5.2	5.6
Deferred Income Tax Liability - Deferred Gas Costs	2.5	3.6
Deferred Income Tax Liability, Natural Gas Conversion Costs	4.6	4.8
Deferred Income Tax Liability, Storm Reserve	5.8	5.8
Deferred Income Tax Liability, Customer Based Intangibles	6.4
Other	8.4	9.7
Total deferred income tax liabilities	322.6	281.6
Deferred Tax Assets, Regulatory Assets and Liabilities	6	4.1
Deferred Income Tax Asset, Intangibles		2.8
Deferred income tax assets:
Pension and other employee benefits	5.1	5
Net operating loss carryforwards	1.1	1.8
Deferred Tax Assets, Tax Deferred Expense, Reserves and Accruals	4	3.3
Other	10.3	5.5
Total deferred income tax assets	26.5	22.5
Deferred Income Tax Liabilities, Net	$ 296.1	$ 259.1

Income Taxes - Schedule of In_2

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$ 7.9	$ 0.1	$ 7.8
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, 2024
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, 2024	Dec. 31, 2022
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 Millions	Dec. 31, 2024	Dec. 31, 2023
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.54%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 255
Long-term debt including current maturities	1,300
Long-term Debt and Lease Obligation	1,287.2	$ 1,205.6
Total long-term debt, net of current maturities	1,261.7	1,187.1
Unamortized Debt Issuance Expense	(3.6)	(3.7)
Long-term Debt and Lease Obligation, Current	$ (25.5)	(18.5)
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	$ 5.8	8.7
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	70
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	$ 2.8	3.5
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	$ 8	10
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	$ 25	30
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	$ 52.5	59.5
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	50
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	50
Uncollateralized Senior Note Due November Two Thousand Thirty Nine
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 100	100
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	50
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	40
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	50
Equipment Security Note
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.46%
Long-term debt including current maturities	$ 6.7	7.6
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	$ 50
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
Uncollateralized Senior Note Due October 2029
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.20%
Uncollateralized Senior Note Due October 2029 | Prudential [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 100

Long-Term Debt - Outstanding Lo

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term Debt	$ 1,300,000
Less: debt issuance costs	(3,600)	$ (3,700)
Long-term Debt and Lease Obligation	1,287,200	1,205,600
Less: current maturities	(25,500)	(18,500)
Total long-term debt, net of current maturities	$ 1,261,700	1,187,100
Debt Instrument, Interest Rate, Stated Percentage	6.54%
Proceeds from issuance of long-term debt	$ 99,500	627,000	$ 49,900
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
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	$ 5,800	8,700
Debt Instrument, Interest Rate, Stated Percentage	5.68%
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 2,800	3,500
Debt Instrument, Interest Rate, Stated Percentage	6.43%
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	$ 8,000	10,000
Debt Instrument, Interest Rate, Stated Percentage	3.73%
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	$ 25,000	30,000
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	$ 52,500	59,500
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	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	80,000
Debt Instrument, Interest Rate, Stated Percentage	5.43%
Uncollateralized Senior Note Due December 2026
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.39%
Uncollateralized Senior Note Due December 2027
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.44%
Uncollateralized Senior Note Due December 2028
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.45%
Uncollateralized Senior Note Due December 2030
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.62%
Uncollateralized Senior Note Due December 2033
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Debt Instrument, Interest Rate, Stated Percentage	6.71%
Uncollateralized Senior Note Due December 2038
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	50,000
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
Uncollateralized Senior Note Due July Two Thousand Thirty Five
Debt Instrument [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
Debt Instrument [Line Items]
Long-term Debt	$ 40,000	40,000
Debt Instrument, Interest Rate, Stated Percentage	2.96%
Uncollateralized Senior Note Due January Two Thousand Thirty Seven
Debt Instrument [Line Items]
Long-term Debt	$ 50,000	50,000
Debt Instrument, Interest Rate, Stated Percentage	2.49%
Uncollateralized Senior Note Due November Two Thousand Thirty Nine
Debt Instrument [Line Items]
Long-term Debt	$ 100,000	100,000
Equipment Security Note
Debt Instrument [Line Items]
Long-term Debt	$ 6,700	$ 7,600
Debt Instrument, Interest Rate, Stated Percentage	2.46%
Uncollateralized Senior Notes Due On October 2029
Debt Instrument [Line Items]
Long-term Debt	$ 100,000
Debt Instrument, Interest Rate, Stated Percentage	5.20%

Long-Term Debt - Outstanding _2

Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.54%
Proceeds from issuance of long-term debt	$ 99.5	$ 627	$ 49.9
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
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
Uncollateralized Senior Notes Due On October 2029
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.20%
Debt Instrument, Maturity Date	Oct. 31, 2029

Long-Term Debt Annual Maturitie

Long-Term Debt Annual Maturities (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long Term Debt Annual Maturities [Abstract]
Long-term Debt, Maturities, Repayments of Principal in Next Rolling Twelve Months	$ 25.5
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Two	134.6
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Three	131.7
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Four	136.7
Long-term Debt, Maturities, Repayments of Principal in Rolling Year Five	157
Long-term Debt, Maturities, Repayments of Principal in Rolling after Year Five	705.3
Total Future Repayments	$ 1,290.8

Long-Term Debt Shelf Arrangemen

Long-Term Debt Shelf Arrangements (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Line of Credit Facility [Line Items]
Long-term Debt	$ (1,300)
Debt Instrument, Interest Rate, Stated Percentage	6.54%
Debt Instrument, Unused Borrowing Capacity, Amount	$ 255
Uncollateralized Senior Note Due April Two Thousand Thirty Two [Member]
Line of Credit Facility [Line Items]
Long-term Debt	$ (52.5)	$ (59.5)
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)	(50)
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)	$ (40)
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)

Short-Term Borrowing - Addition

Short-Term Borrowing - Additional Information (Detail)	3 Months Ended	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Short-term Debt [Line Items]
Short-term borrowings	$ 196,500,000	$ 196,500,000	$ 179,900,000
Number Of Unsecured Bank Credit Facilities		3
Short-term Debt, Weighted Average Interest Rate, at Point in Time	5.06%	5.06%	5.83%
Long-term debt including current maturities	$ 1,300,000,000	$ 1,300,000,000
Line of Credit Facility, Remaining Borrowing Capacity	250,000,000	250,000,000
Notional Amount of Nonderivative Instruments	$ 50,000,000	$ 50,000,000
Debt Instrument, Interest Rate, Stated Percentage	6.54%	6.54%
Amount of letter of credit to our current primary insurance company		$ 6,900,000
Florida City Gas | Regulated Energy [Member]
Short-term Debt [Line Items]
Bridge Loan	$ 965,000,000	965,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Aggregate Borrowing Capacity	$ 450,000,000	$ 450,000,000
Interest Rate Swap Rate, High Range [Member]
Short-term Debt [Line Items]
Fixed Swap Rate	3.97%	3.98%
Revolving Line of Credit, Short-term
Short-term Debt [Line Items]
Aggregate Investment, Maximum	$ 250,000,000	$ 250,000,000
Interest Rate Credit Adjustment	10	10
Line of Credit Facility, Interest Rate Description		1.05 percent
Line of Credit Facility, Increase Request	$ 50,000,000	$ 50,000,000
Revolving Line of Credit, Long-term
Short-term Debt [Line Items]
Interest Rate Credit Adjustment	10	10
Revolving Line of Credit, 5 year
Short-term Debt [Line Items]
Aggregate Investment, Maximum	$ 200,000,000	$ 200,000,000
Line of Credit Facility, Interest Rate Description		1.25 percent
Line of Credit Facility, Increase Request	$ 100,000,000	$ 100,000,000

Short-Term Borrowing Short-Term

Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details)	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Short-term Debt [Line Items]
Line of Credit Facility, Remaining Borrowing Capacity	$ 250,000,000
Short-term borrowing	$ 196,500,000	$ 179,900,000
Number Of Unsecured Bank Credit Facilities	3
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$ 450,000,000

Leases Schedule of Future Minim

Leases Schedule of Future Minimum Rental Payment for Operating Leases (Details) $ in Millions	Dec. 31, 2024 USD ($)
Leases [Abstract]
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	$ 2.6	[1]
Lessee Future Operating Lease Option Payments	2
Lessee, Operating Lease, Liability, Payments, Due Year Two	1.9	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Three	1.6	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Four	1.2	[1]
Lessee, Operating Lease, Liability, Payments, Due Year Five	1.1	[1]
Lessee, Operating Lease, Liability, Payments, Due after Year Five	4.1	[1]
Lessee, Operating Lease, Liability, Payments, Due	12.5	[1]
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	(1.4)
Operating Lease, Liability	$ 11.1
[1] (1)

Leases Lease Cost Additional (D

Leases Lease Cost Additional (Details) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Leases [Abstract]
Operating Lease, Cost	[1]	$ 3	$ 3	$ 2.9
[1]1) Includes short-term leases and variable lease costs, which are not material

Leases Leases - Right of Use As

Leases Leases - Right of Use Asset and Lease Liability Balance Sheet Classification (Details) - USD ($) $ in Millions	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating Lease, Right-of-Use Asset	$ 10.5	$ 12.4
Operating Lease, Liability, Current	2.4	2.4
Operating Lease, Liability, Noncurrent	8.7	10.6
Total Operating and Finance Lease Liabilities	$ 11.1	$ 13

Leases Weighted Average Remaini

Leases Weighted Average Remaining Lease Term Additional Information (Details)	Dec. 31, 2024	Dec. 31, 2023
Leases [Abstract]
Operating Lease, Weighted Average Remaining Lease Term	7 years 8 months 12 days	8 years 1 month 6 days
Operating Lease, Weighted Average Discount Rate, Percent	3.50%	3.50%

Leases Lease Cash Flows Additio

Leases Lease Cash Flows Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Leases Cash Flows [Abstract]
Operating Lease, Payments	$ 2.9	$ 2.9	$ 2.9
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	$ (1.4)

Stockholders' Equity Additional

Stockholders' Equity Additional Details (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
		Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022	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		$ 10	$ 10
Issuance of stock for Dividend Reinvestment Plan		$ 72.5
Proceeds from Issuance or Sale of Equity		72.6	$ 366.4	$ 4.5
Equity Issued in Business Combination, Fair Value Disclosure		366.4
Florida City Gas
Accumulated Other Comprehensive Income (Loss) [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	[1],[2]		4,439,000
Common Stock [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Shares Issued, Price Per Share					$ 82.72
Maximum [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Proceeds from Stock Plans		$ 100	$ 75
[1] 2.0 million shares of preferred stock at $0.01 par value per share have been authorized. No preferred shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity.

Stockholders' Equity Accumulate

Stockholders' Equity Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	$ (2.8)	$ (1.4)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	2.4	(1)
Amounts reclassified from accumulated other comprehensive income/(loss)	(1.3)	(0.4)
Net current-period other comprehensive income/(loss)	1.1	(1.4)
Accumulated other comprehensive loss at end of period	(1.7)	(2.8)	$ (1.4)
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	(2.6)	(2.5)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0.5	(0.1)
Amounts reclassified from accumulated other comprehensive income/(loss)	0	0
Net current-period other comprehensive income/(loss)	0.5	(0.1)
Accumulated other comprehensive loss at end of period	(2.1)	(2.6)	(2.5)
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	(0.3)	1.1
Other Comprehensive Income (Loss), before Reclassifications, before Tax	1.4	(1.4)
Amounts reclassified from accumulated other comprehensive income/(loss)	(0.7)	0	(2.5)
Net current-period other comprehensive income/(loss)	0.7	(1.4)
Accumulated other comprehensive loss at end of period	0.4	(0.3)	1.1
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	0.1	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0.5	0.5
Amounts reclassified from accumulated other comprehensive income/(loss)	(0.6)	(0.4)
Net current-period other comprehensive income/(loss)	(0.1)	0.1
Accumulated other comprehensive loss at end of period	$ 0	$ 0.1	$ 0

Stockholders' Equity Accumula_2

Stockholders' Equity Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes	$ 161.8	$ 115.3	$ 123.6
Income tax benefit	(43.2)	(28.1)	(33.8)
Accumulated other comprehensive loss	(1.7)	(2.8)	(1.4)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	2.4	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(1.3)	(0.4)
Other Comprehensive Income (Loss), Net of Tax	1.1	(1.4)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	0.4	(0.3)	1.1
Other Comprehensive Income (Loss), before Reclassifications, before Tax	1.4	(1.4)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.7)	0	(2.5)
Other Comprehensive Income (Loss), Net of Tax	0.7	(1.4)
Accumulated (Gain) Loss from Interest Rate Swap Cash Flows Hedges
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	0	0.1	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0.5	0.5
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(0.6)	(0.4)
Other Comprehensive Income (Loss), Net of Tax	(0.1)	0.1
AOCI Changes For Defined Benefit Pension And Postretirement Plans [Member]
Amortization of defined benefit pension and postretirement plan items:
Accumulated other comprehensive loss	(2.1)	(2.6)	$ (2.5)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	0.5	(0.1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	0	0
Other Comprehensive Income (Loss), Net of Tax	$ 0.5	$ (0.1)

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) $ in Thousands		12 Months Ended
		Dec. 31, 2024 USD ($) shares	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		$ 9,200
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year		$ 300
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		$ 8,400	$ 6,600	$ 6,200
Shares reserved to fund future contributions | shares		788,495
Investments, Fair Value Disclosure		$ 14,400	12,300
Deferred compensation obligation		$ 9,800	9,100
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		$ 7,100
Expected contribution	[1]	$ 3,600
Medical
Defined Benefit Plan Disclosure [Line Items]
Health care inflation rate		5%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost		$ 1,300
Unfunded accumulated benefit obligation		$ (900)	(1,100)
Health care inflation rate		6%
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Unfunded accumulated benefit obligation		$ (300)	(400)
Health care inflation rate		5%
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		$ 14,400	12,300
Deferred Compensation Equity		$ 9,800	$ 9,100
[1]The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

Employee Benefit Plans - Schedu

Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Change in benefit obligation:
Interest cost	$ 0.1	$ 0.1	$ 0.1
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	49.7	49.9
Interest cost	2.4	2.5	1.8
Actuarial loss	(2)	0.5
Benefits paid	(4.6)	(3.2)
Benefit obligation - end of year	45.5	49.7	49.9
Change in plan assets:
Balance, beginning of year	49.5	46.2
Actual return on plan assets	4.2	6.5
Employer contributions	0	0
Benefits paid	(4.6)	(3.2)
Balance, end of year	49.1	49.5	$ 46.2
Reconciliation:
Accrued pension cost	$ 3.6	$ (0.2)
Assumptions:
Discount rate	5.50%	5%
Expected return on plan assets	6%	6%	6%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year	$ 1.6	$ 1.7
Interest cost	0.1	0.1
Actuarial loss	0	0
Benefits paid	(0.2)	(0.2)
Benefit obligation - end of year	1.5	1.6	$ 1.7
Change in plan assets:
Employer contributions	0.2	0.2
Benefits paid	(0.2)	(0.2)
Reconciliation:
Accrued pension cost	$ (1.5)	$ (1.6)
Assumptions:
Discount rate	5.40%	4.88%
Chesapeake Postretirement Plan
Reconciliation:
Funded status	$ (0.9)	$ (1.1)
FPU Medical Plan
Reconciliation:
Funded status	$ (0.3)	$ (0.4)

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, 2024	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 100	$ 100	$ 100
Accumulated other comprehensive loss pre-tax	(2,600)
Total unrecognized cost	(9,200)
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Interest cost	2,400	2,500	1,800
Post-merger regulatory asset	(5,800)
Total unrecognized cost	(7,100)
Defined Benefit Plan, Expected Return (Loss) on Plan Assets	2,900	2,700	3,400
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year	(300)	(400)	(500)
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ (200)	$ 200	$ (1,100)
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	5%	5.25%	2.75%
Expected return on plan assets	6%	6%	6%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Interest cost	$ 100	$ 100
Defined Benefit Plan, Expected Amortization of Gain (Loss), Next Fiscal Year	0	0	$ 0
Defined Benefit Plan, Net Periodic Benefit Cost (Credit)	$ 100	$ 100	$ 100
Defined Benefit Plan, Assumptions Used Calculating Net Periodic Benefit Cost, Discount Rate	4.88%	5%	2.50%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Total unrecognized cost	$ (1,300)

Employee Benefit Plans - Sche_3

Employee Benefit Plans - Schedule of Assets by Investment Type (Detail) - FPU Pension Plan	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Asset Category
Percentage of assets by investment type	100%	100%	100%
Investments in equity securities
Asset Category
Percentage of assets by investment type	31%	50%	53%
Debt securities
Asset Category
Percentage of assets by investment type	67%	49%	38%
Other
Asset Category
Percentage of assets by investment type	2%	1%	9%

Employee Benefit Plans - Sche_4

Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	Dec. 31, 2024
Minimum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	27%
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	68%
Minimum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	2%
Maximum | Domestic Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	7%
Maximum | Foreign Equities
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	1%
Maximum | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	4%
Maximum | Cash
Debt and Equity Securities, FV-NI [Line Items]
Defined Benefit Plan, Plan Assets, Target Allocation, Percentage	2%

Employee Benefit Plans - Summar

Employee Benefit Plans - Summary of Pension Plan Assets (Detail) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Investments in equity securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		$ 15.1
Investments in equity securities | Us Large Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[1]	10.6	$ 15.4
Investments in equity securities | Us Mid Cap Equity Securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[1]	3.2	4.3
Investments in equity securities | United States Equity Small Cap
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[1]	0	2.5
Investments in equity securities | International All Cap Equity
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[2]	1.3	2.5
Debt securities
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		32.8	24.2
Debt securities | Fixed Income
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[3]	32.8	24.2
Other
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets		1.2	0.6
Other | Guaranteed deposit
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[4]	1.2	$ 0.6
Fair Value Measured at Net Asset Value Per Share
Debt and Equity Securities, FV-NI [Line Items]
Total Pension Plan Assets	[5]	$ 49.1
[1] Includes funds that invest primarily in United States common stocks. Includes investment in a group annuity product issued by an insurance company. (5) 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) $ in Millions	12 Months Ended
	Dec. 31, 2024 USD ($)
Fair Value Measured at Net Asset Value Per Share
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	$ 49.1	[1]
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	15.1
Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	24.2
Balance, end of year	32.8
Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	0.6
Balance, end of year	1.2
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	15.4	[2]
Balance, end of year	10.6	[2]
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	4.3	[2]
Balance, end of year	3.2	[2]
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	2.5	[2]
Balance, end of year	0	[2]
International All Cap Equity | Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	2.5	[3]
Balance, end of year	1.3	[3]
Fixed Income Securities [Member] | Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	24.2	[4]
Balance, end of year	32.8	[4]
Guaranteed deposit | Other Investments [Member]
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	0.6	[5]
Balance, end of year	$ 1.2	[5]
[1] (5) 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 Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Components of net periodic cost:
Interest cost	$ 0.1	$ 0.1	$ 0.1
Chesapeake Postretirement Plan
Assumptions
Funded status	(0.9)	(1.1)
FPU Medical Plan
Assumptions
Funded status	(0.3)	(0.4)
Chesapeake SERP
Components of net periodic cost:
Interest cost	0.1	0.1
Actuarial (gain) loss	0	0	0
Net periodic postretirement cost	$ 0.1	$ 0.1	$ 0.1
Assumptions
Discount rate	4.88%	5%	2.50%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ 0	$ 0
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(0.2)	(0.2)
Defined Benefit Plan, Plan Assets, Contributions by Employer	0.2	0.2
Defined Benefit Plan, Plan Assets, Benefits Paid	(0.2)	(0.2)
Accrued pension cost	$ (1.5)	$ (1.6)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.40%	4.88%
FPU Pension Plan
Components of net periodic cost:
Interest cost	$ 2.4	$ 2.5	$ 1.8
Expected return on assets	(2.9)	(2.7)	(3.4)
Actuarial (gain) loss	0.3	0.4	0.5
Net periodic postretirement cost	$ (0.2)	$ 0.2	$ (1.1)
Assumptions
Discount rate	5%	5.25%	2.75%
Expected return on plan assets	6%	6%	6%
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)	$ (2)	$ 0.5
Defined Benefit Plan, Benefit Obligation, Benefits Paid	(4.6)	(3.2)
Defined Benefit Plan, Plan Assets, Amount	49.1	49.5	$ 46.2
Defined Benefit Plan, Plan Assets, Contributions by Employer	0	0
Defined Benefit Plan, Plan Assets, Benefits Paid	(4.6)	(3.2)
Accrued pension cost	$ 3.6	$ (0.2)
Defined Benefit Plan, Assumptions Used Calculating Benefit Obligation, Discount Rate	5.50%	5%

Employee Benefit Plans - Sche_5

Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) $ in Thousands	Dec. 31, 2024 USD ($)
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
Defined Benefit Plan, Expected Future Employer Contributions, Next Fiscal Year	$ 300
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2017	3,600	[1]
2018	3,700	[1]
2019	3,600	[1]
2020	3,700	[1]
2021	3,600	[1]
Years 2022 through 2026	$ 17,600	[1]
[1]The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	788,495
Number of Shares, Granted	995	765
Number of shares withheld	14,000	20,000	22,000
Share-based Payment Arrangement, Nonvested Award, Cost Not yet Recognized, Amount	$ 6.1
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	$ 110.53	$ 124.12
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	$ 103.95	$ 91.59
Number of Shares, Granted	110,000	81,000
Weighted average grant-date fair value of awards granted	$ 105.21	$ 126.06
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 30.8	$ 22.5	$ 24.1
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	524,579

Share-Based Compensation Plan_2

Share-Based Compensation Plans - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 8.4	$ 7.6	$ 6.5
Less: tax benefit	(2.2)	(1.9)	(1.7)
Share-Based Compensation amounts included in net income	6.2	5.7	4.8
SICP Awards to Non-employee directors
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	0.9	0.9	1
Share-based Payment Arrangement, Nonvested Award, Excluding Option, Cost Not yet Recognized, Amount	0.3
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	30.8	22.5	24.1
Total compensation expense	$ 7.5	$ 6.7	$ 5.5

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, 2024	Dec. 31, 2023
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	995	765
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	$ 110.53	$ 124.12
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, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	995	765
SICP Awards to Key Employees
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	213,000	204,000
Number of Shares, Granted	110,000	81,000
Number of Shares, Vested	(43,000)	(68,000)
Number of Shares, Outstanding Ending Balance	253,000	213,000
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	$ 117.74	$ 103.17
Weighted Average Grant Date Fair Value, Granted	105.21	126.06
Weighted Average Grant Date Fair Value, Vested	103.95	91.59
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$ 117.96	$ 117.74
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeited in Period	0	2,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Forfeitures, Weighted Average Grant Date Fair Value	$ 0	$ 113.44
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Aggregate Intrinsic Value, Nonvested	$ 30.8	$ 22.5	$ 24.1
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	$ 86.24	$ 94.64
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	27,000	2,000

Share-Based Compensation Plan_5

Share-Based Compensation Plans Shares Withheld and Tax Benefits Associated With Share-Based Payments (Details) - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2024	Dec. 31, 2023	Dec. 31, 2022
Share-Based Payment Arrangement [Abstract]
Share-based Payment Arrangement, Shares Withheld for Tax Withholding Obligation	14	20	22
Payment, Tax Withholding, Share-based Payment Arrangement	$ 1.5	$ 2.5	$ 2.8

Rates and Other Regulatory Ac_3

Rates and Other Regulatory Activities - Additional Information (Detail)		12 Months Ended
		Dec. 31, 2024 USD ($) Dekatherm	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2025 USD ($)
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 101,300,000	$ 115,900,000
Revenues		787,200,000	670,600,000	$ 680,700,000
RSAM		25,000,000
Regulatory Liabilities		200,100,000	209,000,000
Gas Utility Access and Replacement Directive Related Capital Expenditures		205,000,000
RSAM Adjustment		$ 15,500,000	$ 5,100,000
Number of Miles of Distribution Mains		150	160
Safety, Access, and Facility Enhancement Capital Expenditures		$ 205,000,000
Total Projected Capital Expenditures		255,000,000
Depreciation Study Impact		1,200,000
Safety, Access, and Facility Enhancement Additional Capital Expenditures		50,000,000
Storm reserve
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	2,100,000	$ 1,900,000
TCJA
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		84,600,000	85,800,000
Underrecovered purchased fuel costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[2],[3]	9,700,000	13,700,000
Maryland Natural Gas Distribution Businesses [Member]
Rates and Other Regulatory Activities [Line Items]
Permanent Rates		6,900,000
Maryland Natural Gas [Member]
Rates and Other Regulatory Activities [Line Items]
Annual Rate Case Recovery		$ 2,600,000
Rate Case ROE		11.50%
West Palm Beach Florida | Minimum [Member]
Rates and Other Regulatory Activities [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss		$ 2,800,000
West Palm Beach Florida | Maximum [Member]
Rates and Other Regulatory Activities [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss		5,200,000
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
Delaware natural gas division [Member]
Rates and Other Regulatory Activities [Line Items]
Permanent Rates		12,100,000
Annual Rate Case Recovery		$ 2,500,000
Rate Case ROE		11.50%
Florida Electric Distribution
Rates and Other Regulatory Activities [Line Items]
Permanent Rates		$ 12,600,000
Annual Rate Case Recovery		$ 1,800,000
Cost Recovery Storm Protection Plan					$ 20,400,000
Rate Case ROE		11.30%
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
Central Florida Reinforcement Projects: Plant City | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		5,000
Central Florida Reinforcement Projects: Lake Mattie | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		8,700
St. Cloud Project Amendment | Peninsula Pipeline Company
Rates and Other Regulatory Activities [Line Items]
Additional Firm Natural Gas Transportation Deliverability | Dekatherm		10,000
Regulated Energy [Member]
Rates and Other Regulatory Activities [Line Items]
Revenues		$ 583,400,000	$ 473,600,000	$ 429,400,000
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 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]Includes amounts 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]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.

Rates and Other Regulatory Ac_4

Rates and Other Regulatory Activities Regulatory Assets and Liabilities (Details) - USD ($) $ in Millions		Dec. 31, 2024	Dec. 31, 2023
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		$ 101.3	$ 115.9
Regulatory Liabilities		200.1	209
Overrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[1]	15.5	12.3
Storm Reserve [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[2]	2.1	1.9
Accrued asset removal cost
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[3]	77.9	86.5
Deferred Income Tax Due to Rate Change [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities	[4]	102.6	105.1
Other Regulatory Liability [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Liabilities		2	3.2
Underrecovered Gas And Fuel Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[1],[5]	9.7	13.7
Deferred Post Retirement Benefits [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[6]	7.7	10.8
Deferred Conversion And Development Costs [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[1]	20.6	21.5
Acquisition Adjustment [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[7]	29.6	31.9
Other Regulatory Asset [Member]
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		19.8	15.6
Deferred Storm Costs
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[8]	11.1	19.4
Under-recovered GRIP Revenues
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets	[9]	1.6	1.8
Deferred rate case expenses - current
Rates and Other Regulatory Activities [Line Items]
Regulatory Assets		1.2	$ 1.2
Florida Public Utilities Company [Member]
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		34.2
Indiantown Gas Company
Rates and Other Regulatory Activities [Line Items]
Business Acquisition Premium Paid		$ 0.7
[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]We have storm reserves in our Florida 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.[3] See Note 2, 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. 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.

Rates and Other Regulatory Ac_5

Rates and Other Regulatory Activities Federal Tax Reform Impact for Regulated Businesses (Details) - USD ($) $ in Thousands	Dec. 31, 2024	Dec. 31, 2023
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 200,100	$ 209,000
Eastern Shore Gas Company [Member]
Regulatory Liabilities Related to the Federal Tax Reform Impact [Line Items]
Regulatory Liabilities	$ 34,200

Environmental Commitments and_3

Environmental Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024 USD ($) site	Dec. 31, 2023 USD ($)
Environmental Commitments And Contingencies [Line Items]
Companys Exposure In Number Of Former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 2,200,000	$ 2,600,000
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, 2024 and 2023, we had approximately $3.2 million and $3.6 million, respectively, in environmental liabilities, related to the former MGP sites, and related regulatory assets of $0.3 million and $0.5 million at the respective balance sheet dates for future recovery of environmental costs from customers. Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware. The remaining clean-up costs are estimated to range from $0.3 million to $0.8 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 not material. 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 actions have been initiated on the site's west parcel, and construction of the systems required to remediate the site are now complete with remediation activities underway at December 31, 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system start-up on the West Parcel, and continued operation and maintenance, are estimated to take between five and fifteen years of operation, maintenance and monitoring, and final site work for closeout of the property is estimated to be between $2.8 million and $5.2 million.
Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	$ 300,000	500,000
West Palm Beach Florida | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	5,200,000
West Palm Beach Florida | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	2,800,000
Seaford | Maximum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	800,000
Seaford | Minimum
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Reasonably Possible Additional Loss	300,000
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	$ 3,200,000	$ 3,600,000

Other Commitments and Conting_3

Other Commitments and Contingencies - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2024 USD ($)	Dec. 31, 2023 USD ($)
Subsequent Event [Line Items]
Intra-Entity Agreement, Description	three years
Debt Service Coverage Ratio	1.25
Time to cure ratio	5 days
Number Of Years to Collect Benefits	20 years
Total purchase obligations for 2018	$ 90,200,000
Total purchase obligations for 2019 - 2020	103,600,000
Total purchase obligations for 2021 - 2022	73,700,000
Total purchase obligations thereafter	119,400,000
Aggregate guaranteed amount	38,000,000
Guarantor Obligations, Current Carrying Value	28,400,000
Amount of letter of credit to our current primary insurance company	6,900,000
Loss Contingencies [Line Items]
Environmental liabilities	$ 2,200,000	$ 2,600,000
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	$ 800,000
Specific Purpose
Subsequent Event [Line Items]
Guarantor Obligations, Current Carrying Value	5,200,000
Florida Public Utilities Company [Member]
Loss Contingencies [Line Items]
Environmental liabilities	$ 3,200,000	$ 3,600,000

Other Commitments and Conting_4

Other Commitments and Contingencies Purchase Obligations (Details) $ in Millions	Dec. 31, 2024 USD ($)
Long-term Purchase Commitment [Line Items]
Purchase Obligation, Due in Next Twelve Months	$ 90.2
Purchase Obligation, Due in Second and Third Year	103.6
Purchase Obligation, Due in Fourth and Fifth Year	73.7
Purchase Obligation, Due after Fifth Year	119.4
Purchase Obligation	$ 386.9

Schedule II - Valuation and Qua

Schedule II - Valuation and Qualifying Accounts (Detail) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$ 2,900	$ 3,100
Additions, Charged to Income	2,300	1,600
Additions, Other Accounts	200	200
Deductions	(2,700)	(2,000)
Balance at End of Year	$ 2,700	$ 2,900