Chesapeake Utilities (CPK) 10-Q 9 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document Document And Entity Information [Abstract]
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Trading Symbol	CPK
Entity Central Index Key	19,745
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		16,378,545

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues
Regulated Energy	$ 72,770	$ 69,703	$ 252,667	$ 238,353
Unregulated Energy and other	67,509	57,233	263,632	198,827
Total Operating Revenues	140,279	126,936	516,299	437,180
Operating Expenses
Regulated Energy cost of sales	21,501	22,794	89,741	87,206
Unregulated Energy and other cost of sales	55,660	44,066	204,880	145,325
Operations	32,821	29,274	101,804	91,778
Maintenance	3,208	2,737	10,419	9,370
Gain From A Settlement	0	0	(130)	(130)
Depreciation and amortization	10,633	9,362	30,176	27,267
Other taxes	4,420	4,071	13,719	12,572
Total Operating Expenses	128,243	112,304	450,609	373,388
Operating Income	12,036	14,632	65,690	63,792
Other expense, net	(11)	(154)	(204)	(1,855)
Interest charges	4,430	3,321	11,976	9,133
Income Before Income Taxes	7,595	11,157	53,510	52,804
Income taxes	2,057	4,324	14,731	20,781
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023
Weighted Average Common Shares Outstanding:
Basic (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Diluted (shares)	16,428,439	16,389,635	16,416,255	16,378,633
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.34	$ 0.42	$ 2.37	$ 1.96
Diluted (in dollars per share)	0.34	0.42	2.36	1.96
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.370	$ 0.325	$ 1.065	$ 0.955

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023
Other Comprehensive Income (Loss), net of tax:
Amortization of prior service cost, net of tax of $(5), $(8), $(16) and $(23), respectively	(14)	(11)	(42)	(35)
Net gain, net of tax of $38, $69, $118 and $212, respectively	100	102	317	297
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $257, $(15), $(70) and $(376), respectively	644	(104)	(83)	(643)
Total Other Comprehensive Income (Loss), net of tax	730	(13)	192	(381)
Comprehensive Income	$ 6,268	$ 6,820	$ 38,971	$ 31,642

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (5)	$ (8)	$ (16)	$ (23)
Net gain, tax	38	69	118	212
Unrealized (loss)/gain on commodity contract cash flow hedges, tax	$ 257	$ (15)	$ (70)	$ (376)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Regulated Energy		$ 1,242,840	$ 1,073,736
Unregulated Energy		220,721	210,682
Other businesses and eliminations		34,975	27,699
Total property, plant and equipment		1,498,536	1,312,117
Less: Accumulated depreciation and amortization		(295,449)	(270,599)
Plus: Construction work in progress		60,243	84,509
Net property, plant and equipment		1,263,330	1,126,027
Current Assets
Cash and cash equivalents		6,215	5,614
Trade and other receivables (less allowance for uncollectible accounts of $987 and $936, respectively)		52,660	77,223
Accrued revenue		12,352	22,279
Propane inventory, at average cost		7,444	8,324
Other inventory, at average cost		4,786	12,022
Regulatory assets		6,891	10,930
Storage gas prepayments		6,989	5,250
Income taxes receivable		8,725	14,778
Prepaid expenses		9,775	13,621
Derivative assets, at fair value		10,568	1,286
Other current assets		2,557	7,260
Total current assets		128,962	178,587
Deferred Charges and Other Assets
Goodwill		19,604	19,604
Other intangible assets, net		4,073	4,686
Investments, at fair value		7,951	6,756
Regulatory assets		76,343	75,575
Other assets		5,293	3,699
Total deferred charges and other assets		113,264	110,320
Total Assets		1,505,556	1,414,934
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)		7,971	7,955
Additional paid-in capital		255,509	253,470
Retained earnings		249,805	229,141
Accumulated other comprehensive loss		(4,987)	(4,272)
Deferred compensation obligation		3,818	3,395
Treasury stock		(3,818)	(3,395)
Total stockholders’ equity	[1]	508,298	486,294
Long-term debt, net of current maturities		241,597	197,395
Total capitalization		749,895	683,689
Current Liabilities
Less: current maturities		9,613	9,421
Short-term borrowing		268,293	250,969
Accounts payable		60,228	74,688
Customer deposits and refunds		34,887	34,751
Accrued interest		3,969	1,742
Dividends payable		6,060	5,312
Accrued compensation		10,396	13,112
Regulatory liabilities		9,099	6,485
Derivative liabilities, at fair value		9,774	6,247
Other accrued liabilities		14,819	10,273
Total current liabilities		427,138	413,000
Deferred Credits and Other Liabilities
Deferred income taxes		146,814	135,850
Regulatory liabilities		141,840	140,978
Environmental liabilities		7,941	8,263
Other pension and benefit costs		28,839	29,699
Deferred investment tax credits and other liabilities		3,089	3,455
Total deferred credits and other liabilities		328,523	318,245
Environmental and other commitments and contingencies (Notes 5 and 6)
Total Capitalization and Liabilities		$ 1,505,556	$ 1,414,934
[1]	Includes 96,622 and 90,961 shares at September 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 987	$ 936
Common stock, par value (in dollars per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized (shares)	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Issued	0	0

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income	$ 38,779	$ 32,023
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,176	27,267
Depreciation and accretion included in other costs	6,464	5,989
Deferred income taxes	11,047	29,520
Realized loss (gain) on commodity contracts/sale of assets/investments	4,015	(2,817)
Unrealized gain on investments/commodity contracts	(427)	(695)
Employee benefits and compensation	456	1,212
Share-based compensation	2,535	1,608
Other, net	(35)	(39)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	32,988	12,912
Propane inventory, storage gas and other inventory	6,379	(8,256)
Regulatory assets/liabilities, net	3,899	927
Prepaid expenses and other current assets	(1,533)	(2,860)
Accounts payable and other accrued liabilities	(9,590)	4,515
Income taxes receivable	6,053	(3,810)
Customer deposits and refunds	136	3,255
Accrued compensation	(2,804)	(2,030)
Other assets and liabilities, net	(542)	(349)
Net cash provided by operating activities	127,996	98,372
Investing Activities
Property, plant and equipment expenditures	(171,410)	(130,137)
Proceeds from sales of assets	565	601
Acquisitions, net of cash received		11,707
Environmental expenditures	(322)	(210)
Net cash used in investing activities	(171,167)	(141,453)
Financing Activities
Common stock dividends	(16,171)	(14,780)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(518)	254
Stock issuance	0	(10)
Tax Withholding payments related to net settled stock compensation	(1,210)	(692)
Change in cash overdrafts due to outstanding checks	712	(3,013)
Net borrowing (repayment) under line of credit agreements and short-term borrowing under the Revolver	16,612	(3,760)
Proceeds from long-term debt and long-term borrowing under the Revolver	74,901	69,800
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation	(30,554)	(5,510)
Net cash provided in financing activities	43,772	42,289
Net Increase (Decrease) in Cash and Cash Equivalents	601	(792)
Cash and Cash Equivalents—Beginning of Period	5,614	4,178
Cash and Cash Equivalents—End of Period	$ 6,215	$ 3,386

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - USD ($) $ in Thousands		Total		Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
Beginning Balances (shares) at Dec. 31, 2016	[1]			16,303,499
Beginning Balances at Dec. 31, 2016		$ 446,086	[1]	$ 7,935	$ 250,967	$ 192,062	$ (4,878)	$ 2,416	$ (2,416)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		58,124				58,124
Other comprehensive income (loss)		606					606
Dividend declared		(21,045)				(21,045)
Retirement savings plan and dividend reinvestment plan (shares)				10,771
Dividend reinvestment plan		735		$ 5	730
Stock issuance, shares				0
Stock issuance		(10)		$ 0	(10)
Share-based compensation (shares)	[2],[3]			30,172
Share-based compensation and tax benefit	[2],[3]	1,798		$ 15	1,783
Treasury stock activities		0						979	(979)
Ending Balances (shares) at Dec. 31, 2017	[1],[4]			16,344,442
Ending Balances at Dec. 31, 2017		$ 486,294	[4]	$ 7,955	253,470	229,141	(4,272)	3,395	(3,395)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		$ 38,779				38,779
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		(1,498)				(1,498)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(907)				907	(907)
Other comprehensive income (loss)		192					192
Dividend declared		(17,524)				(17,524)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan		(2)		$ 0	(2)
Stock issuance		0
Share-based compensation (shares)	[2],[3]			34,103
Share-based compensation and tax benefit	[2],[3]	2,057		$ 16	2,041
Treasury stock activities		0						423	(423)
Ending Balances (shares) at Sep. 30, 2018	[1],[4]			16,378,545
Ending Balances at Sep. 30, 2018		$ 508,298	[4]	$ 7,971	$ 255,509	$ 249,805	$ (4,987)	$ 3,818	$ (3,818)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
[1]	2,000,000 shares of preferred stock at $0.01 par value have been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.
[2]	Includes amounts for shares issued for directors’ compensation.
[3]	The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, 2018, and for the year ended December 31, 2017, we withheld 16,918 and 10,269 shares, respectively, for taxes.
[4]	Includes 96,622 and 90,961 shares at September 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

Condensed Consolidated Statem_6

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.370	$ 1.065	$ 1.2800
Deferred compensation plan held Rabbi Trust (shares)	96,622	96,622	90,961
Preferred Stock, Shares Authorized	2,000,000	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01
Proceeds from Issuance of Common Stock		$ 0	$ (10)
Shares issued under the performance incentive plan withheld for employee taxes (shares)		16,918	10,269

Summary of Accounting Policies

Summary of Accounting Policies	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Summary of Accounting Policies	Summary of Accounting Policies Basis of Presentation References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure. The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2017 . In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented. Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures. ARM, Chipola and Central Gas Asset Acquisitions In August 2017, PESCO acquired certain natural gas marketing assets of ARM. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity. We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million , based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million . We similarly revised the condensed consolidated balance sheet as of December 31, 2017 . These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid. In August 2017, Flo-gas acquired certain operating assets of Chipola, which provided propane distribution service to approximately 800 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida. In December 2017, Flo-gas acquired certain operating assets of Central Gas, which provides propane distribution service to approximately 325 residential and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida. The revenue and net income from these acquisitions, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018 , were not material. The acquisition accounting amounts recorded in conjunction with the ARM and Chipola acquisitions are now final although the amounts associated with the Central Gas acquisition are preliminary and subject to adjustment based on additional valuations performed during the measurement period. FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of adoption of the new revenue standard was immaterial to our net income. This standard requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration that the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 3, Revenue Recognition, for additional information. The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statements for the three and nine months ended September 30, 2018 and condensed consolidated balance sheet as of September 30, 2018 : Three Months Ended Nine Months Ended Income statement As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Regulated Energy operating revenues $ 72,770 $ 72,879 $ (109 ) $ 252,667 $ 253,659 $ (992 ) Regulated Energy cost of sales 21,501 21,512 (11 ) 89,741 90,454 (713 ) Depreciation and amortization 10,633 10,629 4 30,176 30,150 26 Income before income taxes 7,595 7,697 (102 ) 53,510 53,815 (305 ) Income taxes 2,057 2,086 (29 ) 14,731 14,819 (88 ) Net income 5,538 5,611 (73 ) 38,779 38,996 (217 ) As of September 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,352 $ 13,658 $ (1,306 ) Other assets $ 5,293 $ 5,702 $ (409 ) Capitalization Retained earnings $ 249,805 $ 251,520 $ (1,715 ) The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018 , associated with a long-term firm transmission contract with an industrial customer. Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included operating expenses. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations. Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments , which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows. Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations. Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income , which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information. Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities , to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12. Recent Accounting Standards Yet to be Adopted Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROU model that requires a lessee to recognize a ROU asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842 ; ASU No. 2018-10, Codification Improvements to Topic 842, Lease s; and ASU No. 2018-11, Targeted Improvements . ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019 and use the modified retrospective transition approach to all existing leases. The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the lease components to which they relate. The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 million to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases. Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment , which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting , which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations. Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement , which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations. Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans , which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Calculation of Earnings Per Sha

Calculation of Earnings Per Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Calculation of Earnings Per Share	Calculation of Earnings Per Share Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 Weighted average shares outstanding 16,378,545 16,344,442 16,366,608 16,334,210 Basic Earnings Per Share $ 0.34 $ 0.42 $ 2.37 $ 1.96 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,378,545 16,344,442 16,366,608 16,334,210 Effect of dilutive securities—Share-based compensation 49,894 45,193 49,647 44,423 Adjusted denominator—Diluted 16,428,439 16,389,635 16,416,255 16,378,633 Diluted Earnings Per Share $ 0.34 $ 0.42 $ 2.36 $ 1.96

Revenue Recognition (Notes)

Revenue Recognition (Notes)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue from Contract with Customer [Text Block]	3. Revenue Recognition We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays our revenue by major source based on product and service type for the three months ended September 30, 2018 : (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 6,282 $ — $ — $ 6,282 Delaware natural gas division 7,010 — — 7,010 FPU electric distribution 23,830 — — 23,830 FPU natural gas distribution 17,390 — — 17,390 Maryland natural gas division 2,463 — — 2,463 Sandpiper 3,561 — — 3,561 Total energy distribution 60,536 — — 60,536 Energy transmission Aspire Energy — 5,750 — 5,750 Eastern Shore 16,189 — — 16,189 Peninsula Pipeline 3,404 — — 3,404 Total energy transmission 19,593 5,750 — 25,343 Energy generation Eight Flags — 4,044 — 4,044 Propane delivery Delmarva Peninsula propane delivery — 13,172 — 13,172 Florida propane delivery — 4,166 — 4,166 Total propane delivery — 17,338 — 17,338 Energy services PESCO — 51,619 — 51,619 Other and eliminations Eliminations (7,359 ) (3,185 ) (8,668 ) (19,212 ) Other — 476 135 611 Total other and eliminations (7,359 ) (2,709 ) (8,533 ) (18,601 ) Total operating revenues (1) $ 72,770 $ 76,042 $ (8,533 ) $ 140,279 (1) Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 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. The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018 : (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 18,462 $ — $ — $ 18,462 Delaware natural gas division 50,963 — — 50,963 FPU electric distribution 60,933 — — 60,933 FPU natural gas distribution 58,885 — — 58,885 Maryland natural gas division 17,136 — — 17,136 Sandpiper 16,892 — — 16,892 Total energy distribution 223,271 — — 223,271 Energy transmission Aspire Energy — 23,682 — 23,682 Eastern Shore 46,289 — — 46,289 Peninsula Pipeline 8,469 — — 8,469 Total energy transmission 54,758 23,682 — 78,440 Energy generation Eight Flags — 12,652 — 12,652 Propane delivery Delmarva Peninsula propane delivery — 73,907 — 73,907 Florida propane delivery — 15,741 — 15,741 Total propane delivery — 89,648 — 89,648 Energy services PESCO — 181,976 — 181,976 Other and eliminations Eliminations (25,362 ) (11,679 ) (34,643 ) (71,684 ) Other — 1,475 521 1,996 Total other and eliminations (25,362 ) (10,204 ) (34,122 ) (69,688 ) Total operating revenues (1) $ 252,667 $ 297,754 $ (34,122 ) $ 516,299 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 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. 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 Rayonier, produces three sources of energy: electricity, steam and heated water. Rayonier purchases the steam (unfired and fired) and heated water, which is used in Rayonier’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 delivery 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 delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane 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. PESCO provides natural gas supply and asset management services to customers (including affiliates of Chesapeake Utilities) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on customer meter readings, on a monthly basis. 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. Contract balances The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2017 and September 30, 2018 were as follows: Trade Receivables Contract Assets (Non-current) Contract Liabilities (Current) (in thousands) Balance at 12/31/2017 $ 74,962 $ 1,270 $ 407 Balance at 9/30/2018 50,937 2,331 583 Increase (decrease) $ (24,025 ) $ 1,061 $ 176 Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement. At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. At September 30, 2018 and December 31, 2017 , we had a contract liability of $583,000 and $ 407,000 , respectively, which was included in other accrued liabilities in the condensed consolidated balance sheet, and which relates to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three and nine months ended September 30, 2018 , we recognized revenue of $ 48,000 and $384,000 , respectively. Practical expedients 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. For our long-term contracts, the revenue we recognize corresponds directly to the amount we have the right to invoice, which corresponds directly to our performance obligation. Our performance obligations under our long-term contracts are satisfied over time. As a practical expedient, we do not disclose information about remaining, or unsatisfied, performance obligations for these long-term contracts since the revenue recognized corresponds to the amount we have the right to invoice.

Rates and Other Regulatory Acti

Rates and Other Regulatory Activities	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Rates and Other Regulatory Activities	Rates and Other Regulatory Activities Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation, as separate entities, by the Florida PSC. Delaware Effect of the TCJA on customers: The Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also required utilities to propose procedures for changing rates to reflect those impacts on or before March 31, 2018. Our Delaware Division filed the requisite reports with the Delaware PSC on March 30, 2018. Subsequently, the Delaware Division filed an updated report reflecting the impact of the TCJA on May 31, 2018. If, after reviewing the required filing, the Delaware PSC determines to reduce our rates, it will open a new docket and establish a procedural schedule for conducting an evidentiary hearing regarding the impacts of the TCJA on our operations and existing rates. In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changes in the federal corporate income tax laws. In compliance with the Delaware PSC order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. We believe that the reduction in rates charged by our Delaware Division because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction will be offset by an equal reduction in income tax expense. Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018. CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition and subsequent conversion of propane to natural gas for certain CGS located within our territory. We requested the establishment of regulatory accounting treatment and valuation of the acquisition of certain CGS, approval of a methodology to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs. The Delaware PSC has not reached a decision as of the date of this filing. Maryland Division and Sandpiper Effect of the TCJA on customers: The Maryland PSC issued an order requiring all Maryland public utilities with rates explicitly grossed-up for income taxes to track the impacts of the TCJA, beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities, for all impacts of the TCJA; (b) file an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order and made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate. In April 2018, the Maryland PSC ordered both the Maryland Division and Sandpiper to implement reduced rates effective May 1, 2018, reflecting the impact of the TCJA. We implemented a one-time bill credit for the regulatory liability established for the refunds and issued the refunds to customers in July 2018. We submitted an informational filing to the Maryland PSC within the requisite 60 days of completing the refund payments. Additionally, if in the future the Maryland Division or Sandpiper identify any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible. We believe that the reduction in rates charged by our Maryland Division and Sandpiper because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense. Florida Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations filed a petition with the Florida PSC requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of our electrical grid. An interconnection project with FPL, which enables us to mitigate fuel costs for our electric customers, was included in the $15.2 million capital project expenditures. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. We have established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement. Electric Limited Proceeding-Storm Recovery: In February 2018, our Florida electric operations filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of storm reserve to its pre-storm level of $1.5 million . As a result of these hurricanes and tropical storms, our Florida electric operation’s storm reserve was depleted and is currently at a deficit of $779,000 . We have requested approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. This matter is scheduled for review at the Florida PSC’s meeting in the fourth quarter of 2018. Effect of the TCJA on customers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of the TCJA. Hearings for Florida’s electric utilities are tentatively scheduled for the first quarter of 2019, and hearings for the natural gas utilities are tentatively scheduled for the fourth quarter of 2018. In December 2017, the Florida PSC issued an order regarding the limited proceeding for our Florida electric operations, which prescribes the applicability, timing and treatment of the impacts of the TCJA, as discussed above. In June, our Florida natural gas operations filed petitions and testimony in support of the disposition of the impacts created by the TCJA. We believe that the reduction in rates charged by our Florida electric and natural gas operations because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense. In October 18, 2018, our electric distribution operation reached a settlement agreement with the Office of Public Counsel. This settlement agreement was filed for approval with the Florida PSC on October 19, 2018 and hearing in this action is expected to be held in December 2018. This agreement proposes that our electric distribution operation will flow benefit associated with the TCJA back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years. Eastern Shore 2017 Expansion Project: In May 2016, the FERC approved Eastern Shore's request to initiate the pre-filing review process for its 2017 Expansion Project. The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities. In October 2017, the FERC issued a CP authorizing Eastern Shore to construct the expansion facilities. The estimated cost of the 2017 Expansion Project is approximately $117.0 million . Eastern Shore submitted its Implementation Plan in October 2017, addressing the actions Eastern Shore will undertake to meet the environmental conditions set forth in the FERC's order. In December 2017, the TETLP interconnect upgrade was placed into service. In June 2018, the Fair Hill Loop in Chester County, Pennsylvania and Cecil County, Maryland was placed into service. With the exception of some minor facilities, the remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the fourth quarter of 2018. 2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore based its proposed rates on the mainline cost of service of approximately $60.0 million resulting in an overall requested annual revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. In March 2017, the FERC issued an order suspending the tariff rates for the usual five -month period. In August 2017, Eastern Shore implemented new rates, subject to refund, based on the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates pending FERC approval of the settlement and refunds to customers according to the terms of the settlement agreement. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. Exclusive of the TCJA impact, base rates would have increased, on an annual basis, by approximately $9.8 million . Effect of the TCJA on customers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the change in its federal corporate income tax rate. These adjusted base rates became effective April 1, 2018 and will generate approximately $6.6 million in incremental margin, on an annual basis. Any excess accumulated deferred income tax balances will flow back to customers over the period determined in the next rate case, absent any transition rule included in the TCJA or other statutes or rules that would govern the flow-back period. In April 2018, Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates. The refund to customers also reflected the difference in rates due to the impact of the TCJA. In March 2018, the FERC issued a NOPR that proposed a process to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the TCJA and changes to the FERC’s income tax allowance policies following the United Airlines, Inc. v. FERC decision. The NOPR proposed requiring interstate natural gas pipelines to provide an informational filing to allow the FERC to evaluate the impact of the TCJA on the pipelines’ revenue requirement. In April 2018, Eastern Shore filed comments in this proceeding requesting confirmation that Eastern Shore is not required to provide an informational filing because it has already implemented lower rates in accordance with the settlement agreement in its 2017 rate case approved by the FERC. In July 2018, the FERC issued a final rule, which largely adopted the process proposed in the NOPR, requiring all interstate natural gas companies to file an informational filing for the purpose of evaluating the impact of the TCJA and the United Airlines, Inc. v. FERC decision on interstate natural gas pipelines’ revenue requirements. The final rule provides that an individual pipeline has the option to request a waiver if the pre-March 2018 settlement justifies not adjusting its rates at this time. In September 2018, Eastern Shore requested that the FERC grant it a waiver of the requirement. In October 2018, the FERC issued an order granting the waiver. Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application for the Del-Mar Energy Pathway project with the FERC. The proposed project would provide an additional 14,300 Dts/d of capacity to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware, 13 miles of new mainline extension in Sussex County, Delaware and Somerset County, Maryland as well as new pressure control and delivery stations in these counties. The benefits of this project include (i) further natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware and (ii) first extension of Eastern Shore’s pipeline system into Somerset County, Maryland.

Environmental Commitments and C

Environmental Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Environmental Remediation Obligations [Abstract]
Environmental Commitments and Contingencies	Environmental Commitments and Contingencies We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances. MGP Sites We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. Those sites are located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We are also in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland. As of September 30, 2018 , we had approximately $9.4 million in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. As of September 30, 2018 we have recovered approximately $11.4 million , leaving approximately $2.6 million in regulatory assets for future recovery of environmental costs from FPU’s customers. Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates. The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites: Jurisdiction MGP Site Status Cost to Clean up Recovery through Rates Florida West Palm Beach Remedial actions approved by the FDEP have been implemented on the east parcel of the site. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018. Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. Yes Florida Sanford In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site. FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000. Yes Florida Winter Haven Remediation is ongoing. Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site. Yes Delaware Seaford Proposed plan for implementation approved by the DNREC in July 2017. Site assessment is ongoing. Between $273,000 and $465,000. Yes Maryland Cambridge Currently in discussions with the MDE. Unable to estimate. N/A

Other Commitments and Contingen

Other Commitments and Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Other Commitments and Contingencies	Other Commitments and Contingencies Natural Gas, Electric and Propane Supply We have entered into contractual commitments, with various expiration dates, to purchase natural gas, electricity and propane from various suppliers. In 2017, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three -year term, expiring on March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six -year term ending in May 2019. Sandpiper's current annual commitment is approximately 1.8 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices. Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six -year term ending in May 2019. Sharp's current annual commitment is approximately 1.8 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement. Chesapeake Utilities' Florida Division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. 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. FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent ). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2018 , FPU was in compliance with all of the requirements of its fuel supply contracts. Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20 -year power purchase agreement for distribution to our electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20 -year contract, to Rayonier, the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline. Corporate Guarantees We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 2018 was approximately $73.9 million , with the guarantees expiring on various dates through September 2019 . Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14 , Long-Term Debt , for further details). Letters of Credit As of September 30, 2018 , we have issued letters of credit totaling approximately $5.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019 . There have been no draws on these letters of credit as of September 30, 2018 . We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that the letters of credit will be renewed to the extent necessary in the future. Other We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information	Segment Information 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 Chief Executive Officer) in order to make decisions about resources and to assess performance. Our operations 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, propane delivery, and other energy services (propane distribution, the operations of our Eight Flags' CHP plant, as well as natural gas marketing, gathering, processing, transportation and supply). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary, that wound down its operations shortly after the first quarter of 2017. 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. The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 69,697 $ 67,257 $ 243,382 $ 232,519 Unregulated Energy segment and other businesses 70,582 59,679 272,917 204,661 Total operating revenues, unaffiliated customers $ 140,279 $ 126,936 $ 516,299 $ 437,180 Intersegment Revenues (1) Regulated Energy segment $ 3,073 $ 2,446 $ 9,285 $ 5,834 Unregulated Energy segment 5,460 5,009 24,837 15,801 Other businesses 135 194 521 581 Total intersegment revenues $ 8,668 $ 7,649 $ 34,643 $ 22,216 Operating Income Regulated Energy segment $ 15,915 $ 15,523 $ 56,930 $ 53,004 Unregulated Energy segment (3,933 ) (951 ) 10,241 10,626 Other businesses and eliminations 54 60 (1,481 ) 162 Total operating income 12,036 14,632 65,690 63,792 Other expense, net (11 ) (154 ) (204 ) (1,855 ) Interest charges 4,430 3,321 11,976 9,133 Income before Income Taxes 7,595 11,157 53,510 52,804 Income taxes 2,057 4,324 14,731 20,781 Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2018 December 31, 2017 Identifiable Assets Regulated Energy segment $ 1,223,537 $ 1,121,673 Unregulated Energy segment 244,390 259,041 Other businesses and eliminations 37,629 34,220 Total identifiable assets $ 1,505,556 $ 1,414,934 Our operations are entirely domestic.

Stockholder's Equity - Accumula

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Stockholder's Equity Preferred Stock We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of September 30, 2018 and December 31, 2017. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine. Accumulated Other Comprehensive Loss Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated other comprehensive loss. During the first quarter of 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flow hedges. The following tables present the changes in the balance of accumulated other comprehensive (loss)/income as of September 30, 2018 and 2017 . All amounts except the stranded tax reclassification are presented net of tax. Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2017 $ (4,743 ) $ 471 $ (4,272 ) Other comprehensive loss before reclassifications — (1,126 ) (1,126 ) Amounts reclassified from accumulated other comprehensive income 275 1,043 1,318 Net current-period other comprehensive income/(loss) 275 (83 ) 192 Stranded tax reclassification to retained earnings (1,022 ) 115 (907 ) As of September 30, 2018 $ (5,490 ) $ 503 $ (4,987 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2016 $ (5,360 ) $ 482 $ (4,878 ) Other comprehensive (loss)/income before reclassifications (9 ) 322 313 Amounts reclassified from accumulated other comprehensive income/(loss) 271 (965 ) (694 ) Net prior-period other comprehensive income/(loss) 262 (643 ) (381 ) As of September 30, 2017 $ (5,098 ) $ (161 ) $ (5,259 ) The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2018 and 2017 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 19 $ 58 $ 58 Net loss (1) (138 ) (171 ) (435 ) (509 ) Total before income taxes (119 ) (152 ) (377 ) (451 ) Income tax benefit 33 61 102 180 Net of tax $ (86 ) $ (91 ) $ (275 ) $ (271 ) Gains and losses on commodity contracts cash flow hedges: Propane swap agreements (2) $ (276 ) $ 198 $ (921 ) $ 663 Natural gas swaps (2) 123 1 (358 ) 1 Natural gas futures (2) (308 ) (852 ) (171 ) 929 Total before income taxes (461 ) (653 ) (1,450 ) 1,593 Income tax benefit (expense) 129 248 407 (628 ) Net of tax (332 ) (405 ) (1,043 ) 965 Total reclassifications for the period $ (418 ) $ (496 ) $ (1,318 ) $ 694 (1) These amounts are included in the computation of net periodic costs (benefits). See Note 9 , Employee Benefit Plans , for additional details. (2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments , for additional details. Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements, call options and natural gas futures contracts are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

Employee Benefit Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Employee Benefit Plans	Employee Benefit Plans Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2018 and 2017 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 94 $ 103 $ 570 $ 623 $ 21 $ 22 $ 10 $ 11 $ 12 $ 13 Expected return on plan assets (131 ) (127 ) (770 ) (699 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (19 ) — — Amortization of net loss 82 107 86 131 25 22 15 17 — — Net periodic cost (benefit) (1) 45 83 (114 ) 55 46 44 6 9 12 13 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 45 $ 83 $ 77 $ 246 $ 46 $ 44 $ 6 $ 9 $ 14 $ 15 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 288 $ 309 $ 1,754 $ 1,870 $ 63 $ 66 $ 29 $ 31 $ 38 $ 38 Expected return on plan assets (406 ) (381 ) (2,318 ) (2,098 ) — — — — — — Amortization of prior service credit — — — — — — (58 ) (58 ) — — Amortization of net loss 258 319 302 392 75 65 45 50 — — Net periodic cost (benefit) (1) 140 247 (262 ) 164 138 131 16 23 38 38 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 140 $ 247 $ 309 $ 735 $ 138 $ 131 $ 16 $ 23 $ 44 $ 44 (1) As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income. We expect to record pension and postretirement benefit costs of approximately $856,000 for 2018. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $749,000 and approximately $1.3 million at September 30, 2018 and December 31, 2017 , respectively. Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss. The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended September 30, 2018 and 2017 : For the Three Months Ended September 30, 2018 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 82 86 25 15 — 208 Total recognized in net periodic benefit cost 82 86 25 (4 ) — 189 Recognized from accumulated other comprehensive loss (1) 82 16 25 (4 ) — 119 Recognized from regulatory asset — 70 — — — 70 Total $ 82 $ 86 $ 25 $ (4 ) $ — $ 189 For the Three Months Ended September 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 107 131 22 17 — 277 Total recognized in net periodic benefit cost 107 131 22 (2 ) — 258 Recognized from accumulated other comprehensive loss (1) 107 25 22 (2 ) — 152 Recognized from regulatory asset — 106 — — — 106 Total $ 107 $ 131 $ 22 $ (2 ) $ — $ 258 For the Nine Months Ended September 30, 2018 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 258 302 75 45 — 680 Total recognized in net periodic benefit cost 258 302 75 (13 ) — 622 Recognized from accumulated other comprehensive loss (1) 258 57 75 (13 ) — 377 Recognized from regulatory asset — 245 — — — 245 Total $ 258 $ 302 $ 75 $ (13 ) $ — $ 622 For the Nine Months Ended September 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 319 392 65 50 — 826 Total recognized in net periodic benefit cost 319 392 65 (8 ) — 768 Recognized from accumulated other comprehensive loss (1) 319 75 65 (8 ) — 451 Recognized from regulatory asset — 317 — — — 317 Total $ 319 $ 392 $ 65 $ (8 ) $ — $ 768 (1) See Note 8 , Stockholder's Equity . During the three and nine months ended September 30, 2018 , we contributed approximately $235,000 and $433,000 , respectively, to the Chesapeake Pension Plan and approximately $123,000 and $971,000 , respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $359,000 and approximately $1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2018 , which represents the minimum annual contribution payments required. The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and nine months ended September 30, 2018 , were approximately $38,000 and $113,000 , respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in 2018 . Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for nine months ended September 30, 2018 , were approximately $15,000 and no cash benefits were paid for medical claims during the third quarter of 2018. We estimate that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2018 . Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2018 , were approximately $9,000 and $33,000 , respectively. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018 .

Investments

Investments	9 Months Ended
	Sep. 30, 2018
Investments, Debt and Equity Securities [Abstract]
Investments	Investments The investment balances at September 30, 2018 and December 31, 2017 , consisted of the following: (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 7,929 $ 6,734 Investments in equity securities 22 22 Total $ 7,951 6,756 We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2018 and 2017 , we recorded a net unrealized gain of approximately $ 313,000 and $261,000 , respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2018 and 2017 , we recorded a net unrealized gain of approximately $426,000 and $694,000 , respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

Share-Based Compensation

Share-Based Compensation	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Share-Based Compensation	Share-Based Compensation Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period. The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months ended September 30, 2018 and 2017 : Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Awards to non-employee directors $ 135 $ 134 $ 404 $ 406 Awards to key employees 153 662 2,728 1,202 Total compensation expense 288 796 3,132 1,608 Less: tax benefit (79 ) (320 ) (858 ) (647 ) Share-based compensation amounts included in net income $ 209 $ 476 $ 2,274 $ 961 Non-employee Directors Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a one -year service period. In May 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for service as a director through the 2019 Annual Meeting of Stockholders. The table below presents the summary of the stock activity for awards to non-employee directors for the nine months ended September 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 — $ — Granted 7,128 $ 75.70 Vested (7,128 ) $ 75.70 Outstanding—September 30, 2018 — $ — At September 30, 2018 , there was approximately $315,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2019. See Note 1, Summary of Accounting Policies , for additional information regarding ASU 2018-07 and its impact on the accounting for non-employee share-based payments. Key Employees The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 132,642 $ 59.31 Granted 49,494 $ 67.76 Vested (29,786 ) $ 47.39 Vested - Accelerated pursuant to separation agreement (1) (16,676 ) $ 75.78 Expired (3,933 ) $ 49.66 Outstanding—September 30, 2018 131,741 $ 67.43 (1) Includes 2,569 shares that were forfeited. In February 2018, our Board of Directors granted awards of 49,494 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three -year service period ending December 31, 2020. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted. In March 2018, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that we awarded for the performance period ended December 31, 2017, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 10,436 shares, based on the value of the shares on their award date, determined by the average of the high and low prices of our common stock. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $719,000 . In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock previously granted to the executive officer under the SICP, immediately vested at the time of separation, and an additional 2,569 shares were forfeited. We settled the awards that vested in cash and recognized $1.1 million as share-based compensation expense. At September 30, 2018 , the aggregate intrinsic value of the SICP awards granted to key employees was approximately $11.1 million . At September 30, 2018 , there was approximately $2.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense from 2018 through 2020. Stock Options We did not have any stock options outstanding at September 30, 2018 or 2017 , nor were any stock options issued during these periods.

Derivative Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. 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. Aspire Energy 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 and natural gas marketing 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. As of September 30, 2018 , our natural gas and electric distribution operations did not have any outstanding derivative contracts. We adopted ASU 2017-12 as of July 1, 2018. See Note 1, Summary of Accounting Policies, under the heading "FASB Statements and Other Authoritative Pronouncements " for additional details. Volume of Derivative Activity As of September 30, 2018 , the volume of our open commodity derivative contracts were as follows: Business unit Commodity Quantity hedged (in millions) Designation Longest Expiration date of hedge PESCO Natural gas (Dts) 22.1 Cash flows hedges March 2022 PESCO Natural gas (Dts) 1.1 Not designated January 2020 Sharp Propane (gallons) 4.4 Cash flows hedges June 2021 Sharp Propane (gallons) 0.3 Fair value hedges March 2019 PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $570,000 from accumulated other comprehensive loss to earnings during the next 12-month period ending September 30, 2019. Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in August 2018 through June 2021) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $392,000 from accumulated other comprehensive income to earnings during the next 12-month period ending September 30, 2019. Sharp paid a total of $28,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated volumes of propane for its propane price cap program during the upcoming heating season. We will exercise the put option if propane prices fall below specified strike price(s) per gallon in December 2018 to March 2019. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put option as a fair value hedge. The premium paid by Sharp is amortized and recorded in earnings over the duration of the put option and recorded in the same line item as the hedged item. The change in the fair value of the put option is recorded in derivative assets and or derivative liability and later recognized in cost of sales. Balance Sheet Offsetting PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payable on a gross and net basis at September 30, 2018 and December 31, 2017 : At September 30, 2018 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 7,042 $ 1,158 $ 5,884 Accounts payable $ 11,264 $ 1,158 $ 10,106 At December 31, 2017 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 8,283 $ 2,391 $ 5,892 Accounts payable $ 16,643 $ 2,391 $ 14,252 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 MTM relative to maintenance margin requirements. We maintain separate broker margin accounts for Sharp and PESCO. The balances are as follows: (in thousands) Balance Sheet Location At September 30, 2018 At December 31, 2017 Sharp Other Current Liabilities $ 18 $ — PESCO Other Current Assets $ 2,060 $ 6,300 Financial Statements Presentation The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Propane swap agreements Derivative assets, at fair value $ — $ 13 Natural gas futures contracts Derivative assets, at fair value 1,841 — Derivatives designated as fair value hedges Propane put options Derivative assets, at fair value 19 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value 8,114 92 Propane swap agreements Derivative assets, at fair value 594 1,181 Total asset derivatives $ 10,568 $ 1,286 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 1,602 $ 5,776 Derivatives designated as cash flow hedges Natural gas futures contracts Derivative liabilities, at fair value 8,168 469 Natural gas swap contracts Derivative liabilities, at fair value — 2 Propane swap agreements Derivative liabilities, at fair value 4 — Total liability derivatives $ 9,774 $ 6,247 The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows: Amount of Gain (Loss) on Derivatives: Location of Gain For the Three Months Ended September 30, For the Nine Months Ended September 30, (in thousands) (Loss) on Derivatives 2018 2017 2018 2017 Derivatives not designated as hedging instruments Realized gain on forward contracts and options (1) Revenue $ — $ — $ — $ 112 Natural gas futures contracts Cost of sales 197 286 (2,766 ) 907 Propane swap agreements Cost of sales — 15 (13 ) 11 Natural gas swap contracts Cost of sales — 1 — 1 Derivatives designated as fair value hedges Put /Call option (2) Cost of sales — — — (9 ) Derivatives designated as cash flow hedges Propane swap agreements Cost of sales (276 ) 198 (921 ) 663 Propane swap agreements Other comprehensive income (loss) 296 1,590 (590 ) 814 Natural gas futures contracts Cost of sales (308 ) (852 ) (171 ) 929 Natural gas swap contracts Cost of sales 123 1 (358 ) 1 Natural gas swap contracts Other comprehensive income (loss) (25 ) (413 ) 563 (413 ) Natural gas futures contracts Other comprehensive income (loss) 630 (1,296 ) (241 ) (1,420 ) Total $ 637 $ (470 ) $ (4,497 ) $ 1,596 (1) All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. (2) As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets. As of September 30, 2018 , the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges: (in thousands) Carrying Amount of Hedged Item Cumulative Adjustment Included in Carrying Amount of Hedged Item Balance Sheet Location of Hedged Items At September 30, 2018 At December 31, 2017 At September 30, 2018 At December 31, 2017 Inventory $ 290 $ — $ — $ —

Fair Value of Financial Instrum

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments	Fair Value of Financial Instruments GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following: Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities; 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; and 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). Financial Assets and Liabilities Measured at Fair Value The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of September 30, 2018 and December 31, 2017 : Fair Value Measurements Using: As of September 30, 2018 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 679 — — 679 Investments—mutual funds and other 7,250 7,250 — — Total investments 7,951 7,272 — 679 Derivative assets 10,568 — 10,568 — Total assets $ 18,519 $ 7,272 $ 10,568 $ 679 Liabilities: Derivative liabilities $ 9,774 $ — $ 9,774 $ — Fair Value Measurements Using: As of December 31, 2017 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 648 — — 648 Investments—mutual funds and other 6,086 6,086 — — Total investments 6,756 6,108 — 648 Derivative assets 1,286 — 1,286 — Total assets $ 8,042 $ 6,108 $ 1,286 $ 648 Liabilities: Derivative liabilities $ 6,247 $ — $ 6,247 $ — The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above: Level 1 Fair Value Measurements: 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 Fair Value Measurements: Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets. Level 3 Fair Value Measurements: Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value. The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 2018 and 2017 : Nine Months Ended 2018 2017 (in thousands) Beginning Balance $ 648 $ 561 Purchases and adjustments 64 76 Transfers (29 ) — Distribution (12 ) (2 ) Investment income 8 7 Ending Balance $ 679 $ 642 Investment income from the Level 3 investments is reflected in other expense, (net) in the accompanying condensed consolidated statements of income. At September 30, 2018 , there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required. Other Financial Assets and Liabilities Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement). At September 30, 2018 , long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $250.7 million . This compares to a fair value of approximately $248.9 million , 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. At December 31, 2017 , long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $205.2 million , compared to the estimated fair value of approximately $215.4 million . The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

Long-Term Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2018 2017 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,985 $ 7,982 Uncollateralized senior notes: 5.50% note, due October 12, 2020 6,000 6,000 5.93% note, due October 31, 2023 16,500 18,000 5.68% note, due June 30, 2026 23,200 26,100 6.43% note, due May 2, 2028 7,000 7,000 3.73% note, due December 16, 2028 20,000 20,000 3.88% note, due May 15, 2029 50,000 50,000 3.25% note, due April 30, 2032 70,000 70,000 3.48% note, due May 31, 2038 50,000 — Promissory notes 26 97 Capital lease obligation 987 2,070 Less: debt issuance costs (488 ) (433 ) Total long-term debt 251,210 206,816 Less: current maturities (9,613 ) (9,421 ) Total long-term debt, net of current maturities $ 241,597 $ 197,395 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities. In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt due to the stated maturity date of October 8, 2020. In May 2018, we utilized a portion of the proceeds from the issuance of $50.0 million of 3.48% Series A notes to repay the $25.0 million of long-term debt borrowed under the Revolver. For additional information regarding the issuance of the Series A notes, see "Shelf Agreements" below. Shelf Agreements In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018 , we had issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under the Revolver, lines of credit and/or to fund capital expenditures. In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase. In November 2017, NYL agreed to purchase $50.0 million of 3.48% Series A notes and $50.0 million of 3.58% Series B notes. The Series A notes were issued in May 2018 and the Series B notes will be issued on or before November 20, 2018. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. The NYL Shelf Agreement has been fully utilized. As of September 30, 2018 , we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments) under the Prudential Shelf Agreement ( $50.0 million ) and MetLife Shelf Agreement ( $150.0 million ). The Prudential Shelf Agreement and the NYL Shelf Agreement 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.

Summary of Accounting Policies

Summary of Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure. The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2017 . In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented. Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.
Business Acquisition [Line Items]
Schedule of Business Acquisitions, by Acquisition [Table Text Block]	ARM, Chipola and Central Gas Asset Acquisitions In August 2017, PESCO acquired certain natural gas marketing assets of ARM. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity. We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million , based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million . We similarly revised the condensed consolidated balance sheet as of December 31, 2017 . These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid. In August 2017, Flo-gas acquired certain operating assets of Chipola, which provided propane distribution service to approximately 800 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida. In December 2017, Flo-gas acquired certain operating assets of Central Gas, which provides propane distribution service to approximately 325 residential and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida. The revenue and net income from these acquisitions, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018 , were not material. The acquisition accounting amounts recorded in conjunction with the ARM and Chipola acquisitions are now final although the amounts associated with the Central Gas acquisition are preliminary and subject to adjustment based on additional valuations performed during the measurement period.
FASB Statements and Other Authoritative Pronouncements	FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. The impact of adoption of the new revenue standard was immaterial to our net income. This standard requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration that the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 3, Revenue Recognition, for additional information. The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statements for the three and nine months ended September 30, 2018 and condensed consolidated balance sheet as of September 30, 2018 : Three Months Ended Nine Months Ended Income statement As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Regulated Energy operating revenues $ 72,770 $ 72,879 $ (109 ) $ 252,667 $ 253,659 $ (992 ) Regulated Energy cost of sales 21,501 21,512 (11 ) 89,741 90,454 (713 ) Depreciation and amortization 10,633 10,629 4 30,176 30,150 26 Income before income taxes 7,595 7,697 (102 ) 53,510 53,815 (305 ) Income taxes 2,057 2,086 (29 ) 14,731 14,819 (88 ) Net income 5,538 5,611 (73 ) 38,779 38,996 (217 ) As of September 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,352 $ 13,658 $ (1,306 ) Other assets $ 5,293 $ 5,702 $ (409 ) Capitalization Retained earnings $ 249,805 $ 251,520 $ (1,715 ) The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018 , associated with a long-term firm transmission contract with an industrial customer. Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included operating expenses. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations. Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments , which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows. Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations. Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income , which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information. Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities , to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12. Recent Accounting Standards Yet to be Adopted Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROU model that requires a lessee to recognize a ROU asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842 ; ASU No. 2018-10, Codification Improvements to Topic 842, Lease s; and ASU No. 2018-11, Targeted Improvements . ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019 and use the modified retrospective transition approach to all existing leases. The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the lease components to which they relate. The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 million to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases. Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment , which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations. Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting , which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations. Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement , which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations. Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans , which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Summary of Accounting Policie_2

Summary of Accounting Policies Impact of Adoption of ASC 606 (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]	The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statements for the three and nine months ended September 30, 2018 and condensed consolidated balance sheet as of September 30, 2018 : Three Months Ended Nine Months Ended Income statement As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Regulated Energy operating revenues $ 72,770 $ 72,879 $ (109 ) $ 252,667 $ 253,659 $ (992 ) Regulated Energy cost of sales 21,501 21,512 (11 ) 89,741 90,454 (713 ) Depreciation and amortization 10,633 10,629 4 30,176 30,150 26 Income before income taxes 7,595 7,697 (102 ) 53,510 53,815 (305 ) Income taxes 2,057 2,086 (29 ) 14,731 14,819 (88 ) Net income 5,538 5,611 (73 ) 38,779 38,996 (217 ) As of September 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,352 $ 13,658 $ (1,306 ) Other assets $ 5,293 $ 5,702 $ (409 ) Capitalization Retained earnings $ 249,805 $ 251,520 $ (1,715 )

Calculation of Earnings Per S_2

Calculation of Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Calculation of Basic and Diluted Earnings Per Share	Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 Weighted average shares outstanding 16,378,545 16,344,442 16,366,608 16,334,210 Basic Earnings Per Share $ 0.34 $ 0.42 $ 2.37 $ 1.96 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,378,545 16,344,442 16,366,608 16,334,210 Effect of dilutive securities—Share-based compensation 49,894 45,193 49,647 44,423 Adjusted denominator—Diluted 16,428,439 16,389,635 16,416,255 16,378,633 Diluted Earnings Per Share $ 0.34 $ 0.42 $ 2.36 $ 1.96

Revenue Recognition (Tables)

Revenue Recognition (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Disaggregation of Revenue [Table Text Block]	The following table displays our revenue by major source based on product and service type for the three months ended September 30, 2018 : (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 6,282 $ — $ — $ 6,282 Delaware natural gas division 7,010 — — 7,010 FPU electric distribution 23,830 — — 23,830 FPU natural gas distribution 17,390 — — 17,390 Maryland natural gas division 2,463 — — 2,463 Sandpiper 3,561 — — 3,561 Total energy distribution 60,536 — — 60,536 Energy transmission Aspire Energy — 5,750 — 5,750 Eastern Shore 16,189 — — 16,189 Peninsula Pipeline 3,404 — — 3,404 Total energy transmission 19,593 5,750 — 25,343 Energy generation Eight Flags — 4,044 — 4,044 Propane delivery Delmarva Peninsula propane delivery — 13,172 — 13,172 Florida propane delivery — 4,166 — 4,166 Total propane delivery — 17,338 — 17,338 Energy services PESCO — 51,619 — 51,619 Other and eliminations Eliminations (7,359 ) (3,185 ) (8,668 ) (19,212 ) Other — 476 135 611 Total other and eliminations (7,359 ) (2,709 ) (8,533 ) (18,601 ) Total operating revenues (1) $ 72,770 $ 76,042 $ (8,533 ) $ 140,279 (1) Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 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. The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018 : (in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 18,462 $ — $ — $ 18,462 Delaware natural gas division 50,963 — — 50,963 FPU electric distribution 60,933 — — 60,933 FPU natural gas distribution 58,885 — — 58,885 Maryland natural gas division 17,136 — — 17,136 Sandpiper 16,892 — — 16,892 Total energy distribution 223,271 — — 223,271 Energy transmission Aspire Energy — 23,682 — 23,682 Eastern Shore 46,289 — — 46,289 Peninsula Pipeline 8,469 — — 8,469 Total energy transmission 54,758 23,682 — 78,440 Energy generation Eight Flags — 12,652 — 12,652 Propane delivery Delmarva Peninsula propane delivery — 73,907 — 73,907 Florida propane delivery — 15,741 — 15,741 Total propane delivery — 89,648 — 89,648 Energy services PESCO — 181,976 — 181,976 Other and eliminations Eliminations (25,362 ) (11,679 ) (34,643 ) (71,684 ) Other — 1,475 521 1,996 Total other and eliminations (25,362 ) (10,204 ) (34,122 ) (69,688 ) Total operating revenues (1) $ 252,667 $ 297,754 $ (34,122 ) $ 516,299 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 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, 2017 and September 30, 2018 were as follows: Trade Receivables Contract Assets (Non-current) Contract Liabilities (Current) (in thousands) Balance at 12/31/2017 $ 74,962 $ 1,270 $ 407 Balance at 9/30/2018 50,937 2,331 583 Increase (decrease) $ (24,025 ) $ 1,061 $ 176

Environmental Commitments and_2

Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Environmental Commitments and Contingencies [Abstract]
Environmental Remedies [Table Text Block]	Jurisdiction MGP Site Status Cost to Clean up Recovery through Rates Florida West Palm Beach Remedial actions approved by the FDEP have been implemented on the east parcel of the site. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018. Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. Yes Florida Sanford In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site. FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000. Yes Florida Winter Haven Remediation is ongoing. Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site. Yes Delaware Seaford Proposed plan for implementation approved by the DNREC in July 2017. Site assessment is ongoing. Between $273,000 and $465,000. Yes Maryland Cambridge Currently in discussions with the MDE. Unable to estimate. N/A

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Schedule of Segment Reporting Information by Segment	The following table presents financial information about our reportable segments: Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 69,697 $ 67,257 $ 243,382 $ 232,519 Unregulated Energy segment and other businesses 70,582 59,679 272,917 204,661 Total operating revenues, unaffiliated customers $ 140,279 $ 126,936 $ 516,299 $ 437,180 Intersegment Revenues (1) Regulated Energy segment $ 3,073 $ 2,446 $ 9,285 $ 5,834 Unregulated Energy segment 5,460 5,009 24,837 15,801 Other businesses 135 194 521 581 Total intersegment revenues $ 8,668 $ 7,649 $ 34,643 $ 22,216 Operating Income Regulated Energy segment $ 15,915 $ 15,523 $ 56,930 $ 53,004 Unregulated Energy segment (3,933 ) (951 ) 10,241 10,626 Other businesses and eliminations 54 60 (1,481 ) 162 Total operating income 12,036 14,632 65,690 63,792 Other expense, net (11 ) (154 ) (204 ) (1,855 ) Interest charges 4,430 3,321 11,976 9,133 Income before Income Taxes 7,595 11,157 53,510 52,804 Income taxes 2,057 4,324 14,731 20,781 Net Income $ 5,538 $ 6,833 $ 38,779 $ 32,023 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) September 30, 2018 December 31, 2017 Identifiable Assets Regulated Energy segment $ 1,223,537 $ 1,121,673 Unregulated Energy segment 244,390 259,041 Other businesses and eliminations 37,629 34,220 Total identifiable assets $ 1,505,556 $ 1,414,934

Stockholder's Equity - Accumul

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Changes in Accumulated Other Comprehensive Loss	Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2017 $ (4,743 ) $ 471 $ (4,272 ) Other comprehensive loss before reclassifications — (1,126 ) (1,126 ) Amounts reclassified from accumulated other comprehensive income 275 1,043 1,318 Net current-period other comprehensive income/(loss) 275 (83 ) 192 Stranded tax reclassification to retained earnings (1,022 ) 115 (907 ) As of September 30, 2018 $ (5,490 ) $ 503 $ (4,987 ) Defined Benefit Commodity Pension and Contracts Postretirement Cash Flow Plan Items Hedges Total (in thousands) As of December 31, 2016 $ (5,360 ) $ 482 $ (4,878 ) Other comprehensive (loss)/income before reclassifications (9 ) 322 313 Amounts reclassified from accumulated other comprehensive income/(loss) 271 (965 ) (694 ) Net prior-period other comprehensive income/(loss) 262 (643 ) (381 ) As of September 30, 2017 $ (5,098 ) $ (161 ) $ (5,259 )
Reclassifications out of Accumulated Other Comprehensive Income (Loss)	The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2018 and 2017 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 19 $ 58 $ 58 Net loss (1) (138 ) (171 ) (435 ) (509 ) Total before income taxes (119 ) (152 ) (377 ) (451 ) Income tax benefit 33 61 102 180 Net of tax $ (86 ) $ (91 ) $ (275 ) $ (271 ) Gains and losses on commodity contracts cash flow hedges: Propane swap agreements (2) $ (276 ) $ 198 $ (921 ) $ 663 Natural gas swaps (2) 123 1 (358 ) 1 Natural gas futures (2) (308 ) (852 ) (171 ) 929 Total before income taxes (461 ) (653 ) (1,450 ) 1,593 Income tax benefit (expense) 129 248 407 (628 ) Net of tax (332 ) (405 ) (1,043 ) 965 Total reclassifications for the period $ (418 ) $ (496 ) $ (1,318 ) $ 694

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Schedule of Net Benefit Costs [Table Text Block]	Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2018 and 2017 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 94 $ 103 $ 570 $ 623 $ 21 $ 22 $ 10 $ 11 $ 12 $ 13 Expected return on plan assets (131 ) (127 ) (770 ) (699 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (19 ) — — Amortization of net loss 82 107 86 131 25 22 15 17 — — Net periodic cost (benefit) (1) 45 83 (114 ) 55 46 44 6 9 12 13 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 45 $ 83 $ 77 $ 246 $ 46 $ 44 $ 6 $ 9 $ 14 $ 15 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Nine Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 288 $ 309 $ 1,754 $ 1,870 $ 63 $ 66 $ 29 $ 31 $ 38 $ 38 Expected return on plan assets (406 ) (381 ) (2,318 ) (2,098 ) — — — — — — Amortization of prior service credit — — — — — — (58 ) (58 ) — — Amortization of net loss 258 319 302 392 75 65 45 50 — — Net periodic cost (benefit) (1) 140 247 (262 ) 164 138 131 16 23 38 38 Amortization of pre-merger regulatory asset — — 571 571 — — — — 6 6 Total periodic cost $ 140 $ 247 $ 309 $ 735 $ 138 $ 131 $ 16 $ 23 $ 44 $ 44
Amounts Included in Regulatory asset and AOCI [Table Text Block]	The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended September 30, 2018 and 2017 : For the Three Months Ended September 30, 2018 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 82 86 25 15 — 208 Total recognized in net periodic benefit cost 82 86 25 (4 ) — 189 Recognized from accumulated other comprehensive loss (1) 82 16 25 (4 ) — 119 Recognized from regulatory asset — 70 — — — 70 Total $ 82 $ 86 $ 25 $ (4 ) $ — $ 189 For the Three Months Ended September 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 107 131 22 17 — 277 Total recognized in net periodic benefit cost 107 131 22 (2 ) — 258 Recognized from accumulated other comprehensive loss (1) 107 25 22 (2 ) — 152 Recognized from regulatory asset — 106 — — — 106 Total $ 107 $ 131 $ 22 $ (2 ) $ — $ 258 For the Nine Months Ended September 30, 2018 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 258 302 75 45 — 680 Total recognized in net periodic benefit cost 258 302 75 (13 ) — 622 Recognized from accumulated other comprehensive loss (1) 258 57 75 (13 ) — 377 Recognized from regulatory asset — 245 — — — 245 Total $ 258 $ 302 $ 75 $ (13 ) $ — $ 622 For the Nine Months Ended September 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (58 ) $ — $ (58 ) Net loss 319 392 65 50 — 826 Total recognized in net periodic benefit cost 319 392 65 (8 ) — 768 Recognized from accumulated other comprehensive loss (1) 319 75 65 (8 ) — 451 Recognized from regulatory asset — 317 — — — 317 Total $ 319 $ 392 $ 65 $ (8 ) $ — $ 768

Investments (Tables)

Investments (Tables)	9 Months Ended
	Sep. 30, 2018
Investments, Debt and Equity Securities [Abstract]
Investments schedule [Table Text Block]	The investment balances at September 30, 2018 and December 31, 2017 , consisted of the following: (in thousands) September 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 7,929 $ 6,734 Investments in equity securities 22 22 Total $ 7,951 6,756

Share-Based Compensation (Table

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2018
Shares awarded to non-employee directors [Line Items]
Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan	The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months ended September 30, 2018 and 2017 : Three Months Ended Nine Months Ended September 30, September 30, 2018 2017 2018 2017 (in thousands) Awards to non-employee directors $ 135 $ 134 $ 404 $ 406 Awards to key employees 153 662 2,728 1,202 Total compensation expense 288 796 3,132 1,608 Less: tax benefit (79 ) (320 ) (858 ) (647 ) Share-based compensation amounts included in net income $ 209 $ 476 $ 2,274 $ 961
Awards to non-employee directors [Member]
Shares awarded to non-employee directors [Line Items]
Schedule of Share-based Compensation, Activity	The table below presents the summary of the stock activity for awards to non-employee directors for the nine months ended September 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 — $ — Granted 7,128 $ 75.70 Vested (7,128 ) $ 75.70 Outstanding—September 30, 2018 — $ —
Award to key employees [Member]
Shares awarded to non-employee directors [Line Items]
Schedule of Share-based Compensation, Activity	The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 132,642 $ 59.31 Granted 49,494 $ 67.76 Vested (29,786 ) $ 47.39 Vested - Accelerated pursuant to separation agreement (1) (16,676 ) $ 75.78 Expired (3,933 ) $ 49.66 Outstanding—September 30, 2018 131,741 $ 67.43

Derivative Instruments (Tables)

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Offsetting Assets and Liabilities [Table Text Block]	The following table summarizes the accounts receivable and payable on a gross and net basis at September 30, 2018 and December 31, 2017 : At September 30, 2018 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 7,042 $ 1,158 $ 5,884 Accounts payable $ 11,264 $ 1,158 $ 10,106 At December 31, 2017 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 8,283 $ 2,391 $ 5,892 Accounts payable $ 16,643 $ 2,391 $ 14,252
Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]	The balances are as follows: (in thousands) Balance Sheet Location At September 30, 2018 At December 31, 2017 Sharp Other Current Liabilities $ 18 $ — PESCO Other Current Assets $ 2,060 $ 6,300
Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet	The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 2018 and December 31, 2017 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Propane swap agreements Derivative assets, at fair value $ — $ 13 Natural gas futures contracts Derivative assets, at fair value 1,841 — Derivatives designated as fair value hedges Propane put options Derivative assets, at fair value 19 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value 8,114 92 Propane swap agreements Derivative assets, at fair value 594 1,181 Total asset derivatives $ 10,568 $ 1,286 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location September 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 1,602 $ 5,776 Derivatives designated as cash flow hedges Natural gas futures contracts Derivative liabilities, at fair value 8,168 469 Natural gas swap contracts Derivative liabilities, at fair value — 2 Propane swap agreements Derivative liabilities, at fair value 4 — Total liability derivatives $ 9,774 $ 6,247
Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements	The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows: Amount of Gain (Loss) on Derivatives: Location of Gain For the Three Months Ended September 30, For the Nine Months Ended September 30, (in thousands) (Loss) on Derivatives 2018 2017 2018 2017 Derivatives not designated as hedging instruments Realized gain on forward contracts and options (1) Revenue $ — $ — $ — $ 112 Natural gas futures contracts Cost of sales 197 286 (2,766 ) 907 Propane swap agreements Cost of sales — 15 (13 ) 11 Natural gas swap contracts Cost of sales — 1 — 1 Derivatives designated as fair value hedges Put /Call option (2) Cost of sales — — — (9 ) Derivatives designated as cash flow hedges Propane swap agreements Cost of sales (276 ) 198 (921 ) 663 Propane swap agreements Other comprehensive income (loss) 296 1,590 (590 ) 814 Natural gas futures contracts Cost of sales (308 ) (852 ) (171 ) 929 Natural gas swap contracts Cost of sales 123 1 (358 ) 1 Natural gas swap contracts Other comprehensive income (loss) (25 ) (413 ) 563 (413 ) Natural gas futures contracts Other comprehensive income (loss) 630 (1,296 ) (241 ) (1,420 ) Total $ 637 $ (470 ) $ (4,497 ) $ 1,596 (1) All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. (2) As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets.
Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]	As of September 30, 2018 , the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges: (in thousands) Carrying Amount of Hedged Item Cumulative Adjustment Included in Carrying Amount of Hedged Item Balance Sheet Location of Hedged Items At September 30, 2018 At December 31, 2017 At September 30, 2018 At December 31, 2017 Inventory $ 290 $ — $ — $ —

Derivative Instruments Volume o

Derivative Instruments Volume of Derivative Activity (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Instruments [Table Text Block]	Business unit Commodity Quantity hedged (in millions) Designation Longest Expiration date of hedge PESCO Natural gas (Dts) 22.1 Cash flows hedges March 2022 PESCO Natural gas (Dts) 1.1 Not designated January 2020 Sharp Propane (gallons) 4.4 Cash flows hedges June 2021 Sharp Propane (gallons) 0.3 Fair value hedges March 2019

Fair Value of Financial Instr_2

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Financial Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of September 30, 2018 and December 31, 2017 : Fair Value Measurements Using: As of September 30, 2018 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 679 — — 679 Investments—mutual funds and other 7,250 7,250 — — Total investments 7,951 7,272 — 679 Derivative assets 10,568 — 10,568 — Total assets $ 18,519 $ 7,272 $ 10,568 $ 679 Liabilities: Derivative liabilities $ 9,774 $ — $ 9,774 $ — Fair Value Measurements Using: As of December 31, 2017 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other Observable Inputs (Level 2) Significant Unobservable Inputs (Level 3) (in thousands) Assets: Investments—equity securities $ 22 $ 22 $ — $ — Investments—guaranteed income fund 648 — — 648 Investments—mutual funds and other 6,086 6,086 — — Total investments 6,756 6,108 — 648 Derivative assets 1,286 — 1,286 — Total assets $ 8,042 $ 6,108 $ 1,286 $ 648 Liabilities: Derivative liabilities $ 6,247 $ — $ 6,247 $ —
Summary of Changes in Fair Value of Investments	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 2018 and 2017 : Nine Months Ended 2018 2017 (in thousands) Beginning Balance $ 648 $ 561 Purchases and adjustments 64 76 Transfers (29 ) — Distribution (12 ) (2 ) Investment income 8 7 Ending Balance $ 679 $ 642

Long-Term Debt (Tables)

Long-Term Debt (Tables)	9 Months Ended
	Sep. 30, 2018
Debt Disclosure [Abstract]
Outstanding Long-Term Debt	Our outstanding long-term debt is shown below: September 30, December 31, (in thousands) 2018 2017 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,985 $ 7,982 Uncollateralized senior notes: 5.50% note, due October 12, 2020 6,000 6,000 5.93% note, due October 31, 2023 16,500 18,000 5.68% note, due June 30, 2026 23,200 26,100 6.43% note, due May 2, 2028 7,000 7,000 3.73% note, due December 16, 2028 20,000 20,000 3.88% note, due May 15, 2029 50,000 50,000 3.25% note, due April 30, 2032 70,000 70,000 3.48% note, due May 31, 2038 50,000 — Promissory notes 26 97 Capital lease obligation 987 2,070 Less: debt issuance costs (488 ) (433 ) Total long-term debt 251,210 206,816 Less: current maturities (9,613 ) (9,421 ) Total long-term debt, net of current maturities $ 241,597 $ 197,395 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Summary of Accounting policie_3

Summary of Accounting policies - Additional Information (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018USD ($)
Summary of Accounting Policies [Abstract]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 1,700
Delay of Revenue Recognition Due To Implementation of New Standard	$ 305

Summary of Accounting Policie_4

Summary of Accounting Policies Acquisitions Additional information (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Sep. 30, 2018USD ($)
Business Acquisition [Line Items]
Number of customers acquired through acquisition	800
ARM Energy [Member]
Business Acquisition [Line Items]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized		$ 2,500,000
Central Gas [Member]
Business Acquisition [Line Items]
Number of customers acquired through acquisition	325
Unregulated Energy [Member] | ARM [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period	$ 6,800,000

Summary of Accounting Policie_5

Summary of Accounting Policies Summary of Effect of Adoption on Consolidated Financial Statements (Details) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Item Effected [Line Items]
Accrued revenue	$ 12,352		$ 12,352		$ 22,279
Regulated Energy Operating Revenue	72,770	$ 69,703	252,667	$ 238,353
Regulated Energy cost of sales	21,501	22,794	89,741	87,206
Depreciation and amortization	10,633	9,362	30,176	27,267
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	7,595	11,157	53,510	52,804
Income taxes	2,057	4,324	14,731	20,781
Net Income	5,538	$ 6,833	38,779	$ 32,023	58,124
Other assets	5,293		5,293		3,699
Retained earnings	249,805		249,805		$ 229,141
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	13,658		13,658
Regulated Energy Operating Revenue	72,879		253,659
Regulated Energy cost of sales	21,512		90,454
Depreciation and amortization	10,629		30,150
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	7,697		53,815
Income taxes	2,086		14,819
Net Income	5,611		38,996
Other assets	5,702		5,702
Retained earnings	251,520		251,520
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	(1,306)		(1,306)
Deferred Revenue, Period Increase (Decrease)	(109)		(992)
Regulated Energy cost of sales	(11)		(713)
Depreciation and amortization	4		26
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(102)		(305)
Income taxes	(29)		(88)
Net Income	(73)		(217)
Other assets	(409)		(409)
Retained earnings	$ (1,715)		$ (1,715)

Calculation of Earnings Per S_3

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Calculation of Basic Earnings Per Share:
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023	$ 58,124
Weighted shares outstanding (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Basic Earnings Per Share (in dollars per share)	$ 0.34	$ 0.42	$ 2.37	$ 1.96
Reconciliation of Numerator:
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023	$ 58,124
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Effect of dilutive securities:
Share-based compensation (shares)	49,894	45,193	49,647	44,423
Adjusted denominator-Diluted (shares)	16,428,439	16,389,635	16,416,255	16,378,633
Diluted Earnings Per Share (in dollars per share)	$ 0.34	$ 0.42	$ 2.36	$ 1.96

Revenue Recognition Additional

Revenue Recognition Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Revenues	$ 140,279,000	$ 126,936,000	$ 516,299,000	$ 437,180,000
Contract with Customer, Liability, Current	583,000		583,000		$ 407,000
Contract with Customer, Liability, Revenue Recognized	48,000		384,000
Regulated Energy [Member] | Other [Member]
Revenues	546,000		(399,000)
Unregulated Energy [Member] | Other [Member]
Revenues	$ 91,000		$ 246,000

Revenue Recognition Disegragati

Revenue Recognition Disegragation of Revenue (Details) - USD ($) $ in Thousands		3 Months Ended	9 Months Ended
		Sep. 30, 2018	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	$ 140,279	$ 516,299
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(18,601)	(69,688)
Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	72,770	252,667
Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	76,042	297,754
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(8,533)	(34,122)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	(8,533)	(34,122)
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2,709)	(10,204)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(7,359)	(25,362)
Energy Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		60,536	223,271
Energy Distribution [Member] | Florida Natural Gas Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6,282	18,462
Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,390	58,885
Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,463	17,136
Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		7,010	50,963
Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		23,830	60,933
Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,561	16,892
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		25,343	78,440
Energy Transmission [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		19,593	54,758
Energy Transmission [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,750	23,682
Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,750	23,682
Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		16,189	46,289
Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,404	8,469
Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,044	12,652
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,338	89,648
Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,338	89,648
Propane Delivery [Member] | Delmarva Peninsula Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		13,172	73,907
Propane Delivery [Member] | Florida Propane [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,166	15,741
Energy Services [Member] | PESCO [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		51,619	181,976
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(19,212)	(71,684)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(7,359)	(25,362)
Eliminations [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(3,185)	(11,679)
Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(8,668)	(34,643)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		611	1,996
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		476	1,475
Other [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 135	$ 521
[1]	(1) Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 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.

Revenue Recognition Contract Ba

Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 50,937	$ 74,962
Contract with Customer, Asset, Net, Noncurrent	2,331	1,270
Contract with Customer, Liability, Current	583	$ 407
Increase (Decrease) in Receivables	(24,025)
Increase (Decrease) in Other Noncurrent Assets	1,061
Increase (Decrease) in Other Current Liabilities	$ 176

Rates and Other Regulatory Ac_2

Rates and Other Regulatory Activities - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2018USD ($)dekatherm / dunitmi	Dec. 31, 2017USD ($)
Electric Distribution [Member]
Rates and Other Regulatory Activities [Line Items]
Amount of Regulatory Costs Not yet Approved	$ 15,200,000
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Asset Recovery Damaged Property Costs, Noncurrent	1,500,000
Deferred Storm and Property Reserve Deficiency, Noncurrent	779,000
Public Utilities, Requested Rate Increase (Decrease), Amount	1.82
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Cost of Services	60,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 18,900,000
Public Utilities, Requested Return on Equity, Percentage	13.75%
Number of Months Rates Suspended	5 months
Increase in Revenue Recognized Due to Motion Rate in Effect		$ 3,700,000
2017 Expansion Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Estimated Capital Cost	$ 117,000,000
Number of pipeline miles requested | mi	23
Revised Miles Of Natural Gas Pipeline | mi	17
Pressure Control Stations	2
Firm natural gas transportation deliverability | dekatherm / d	61,162
Additional Firm Natural Gas Transportation Deliverability | dekatherm / d	52,500
Del-Mar Pathway Project [Domain] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Firm natural gas transportation deliverability | dekatherm / d	14,300
Del-Mar Pathway Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of pipeline miles requested | mi	13
Subscribers [Member] | 2017 Expansion Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of customers	7
Number of affiliates | unit	3
Pre TCJA approved revenue requirements [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 9,800,000
Post TCJA approved revenue requirements [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 6,600,000

Environmental Commitments and_3

Environmental Commitments and Contingencies - Additional Information (Detail)	9 Months Ended
	Sep. 30, 2018USD ($)site	Dec. 31, 2017USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 7,941,000	$ 8,263,000
West Palm Beach Florida [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
West Palm Beach Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	15,400,000
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	10,000
Winter Haven Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	425,000
Seaford [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	273,000
Seaford [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	465,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	9,400,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	11,400,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 2,600,000

Other Commitments and Conting_2

Other Commitments and Contingencies - Additional Information (Detail) gal in Millions, $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)gal
Commitments and Contingencies Disclosure [Abstract]
Number of Years for Asset Management Agreement	3 years
Number of years to purchase propane under contract	6 years
Estimated current annual commitment | gal	1.8
Debt Service Coverage Ratio	1.25
Ratio based on average number of prior quarters	6
Number of Propane Price Indices	2
Ratios based on average of the prior quarters	1 year 6 months
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	0.65
Number Of Years For Power Purchase Agreement	20 years
Contract Duration	20 years
Aggregate guaranteed amount	$ 73.9
Draws on letters of credit	$ 5

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) $ in Thousands		3 Months Ended		9 Months Ended		12 Months Ended
		Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments		2
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 140,279	$ 126,936	$ 516,299	$ 437,180
Intersegment Revenues
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Operating Income
Total operating income		12,036	14,632	65,690	63,792
Other expense, net		(11)	(154)	(204)	(1,855)
Interest		4,430	3,321	11,976	9,133
Income Before Income Taxes		7,595	11,157	53,510	52,804
Income taxes		2,057	4,324	14,731	20,781
Net Income		5,538	6,833	38,779	32,023	$ 58,124
Identifiable Assets
Total identifiable assets		1,505,556		1,505,556		1,414,934
Regulated Energy [Member]
Operating Income
Total operating income		15,915	15,523	56,930	53,004
Identifiable Assets
Total identifiable assets		1,223,537		1,223,537		1,121,673
Unregulated Energy [Member]
Operating Income
Total operating income		(3,933)	(951)	10,241	10,626
Identifiable Assets
Total identifiable assets		244,390		244,390		259,041
Other [Member]
Identifiable Assets
Total identifiable assets		37,629		37,629		$ 34,220
Other and eliminations [Member]
Operating Income
Total operating income		54	60	(1,481)	162
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Intersegment Revenues
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		69,697	67,257	243,382	232,519
Intersegment Revenues
Total operating revenues, unaffiliated customers		69,697	67,257	243,382	232,519
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		70,582	59,679	272,917	204,661
Intersegment Revenues
Total operating revenues, unaffiliated customers		70,582	59,679	272,917	204,661
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	8,668	7,649	34,643	22,216
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	8,668	7,649	34,643	22,216
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	3,073	2,446	9,285	5,834
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	3,073	2,446	9,285	5,834
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	5,460	5,009	24,837	15,801
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	5,460	5,009	24,837	15,801
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	135	194	521	581
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 135	$ 194	$ 521	$ 581
[1]	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

Stockholder's Equity - Accumu_2

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (4,272)	$ (4,878)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(1,126)	313
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,318	(694)
Net current-period other comprehensive income (loss)	192	(381)
Ending balance	(4,987)	(5,259)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(907)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(4,743)	(5,360)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	(9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	275	271
Net current-period other comprehensive income (loss)	275	262
Ending balance	(5,490)	(5,098)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(1,022)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	471	482
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(1,126)	322
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,043	(965)
Net current-period other comprehensive income (loss)	(83)	(643)
Ending balance	503	$ (161)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 115

Stockholder's Equity - Accum_2

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Amortization of pension and postretirement items:
Tax benefit		$ (2,057)	$ (4,324)	$ (14,731)	$ (20,781)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(418)	(496)	(1,318)	694
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	[1]	19	19	58	58
Net loss	[1]	(138)	(171)	(435)	(509)
Total before tax		(119)	(152)	(377)	(451)
Tax benefit		33	61	102	180
Net of tax		(86)	(91)	(275)	(271)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Total before tax		(461)	(653)	(1,450)	1,593
Tax benefit		129	248	407	(628)
Net of tax		(332)	(405)	(1,043)	965
Propane Swap Agreement [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	[2]	(276)	198	(921)	663
Natural Gas Swaps [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[2]	123	1	(358)	1
Natural Gas Futures [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[2]	$ (308)	$ (852)	$ (171)	$ 929
[1]	These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
[2]	These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Stockholder's Equity Stockholde

Stockholder's Equity Stockholder's Equity Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Equity [Abstract]
Preferred Stock, Shares Authorized	2,000,000		2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01		$ 0.01
Proceeds from Issuance of Common Stock	$ 0	$ (10)	$ (10)

Employee Benefit Plans (Detail)

Employee Benefit Plans (Detail) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)	$ (19)	$ (58)	$ (58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		208	277	680	826
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		10	11	29	31
Amortization of prior service cost		(19)	(19)	(58)	(58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	45	50
Net periodic cost (benefit)	[1]	6	9	16	23
Total periodic cost		6	9	16	23
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		12	13	38	38
Net periodic cost (benefit)	[1]	12	13	38	38
Amortization of pre-merger regulatory asset		2	2	6	6
Total periodic cost		14	15	44	44
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		570	623	1,754	1,870
Expected return on plan assets		(770)	(699)	(2,318)	(2,098)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		86	131	302	392
Net periodic cost (benefit)	[1]	(114)	55	(262)	164
Amortization of pre-merger regulatory asset		191	191	571	571
Total periodic cost		77	246	309	735
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		21	22	63	66
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	75	65
Net periodic cost (benefit)	[1]	46	44	138	131
Total periodic cost		46	44	138	131
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		94	103	288	309
Expected return on plan assets		(131)	(127)	(406)	(381)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		82	107	258	319
Net periodic cost (benefit)	[1]	45	83	140	247
Total periodic cost		$ 45	$ 83	$ 140	$ 247
[1]	See Note 8, Stockholder's Equity.

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs		$ 856
Expected amortization of pre merger regulatory asset		769
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	$ 749	749	$ 1,300
Contribution to pension plan	123	971
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	1,500	1,500
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	235	433
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	359	359
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	38	113
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	151	151
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan		15
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	97	97
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	9	33
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	$ 88	$ 88

Employee Benefit Plans - Amount

Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (19)	$ (19)	$ (58)	$ (58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		208	277	680	826
Recognized from accumulated other comprehensive loss	[1]	119	152	377	451
Recognized from regulatory asset		70	106	245	317
Total recognized in net periodic benefit cost		189	258	622	768
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		82	107	258	319
Recognized from accumulated other comprehensive loss	[1]	82	107	258	319
Total recognized in net periodic benefit cost		82	107	258	319
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		86	131	302	392
Recognized from accumulated other comprehensive loss	[1]	16	25	57	75
Recognized from regulatory asset		70	106	245	317
Total recognized in net periodic benefit cost		86	131	302	392
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	75	65
Recognized from accumulated other comprehensive loss	[1]	25	22	75	65
Total recognized in net periodic benefit cost		25	22	75	65
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(19)	(19)	(58)	(58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	45	50
Recognized from accumulated other comprehensive loss	[1]	(4)	(2)	(13)	(8)
Total recognized in net periodic benefit cost		$ (4)	$ (2)	$ (13)	$ (8)
[1]	See Note 8, Stockholder's Equity.

Investments - Schedule of Inves

Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Investments schedule [Line Items]
Investments, at fair value	$ 7,951	$ 6,756
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	7,929	6,734
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 22	$ 22

Investments - Additional Inform

Investments - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Investments, Debt and Equity Securities [Abstract]
Unrealized gain (loss), net of other expenses	$ 313,000	$ 261,000	$ 426,000	$ 694,000

Share-Based Compensation - Shar

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 288	$ 796	$ 3,132	$ 1,608
Less: tax benefit	(79)	(320)	(858)	(647)
Share-Based Compensation amounts included in net income	209	476	$ 2,274	961
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			792
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 135	134	$ 404	406
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value					$ 0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 75.70
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			7,128
Award to key employees [Member]
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, Nonvested, Number	131,741		131,741		132,642
Total compensation expense	$ 153	$ 662	$ 2,728	$ 1,202
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 67.43		$ 67.43		$ 59.31
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			49,494
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 47.39
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			29,786
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost			$ 1,100
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 75.78

Share-Based Compensation - Summ

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	9 Months Ended
	Sep. 30, 2018$ / sharesshares
Number of Shares
Granted awards (shares)	792
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	7,128
Number of Shares
Vested (shares)	(7,128)
Weighted Average Fair Value
Outstanding - December 31, 2017 (in dollars per share) | $ / shares	$ 0
Vested (in dollars per share) | $ / shares	$ 75.70
Award to key employees [Member]
Number of Shares
Outstanding - December 31, 2017 (shares)	132,642
Granted awards (shares)	49,494
Vested (shares)	(29,786)
Expired (shares)	(3,933)
Outstanding - September 30, 2018 (shares)	131,741
Weighted Average Fair Value
Outstanding - December 31, 2017 (in dollars per share) | $ / shares	$ 59.31
Granted (in dollars per share) | $ / shares	67.76
Vested (in dollars per share) | $ / shares	47.39
Expired (in dollars per share) | $ / shares	49.66
Outstanding - September 30, 2018 (in dollars per share) | $ / shares	67.43
Accelerated Vested Shares [Member]
Weighted Average Fair Value
Vested (in dollars per share) | $ / shares	$ 75.78
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	16,676
Accelerated Vested Shares [Member] | Award to key employees [Member]
Number of Shares
Expired (shares)	2,569
Weighted Average Fair Value
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	14,107

Share-Based Compensation - Addi

Share-Based Compensation - Additional Information (Detail) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2018USD ($)unitshares	Sep. 30, 2017USD ($)	Dec. 31, 2017shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)	792
Shares Paid for Tax Withholding for Share Based Compensation	16,918		10,269
Payments Related to Tax Withholding for Share-based Compensation | $	$ 1,210	$ 692
Unrecognized compensation cost | $	$ 2,600
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortization of expense equally over a service period	1 year
Unrecognized compensation expense related to the awards to non-employee directors | $	$ 315
Award to key employees [Member]
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, Forfeited in Period	2,569
Granted awards (shares)	49,494
Vesting period	3 years
Payments Related to Tax Withholding for Share-based Compensation | $	$ 719
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	3,933
Intrinsic value of the SICP awards | $	$ 11,100
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Multi year Awards | unit	3
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	16,676
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $	$ 1,100
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Paid for Tax Withholding for Share Based Compensation	10,436
Accelerated Vested Shares [Member] | Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	14,107
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	(2,569)

Derivative Instruments - Additi

Derivative Instruments - Additional Information (Detail) $ in Thousands, Mcf in Millions	9 Months Ended
	Sep. 30, 2018USD ($)Mcf	Dec. 31, 2017USD ($)
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 290	$ 0
Other Payables to Broker-Dealers and Clearing Organizations	18	0
Other Receivables from Broker-Dealers and Clearing Organizations	2,060	6,300
Accounts Receivable Subject to Master Netting Arrangement	1,158	2,391
Energy Marketing Contracts Assets, Current	10,568	1,286
Energy Marketing Contract Liabilities, Current	(9,774)	(6,247)
Accounts Payable Subject To Master Netting Arrangement	1,158	2,391
Put Option [Member]
Derivative [Line Items]
Derivative, Cost of Hedge	28
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(8,168)	(469)
Hedging Liability [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	0	(2)
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Put Option [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	19	0
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	8,114	92
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	594	1,181
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ (4)	0
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	1.1
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 1,841
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	0	13
Not Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ (1,602)	(5,776)
PESCO [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	22.1
Gross [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 7,042	8,283
Accounts Payable Subject To Master Netting Arrangement	11,264	16,643
Net [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	5,884	5,892
Accounts Payable Subject To Master Netting Arrangement	$ 10,106	$ 14,252

Derivative Instruments - Fair V

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 10,568	$ 1,286
Mark To Market Energy Assets [Member] | Natural Gas Futures [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	1,841
Mark To Market Energy Assets [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	8,114	92
Mark To Market Energy Assets [Member] | Put Option [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	19	0
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	13
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 594	$ 1,181

Derivative Instruments - Effect

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 637,000	$ (470,000)	$ (4,497,000)		$ 1,596,000
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		0	0	[1]	112,000	[1]
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	197,000	286,000	(2,766,000)		907,000
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	1,000	0		1,000
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	15,000	(13,000)		11,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(308,000)	(852,000)	(171,000)		929,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	123,000	1,000	(358,000)		1,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(276,000)	198,000	(921,000)		663,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		0	0	[2]	(9,000)	[2]
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	(25,000)	(413,000)	563,000		(413,000)
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	296,000	1,590,000	(590,000)		814,000
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax	$ 630,000	$ (1,296,000)	$ (241,000)		$ (1,420,000)
[1]	All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income.
[2]	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets.

Derivative Instruments Volume_2

Derivative Instruments Volume of Derivative Activity (Details) $ in Thousands, gal in Millions	9 Months Ended
	Sep. 30, 2018USD ($)gal
PESCO [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ (570)
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 392
Sharp Energy Inc [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	4.4
Sharp Energy Inc [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	0.3

Fair Value of Financial Instr_3

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Assets:
Investments	$ 7,951	$ 6,756
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Equity Securities [Member]
Assets:
Investments	22	22
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	7,272	6,108
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	22	22
Quoted Prices in Active Markets (Level 1) [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments	7,250	6,086
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member]
Assets:
Investments	7,272	6,108
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	10,568	1,286
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	10,568	1,286
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	679	648
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	679	648
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member]
Assets:
Investments	679	648
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	18,519	8,042
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	22	22
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	679	648
Recurring [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments	7,250	6,086
Recurring [Member] | Total Investments [Member]
Assets:
Investments	7,951	6,756
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	$ 10,568	$ 1,286

Fair Value of Financial Instr_4

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 648	$ 561
Purchases and adjustments	64	76
Transfers	29	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	(12)	(2)
Investment Income	8	7
Ending Balance	$ 679	$ 642

Fair Value of Financial Instr_5

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 250.7	$ 205.2
Fair value of long-term debt	$ 248.9	$ 215.4

Long-Term Debt - Outstanding Lo

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt		$ 250,700		$ 205,200
Capital lease obligation		987		2,070
Total Long-term debt		251,210		206,816
Less: current maturities		(9,613)		(9,421)
Less: debt issuance costs		(488)		(433)
Total long-term debt, net of current maturities		241,597		197,395
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,985		7,982
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Total long-term debt		6,000		6,000
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt		16,500		18,000
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt		23,200		26,100
6.43% note, due May 2, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		7,000		7,000
3.73% note, due December 16, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		20,000		20,000
3.88% note, due May 15, 2029 [Member]
Debt Instrument [Line Items]
Total long-term debt		50,000		50,000
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Total long-term debt		70,000		70,000
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Total long-term debt		50,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total long-term debt			$ 25,000
Promissory note [Member]
Debt Instrument [Line Items]
Total long-term debt		$ 26		$ 97
[1]	FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Long-Term Debt - Outstanding _2

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	9 Months Ended
	Sep. 30, 2018
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt instrument, maturity date	Jun. 1, 2022
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt instrument, maturity date	Oct. 12, 2020
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt instrument, maturity date	Oct. 31, 2023
5.68% note, due June 30, 2026 [Member]
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 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt instrument, maturity date	May 2, 2028
3.73% note, due December 16, 2028 [Member]
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 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt instrument, maturity date	May 15, 2029
3.25% due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Debt instrument, maturity date	Apr. 30, 2032
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.48%
Debt instrument, maturity date	May 31, 2038
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage
Debt instrument, maturity date

Long-Term Debt - Additional Inf

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Nov. 30, 2017
Debt Instrument [Line Items]
Document Period End Date	Sep. 30, 2018
Long-term debt including current maturities	$ 250,700		$ 205,200
Debt Instrument, Unused Borrowing Capacity, Amount	$ 200,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		$ 25,000
Debt Instrument, Interest Rate, Stated Percentage
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 50,000
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 70,000		$ 70,000
Notes Payable, Other Payables [Member] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.48%
Shelf Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Prudential [Member]
Debt Instrument [Line Items]
Senior notes	$ 100,000
Debt Instrument, Unused Borrowing Capacity, Amount	50,000
Prudential [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Prudential [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
MetLife [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Maturity date term	20 years
Debt Instrument, Unused Borrowing Capacity, Amount	$ 150,000
New York Life [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 100,000
Maturity date term	20 years
Series A [Member] | New York Life [Member]
Debt Instrument [Line Items]
Senior notes				$ 50,000
Debt Instrument, Interest Rate, Stated Percentage				3.48%
Series B [Member] | New York Life [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage				3.58%